MMLP 10-K Annual Report Dec. 31, 2012

MARTIN MIDSTREAM PARTNERS L.P.

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PROXIES

DEF 14A

Filed on April 21, 2017

10-K 1 a2012123110-k.htm 10-K 2012.12.31 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



Mark One	Annual Report Pursuant to Section 13 or 15(d) of the
ý	Securities Exchange Act of 1934
	For the fiscal year ended December 31, 2012



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

For the transition period from _____ to _____.

Commission file number 000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)



Delaware		05-0527861
State or other jurisdiction of incorporation or organization		(I.R.S. Employer Identification No.)

4200 Stone Road Kilgore, Texas 75662

(Address of principal executive offices) (Zip Code)

903-983-6200

(Registrant’s telephone number, including area code)

_______________________

Securities Registered Pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Units representing limited partnership interests		NASDAQ Global Select Market

Securities Registered Pursuant to Section 12(g) of the Act:

NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements the past 90 days.

Yes ý No o

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

Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer o	Accelerated filer x	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No ý

As of June 30, 2012, 23,116,776 common units were outstanding. The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $540,979,685 based on the closing sale price on that date. There were 26,624,526 of the registrant’s common units outstanding as of March 4, 2013 .

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS



		Page
PART I		1
Item 1.	Business	1
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	41
Item 2.	Properties	41
Item 3.	Legal Proceedings	41
Item 4.	Mine Safety Disclosures	41

PART II		42
Item 5.	Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	42
Item 6.	Selected Financial Data	44
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 7A.	Quantative and Qualitative Disclosures about Market Risk	71
Item 8.	Financial Statements and Supplementary Data	72
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	116
Item 9A.	Controls and Procedures	116
Item 9B.	Other Information	117

PART III		118
Item 10.	Directors, Executive Officers and Corporate Governance	118
Item 11.	Executive Compensation	122
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	129
Item 13.	Certain Relationships and Related Transactions, and Director Independence	132
Item 14 .	Principal Accounting Fees and Services	138

PART IV		138
Item 15.	Exhibits, Financial Statement Schedules	138

PART I



Item 1.	Business

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

Forward-Looking Statements

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

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

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

Overview

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


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


•	Natural gas services;


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


•	Marine transportation services for petroleum products and by-products.

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

on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2012, Martin Resource Management owned 19.2% of our total outstanding common limited partner units. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operation through its ownership and control of our general partner.

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

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

Primary Business Segments

Our primary business segments can be generally described as follows:

•

Terminalling and Storage. We own or operate 31 marine shore based terminal facilities and 16 specialty terminal facilities located in the U.S. Gulf Coast region that provide storage, refining, blending, packaging, and handling services for producers and suppliers of petroleum products and by-products, lubricants and other liquids, including the refining, blending and packaging of various grades and quantities of naphthenic lubricants and related products. Our facilities and resources provide us with the ability to handle various products that require specialized treatment, such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuel oil. We provide these terminalling and storage services on a fee basis primarily under long-term contracts. A significant portion of the contracts in this segment provide for minimum fee arrangements that are not based on the volumes handled.

•

Natural Gas Services. We distribute natural gas liquids (“NGLs"). We purchase NGLs primarily from refineries and natural gas processors. We store NGLs in our supply and storage facilities for wholesale deliveries to propane retailers, refineries and industrial NGL users in Texas and the Southeastern U.S. We own an NGL pipeline which spans approximately 200 miles running from Kilgore, Texas to Beaumont, Texas. We own three NGL supply and storage facilities with an aggregate above-ground storage capacity of approximately 3,000 barrels and we lease approximately 2.7 million barrels of underground storage capacity for NGLs. Additionally, through our ownership interests in Redbird Gas Storage LLC (“Redbird”), we are partners in a joint venture, Cardinal Gas Storage Partners LLC (“Cardinal”), which is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi. We previously engaged in the natural gas processing business through our subsidiaries, Prism Gas Systems I, L.P. (“Prism Gas”) and Woodlawn Pipeline Co., Inc. (“Woodlawn”), and the Darco Gathering System, the Harrison Gathering System and the East Harrison Pipeline System. The East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas, which included Woodlawn, the Darco Gathering System, the Harrison Gathering System and the East Harrison Pipeline System (the “Prism Assets”), and certain other natural gas gathering and processing assets owned by us were sold on July 31, 2012 to a subsidiary of CenterPoint Energy Inc. (“CenterPoint”) for net cash proceeds of $273.3 million.

•

Sulfur Services. We have developed an integrated system of transportation assets and facilities relating to sulfur services over the last 50 years. We process and distribute sulfur predominantly produced by oil refineries primarily located in the U.S. Gulf Coast region. We handle molten sulfur on contracts that are tied to sulfur indices and tend to provide stable margins. We process molten sulfur into prilled or pelletized sulfur on take-or-pay fee contracts at our facilities in Port of Stockton, California and Beaumont, Texas. The sulfur we process and handle is primarily used in the production of fertilizers and industrial chemicals. We own and operate six sulfur-based fertilizer production plants and one emulsified sulfur blending plant that manufacture primarily sulfur-based fertilizer products for wholesale distributors and industrial users. These plants are located in Illinois, Texas and Utah.

Demand for our sulfur products exists in both the domestic and foreign markets, and we believe our asset base provides us with additional opportunities to handle increases in U.S. supply and access to foreign demand.

•

Marine Transportation. We own a fleet of 54 inland marine tank barges, 29 inland push boats and four offshore tug barge units that transport petroleum products and by-products largely in the U.S. Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts and many of our customers have long standing contractual relationships with us. Over the past several years, we have focused on modernizing our fleet. As a result, the average age of our vessels has decreased from 33 years in 2006 to 23 years as of December 31, 2012. This modernized asset base is attractive both to our existing customers as well as potential new customers. In addition, our fleet contains several vessels that reflect our focus on specialty products. For example, we are one of a very limited number of companies that can transport molten sulfur.

Recent Developments

We believe one of the rationales driving investment in master limited partnerships, including us, is the opportunity for distribution growth offered by the partnerships. Such distribution growth is a function of having access to liquidity in the financial markets used for incremental capital investment (development projects and acquisitions) to grow distributable cash flow.

We continually adjust our business strategy to focus on maximizing liquidity, maintaining a stable asset base which generates fee based revenues not sensitive to commodity prices, and improving profitability by increasing asset utilization and controlling costs. Over the past year, we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth. Over the next two years, we plan to increase growth capital expenditures primarily in our Terminalling and Storage and Natural Gas Services segments.

During the past year, we continued to experience positive market dynamics in our Terminalling and Storage segment. This is in large part to the rapid development of the Eagle Ford shale basin in South Texas and its need for off-take infrastructure. In addition, we purchased certain specialty lubricant product blending and packaging assets from Cross Oil Refining & Marketing, Inc. ("Cross"), a wholly-owned subsidiary of Martin Resource Management, as further integration into our existing assets.

We also purchased all remaining Class A interests in Redbird. Redbird was formerly a joint venture between us and Martin Resource Management formed in 2011 to invest in Cardinal, a joint venture between Martin Resource Management and Energy Capital Partners ("ECP") that is focused on the development, construction, operation and management of natural gas storage facilities in northern Louisiana and Mississippi. As a result of this transaction, Redbird is now a wholly-owned subsidiary of us. We believe natural gas storage assets are ideally suited for the master limited partnership structure.

Recent Acquisitions

Talen's Marine & Fuel, LLC. On December 31, 2012, we acquired all of the outstanding membership interests in Talen's Marine & Fuel, LLC (“Talen's”) from Quintana Energy Partners, L.P. for $103.4 million in cash, subject to certain post-closing adjustments. Simultaneous with the acquisition, we sold certain working capital-related assets to Martin Energy Services, LLC (“MES”), a wholly-owned subsidiary of Martin Resource Management for $56.0 million, reducing our investment in Talen's to $47.4 million. In conjunction with its purchase of certain working capital-related assets, MES entered into various service agreements with Talen's pursuant to which we provide certain terminalling and marine services to MES.

Acquisition of Redbird Interests. On October 2, 2012, we acquired the remaining Class A interests in Redbird for $150.0 million in cash from Martin Underground Storage, Inc., a subsidiary of Martin Resource Management. Redbird was formed by us and Martin Resource Management in 2011 to invest in Cardinal. Cardinal is a joint venture between Redbird and ECP that is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi.

Acquisition of Specialty Lubricant Product Blending and Packaging Assets. On October 2, 2012, we acquired from Cross certain specialty lubricant product blending and packaging assets ("Blending and Packaging Assets"), including working capital, for total consideration of $121.8 million in cash at closing, plus a final net working capital adjustment of $0.9 million paid in October of 2012.

Other Developments

Litigation Settlement. On October 2, 2012, we announced that the ongoing litigation and disputes since May 2008 involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all the lawsuits and disputes. In connection with the settlement, Martin Resource Management transferred 1,500,000 of our common units to KCM, LLC. Martin Resource Management continues to own 5,093,267 of our common units.

Amendment No. 2 to Omnibus Agreement. In connection with the purchase of the Blending and Packaging Assets, on October 2, 2012, we entered into Amendment No. 2 to our Omnibus Agreement (the “Amendment”) with Martin Resource Management, Martin Midstream GP LLC (the "General Partner"), and Martin Operating Partnership L.P. (the "Operating Partnership"). The Amendment allows us to provide certain products and services to Martin Resource Management under the Omnibus Agreement by amending the definition of the term “Business” to reflect the operation of the blending and packaging assets acquired by the Partnership pursuant to the purchase agreement.

Amendment No. 3 to the Second Amendment and Restated Agreement of Limited Partnership. In conjunction with the Redbird purchase agreement, on October 2, 2012, the General Partner executed Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (“the Partnership Agreement”). The Partnership Agreement Amendment provides that the General Partner, currently the holder of the incentive distribution rights, shall forego the next $18.0 million in incentive distributions that it would otherwise be entitled to receive.

Disposition of Natural Gas Gathering Assets. On June 18, 2012, we and a subsidiary of CenterPoint, entered into a definitive agreement under which CenterPoint would acquire our East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas, which include Woodlawn, the Darco Gathering System, the Harrison Gathering System, and the East Harrison Pipeline System, and other natural gas gathering and processing assets also owned by us, for cash in a transaction valued at approximately $275.0 million excluding any transaction costs and purchase price adjustments. The asset sale included our 50% operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint owned the other 50% percent interest. On July 31, 2012, we completed the sale of our East Texas and Northwest Louisiana natural gas gathering and processing assets for net cash proceeds of $273.3 million. Additionally, on September 18, 2012, we completed the sale of our interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy, LLC (“PIPE”) to a private investor group for $1.5 million in cash (the assets described above, collectively, are herein referred to as the "Prism Assets"). Prism Gas Systems I, L.P. and all of its subsidiaries were liquidated and dissolved prior to December 31, 2012.

Public Offerings . On November 26, 2012, we completed a public offering of 3,450,000 common units at a price of $31.16 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $102.8 million. Our general partner contributed $2.2 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce our outstanding indebtedness.

On January 25, 2012, we completed a public offering of 2,645,000 common units at a price of $36.15 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,645,000 common units, net of underwriters' discounts, commissions and offering expenses were $91.4 million. Our general partner contributed $2.0 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce our outstanding indebtedness.

Debt Financing Activities. On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility. On May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million. See subsequent events section below for discussion surrounding our February 2013 issuance of senior unsecured notes.

For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Credit Facility” within this Item.

Subsequent Events

NGL Marine Equipment Purchase. On February 28, 2013, we purchased from affiliates of Florida Marine Transporters, Inc. six liquefied petroleum gas pressure barges and two commercial push boats for approximately $50.8 million. The purchase was funded with borrowings under the Partnership's revolving credit facility.

Senior Notes Issuance. On February 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.25% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $245.1 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership's revolving credit facility.

Quarterly Distribution. On January 24, 2013, we declared a quarterly cash distribution of $0.77 per common unit for the fourth quarter of 2012, or $3.08 per common unit on an annualized basis, which was paid on February 14, 2013 to unitholders of record as of February 7, 2013.

Common Unit Grants. On January 2, 2013, we issued 57,500 restricted common units under our long-term incentive plan to the executive officers of the General Partner and certain Martin Resource Management employees who provide services to us. These restricted units vest 100% on January 1, 2016.

Our Business Strategy

The key components of our business strategy are:


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

•

Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to Existing Customers . 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, storing 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 an efficient and cost effective method of achieving organic growth in revenues and cash flow. We believe significant opportunities exist to expand our customer base and provide additional services and products to existing customers.

•

Pursue Strategic Acquisitions . We continually monitor the marketplace to identify and pursue accretive acquisitions that expand the services and products we offer or that expand our geographic presence. After acquiring other businesses, we 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 Strategic Commercial Alliances . Many of our larger customers, which include major integrated energy companies, have established strategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operational synergies. We intend to pursue strategic commercial alliances with such customers in the future.

Competitive Strengths

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

Fee Based Contracts . We generate a majority of our cash flow from fee-based contracts with our customers. In addition, a significant portion of these fee-based contracts consist of reservation charges or minimum fee arrangements, which reduce the volatility of a portion of our cash flows due to volume fluctuations.

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

distribution network enables us to provide customers with a complementary portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by-products.

Strategically Located Assets . We are one of the largest operators of marine service shore-based terminals in the U.S. Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas storage and natural gas liquids distribution and storage assets are focused in areas that continue to experience high levels of drilling activity. In addition, our natural gas storage assets are located in areas highly desirable for our customers. Finally, many of our sulfur services assets are strategically located to source sulfur from the largest refinery sources in the U.S.

Specialized Transportation Equipment and Storage Facilities . We have the assets and expertise to handle and transport certain petroleum products and by-products with unique requirements for transportation and storage. For example, we own facilities and resources to transport a variety of specialty products, including ammonia, molten sulfur and asphalt. Some of these specialty products require treatment across a wide range of temperatures ranging between approximately -30 to +400 degrees Fahrenheit to remain in liquid form, which our facilities are designed to accommodate. We believe these capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.

Strong Industry Reputation and Established Relationships with Suppliers and Customers . We believe we have established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient operation of our facilities. Our management has also established long-term relationships with many of our suppliers and customers. We believe we benefit from our management's reputation and track record and from these long-term relationships.

Financial Strength and Flexibility . We have historically financed our operations with a combination of debt and equity while maintaining a modest leverage profile, even in challenging business environments. Since our initial public offering, we have accessed the public equity markets eight times for approximately $539.3 million in total net proceeds, including capital contributions from our general partner. As of March 4, 2013, we have accessed the public debt markets two times for approximately $442.3 million in total net proceeds. We have also occasionally issued common units to Martin Resource Management in exchange for cash or assets.

Experienced Management Team and Operational Expertise . Members of our executive management team and the heads of our principal business lines have, on average, more than 30 years of experience in the industries in which we operate. 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.

Terminalling and Storage Segment

Industry Overview. The U.S. 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, railcars and trucks. Terminals play a key role in moving these products throughout the distribution system by providing storage, blending and other ancillary services.

In the 1990s, the petroleum industry entered a period of consolidation. Refiners and marketers developed large-scale, cost-efficient operations resulting in several refinery acquisitions, combinations, alliances and joint ventures. This consolidation resulted in major oil companies integrating the various components of their businesses, including terminalling and storage. However, major integrated oil companies later concentrated their focus and resources on their core competencies of exploration, production, refining and retail marketing and examined ways to lower their distribution costs. Additionally, the Federal Trade Commission required some divestitures of terminal assets in markets in which merged companies, alliances and joint ventures were regarded as having excessive market power. As a result of these factors, oil and gas companies began to increasingly rely on third parties, such as us, to perform many terminalling and storage services.

Although many large energy and chemical companies own terminalling and storage facilities, these companies also use third-party terminalling and storage services. Major energy and chemical companies typically have a strong demand for terminals owned by independent operators when such terminals are strategically located at or near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of lack of capacity, the nature of the stored material or specialized handling requirements.

The Gulf Coast region is a major hub for petroleum refining. Approximately 50% of U.S. refining capacity exists in this region. Growth in the refining and natural gas processing industries has increased the volume of petroleum products and by-products that are transported within the Gulf Coast region, which consequently has increased the need for terminalling and storage services.

The marine and offshore oil and gas exploration and production industries use terminal facilities in the Gulf Coast region as shore bases that provide them logistical support services as well as provide a broad range of products, including fuel oil, lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly influenced by current and projected prices of oil and natural gas.

Marine Shore Based Terminals. We own or operate 31 marine shore based terminals along the Gulf Coast from Theodore, Alabama to Corpus Christi, Texas. Of our 31 marine shore based terminals, 12 were acquired on January 31, 2011, through our acquisition of certain terminalling assets from Martin Resource Management and seven were acquired through the purchase of Talen's on December 31, 2012. Our terminal assets are located at strategic distribution points for the products we handle and are in close proximity to our customers.

We are one of the largest operators of marine shore based terminals in the Gulf Coast region. These terminals are used to distribute and market fuel and lubricants, and the full service terminals also provide shore bases for companies that are operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production companies and oilfield service companies, such as drilling fluid companies, marine transportation companies and offshore construction companies. Shore bases typically provide logistical support, including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. In addition, Martin Resource Management, through contractual arrangements, pays us for terminalling and storage of fuel oil and lubricants at these terminal facilities.

Our 31 marine shore based terminals are divided into two classes of terminals: (i) full service terminals and (ii) fuel and lubricant terminals.

Full Service Terminals. We own or operate 12 full service terminals. These terminal facilities provide logistical support services and storage and handling services for fuel oil and lubricants. The significant difference between our full service terminals and our fuel and lubricant terminals is that our full service terminals generate additional revenues by providing shore bases to support our customer’s operating activities related to the offshore exploration and production industry. One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drilling industry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore operations. Customers of our full service terminals are primarily oil and gas exploration and production companies, oilfield service companies such as drilling fluids companies, marine transportation companies and offshore construction companies.

The following is a summary description of our 12 full service terminals:



Terminal	Location	Aggregate Capacity
Amelia-2 (3)(4)	Amelia, Louisiana	13,000 Bbls.
Cameron East (2)	Cameron, Louisiana	32,500 Bbls.
Dock 193 (7)(12)	Geuydan, Louisiana	14,700 Bbls.
Fourchon-15 (3)(6)	Fourchon, Louisiana	16,500 Bbls.
Freshwater City (7)(8)(9)	Freshwater City, Louisiana	7,400 Bbls.
Galveston-T (7)	Galveston Texas	10,400 Bbls.
Harbor Island (1)	Harbor Island, Texas	31,400 Bbls.
Intracoastal City-2 (3)(5)	Intracoastal City, Louisiana	12,500 Bbls.
Pascagoula	Pascagoula, Mississippi	11,000 Bbls.
Pelican Island	Galveston, Texas	88,600 Bbls.
Theodore	Theodore, Alabama	20,000 Bbls.
Venice (3)(10)(11)	Venice, Louisiana	25,000 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 2015.


(2)	This terminal is located on land owned by third parties and leased under a lease that expires in March 2017 and can be extended by us through February 2022.


(3)	These terminals were acquired from Martin Resource Management on January 31, 2011.


(4)	This terminal is located on land owned by a third party and leased under a lease that expires in August 2018 and can be extended by us through August 2023.


(5)	This terminal is located on land owned by a third party and leased under a lease that expires in December 2015 and can be extended by us through December 2025.


(6)	This terminal is located on land owned by a third party and leased under a lease that expires in February 2017.


(7)	These terminals were acquired from the purchase of Talen's on December 31, 2012.


(8)	This terminal is located on land owned by a third party and leased under a lease that expires in March 2014 and can be extended by us through March 2017.


(9)	This terminal has a warehousing agreement with a third party and under a lease that expires in March 2014 and can be extended by us through March 2017.


(10)	This terminal is located on land owned by third parties and leased under a lease that expires in September 2017 and can be extended by us through December 2027


(11)	This terminal was converted from a fuel and lube terminal to a full service terminal in 2012.


(12)	A Portion of this terminal is located on land owned by a third party and leased under a lease that expires in May 2014 and can be extended by us through May 2016.

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

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



Terminal	Location	Aggregate Capacity
Berwick (1)	Berwick, Louisiana	25,000 Bbls.
Cameron West (5)(19)	Cameron, Louisiana	18,400 Bbls.
Cameron-7 (10)(20)(19)	Cameron, Louisiana	15,500 Bbls.
Cameron-8 (10)(6)(19)(23)	Cameron, Louisiana	32,000 Bbls.
Dulac (10)(12)	Dulac, Louisiana	16,300 Bbls.
Fourchon (9)	Fourchon, Louisiana	80,500 Bbls.
Fourchon 16 (10)(17)	Fourchon, Louisiana	11,900 Bbls.
Fourchon 17(10)(13)	Fourchon, Louisiana	40,900 Bbls.
Fourchon-T (4)(11)	Fourchon, Louisiana	39,100 Bbls.
Freeport (19)	Freeport, Texas	8,500 Bbls.
Intracoastal City (7)(8)(23)	Intracoastal City, Louisiana	32,400 Bbls.
Lake Charles-T (4)(18)	Lake Charles, Louisiana	13,500 Bbls.
Morgan City 33 (10)(16)(23)	Morgan City, Louisiana	53,500 Bbls.
Morgan City DWC 31(10)(15)	Morgan City, Louisiana	7,100 Bbls.
Port Arthur (4)(21)	Port Arthur, Texas	0 Bbls.
Port O'Connor (2)(19)	Port O'Connor, Texas	7,000 Bbls.
River Ridge (10)(14)	River Ridge, Louisiana	10,000 Bbls.
Sabine Pass (3)(19)	Sabine Pass, Texas	17,500 Bbls.
Texas Terminal (4)(22)	Houston, Texas	0 Bbls.


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


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


(3)	This terminal is located on land owned by a third party and leased under a lease that expires in September 2016 and can be extended by us through September 2036.


(4)	These terminals were acquired from the purchase of Talen's on December 31, 2012.


(5)	This terminal is located on land owned by a third party and leased under a lease that expires in February 2013. We are currently negotiating to extend the lease until February 2033.


(6)	This terminal is located on land owned by a third party and leased under a lease that expires in July 2016 and can be extended by us through July 2036.


(7)	A portion of this terminal is located on land owned by a third party at which we throughput fuel oil pursuant to an agreement that expires in April 2014.


(8)	A portion of this terminal is located on land owned by third parties and leased under a lease that expires in April 2014.


(9)	This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an agreement that expires in January 2017.


(10)	These terminals were acquired from Martin Resource Management on January 31, 2011.


(11)	This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an agreement that expires in October 2018 and can be extended by us through October 2038.


(12)	This terminal is located on land owned by third parties and leased under a lease that expires in December 2021 and can be extended by us through December 2041.


(13)	This terminal is located on land owned by third parties and leased under a lease that expires in December 2013 and can be extended by us through December 2023.


(14)	This terminal is located on land owned by third parties and leased under a lease that expires in April 2019.


(15)	This terminal is located on land owned by third parties and leased under a lease that expires in December 2014 and can be extended by us through December 2034. In addition, there is an office sublease that expires December 2014 and can be extended through December 2019.


(16)	This terminal is located on land owned by third parties and leased under a lease that expires in May 2014 and can be extended by us through May 2019.


(17)	This terminal is located on land owned by third parties and leased under multiple leases that expires in July 2017, and July 2016, and March 2017. These leases can be extended by us through March 2022, and July 2026, respectively.


(18)	This terminal is located on land owned by third parties and leased under a lease that expires in April 2023.


(19)	These terminals were converted from full services terminals to fuel and lube terminals during 2012.


(20)	This terminal is located on land owned by a third party and leased under a lease that expires in July 2017 and can be extended by us through July 2027.


(21)	This terminal is located on land owned by third parties and leased under a lease that expires in November 2015 and can be extended by us through November 2025.


(22)	This terminal is located on land owned by third parties and leased under a lease that expires 55 months after receipt of the U.S. Army Corps of Engineers permit for dredging.


(23)	These terminals are currently in caretaker status.

Specialty Petroleum Terminals. We own or operate 16 terminal facilities providing storage and handling services for some or all of the following: anhydrous ammonia, asphalt, sulfur, sulfuric acid, fuel oil, crude oil and other petroleum products and by-products. Of our 14 terminals, one was acquired on January 31, 2011, through our acquisition of certain terminalling assets from Martin Resource Management and two were acquired through our acquisition of Talen's on December 31, 2012. Our specialty terminals have an aggregate storage capacity of approximately 2.9 million barrels. Each of these terminals has storage capacity for petroleum products and by-products and assets to handle products transported by vessel, barge and/or truck. The location and composition of our terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated services in the handling and transportation of petroleum products and by-products. We primarily 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 have also identified strategic locations near rail, waterways and pipelines and have developed our own terminal facilities. We expect to continue to acquire facilities, streamline their operations and customize and upgrade them as part of our growth strategy. We also anticipate continuing to develop our own facilities when strategically desirable locations are identified. We also continually evaluate opportunities to add services and increase access to our terminals to attract more customers and create additional revenues.

Our Tampa terminal is located on approximately 10 acres of land owned by the Tampa Port Authority that was leased to us under a 10-year lease that commenced on December 16, 2006 with two five-year options. Our Stanolind terminal is located on approximately 11 acres of land owned by us located on the Neches River in Beaumont, Texas. Our Neches terminal is a deep water marine terminal located near Beaumont, Texas, on approximately 50 acres of land owned by us. Our Corpus Christi, Texas Barge terminal is located on approximately 25 acres of land owned by us and has access to the waterfront via marine docks owned by the Port of Corpus Christi. Our Corpus Christi, Texas Crude terminal is located on 10 acres leased from the Port of Corpus Christi under terms of a five-year lease commencing on May 18, 2011 with five five-year options.

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

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

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

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

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

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

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

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

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

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

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

The following is a summary description of our shore-based specialty terminals:



Terminal	Location	Aggregate Capacity	Products	Description
Tampa (1)	Tampa, Florida	718,000 Bbls.	Asphalt, sulfur and fuel oil	Marine terminal, loading/unloading for vessels, barges railcars and trucks
Stanolind	Beaumont, Texas	555,000 Bbls.	Asphalt, crude oil, sulfur, sulfuric acid and fuel oil	Marine terminal, marine dock for loading/unloading of vessels, barges, railcars and trucks
Neches	Beaumont, Texas	500,400 Bbls.	Molten sulfur, ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer	Marine terminal, loading/unloading for vessels, barges, railcars and trucks
Corpus Christi Barge terminal	Corpus Christi, Texas	150,000 Bbls.	Fuel oil and diesel	Marine terminal, loading/unloading barges and vessels and unloading trucks
Corpus Christi Crude terminal (2)	Corpus Christi, Texas	600,000 Bbls.	Crude oil	Marine terminal, loading/unloading barges and vessels, trucks, and pipeline access


(1)	This terminal is located on land owned by the Tampa Port Authority that was leased to us under a 10-year lease that expires in December 2016 with two five-year extension options.


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

The following is a summary description of our non shore-based specialty terminals:



Terminal	Location	Aggregate Capacity	Products	Description
Channelview	Houston, Texas	44,000 sq. ft. Warehouse 35,000 Bbls	Lubricants	Lubricants blending and storage
Smackover Refinery	Smackover, Arkansas	7,500 Bbls per day	Naphthenic lubricants, Distillates, Asphalt	Crude refining facility
Martin Lubricants	Smackover, Arkansas	235,000 sq. ft. Warehouse 5.3 million gallons bulk storage	Gard, SynGard, and Xtreme brands, and private label packaged lubricants	Lubricants packaging facility
Martin Lubricants	Kansas City, Kansas	65,000 sq. ft. Warehouse 1.5 million gallons bulk storage	Gard, SynGard, and Xtreme brands, and private label packaged lubricants	Lubricants packaging facility
South Houston Asphalt	Houston, Texas	71,000 Bbls	Asphalt	Asphalt Processing and storage
Port Neches Asphalt	Port Neches, Texas	31,300 Bbls	Asphalt	Asphalt Processing and storage
Omaha Asphalt	Omaha, Nebraska	114,200 Bbls	Asphalt	Asphalt Processing and storage
Spindletop	Beaumont, Texas	90,000 Bbls	Natural Gasoline	Pipeline receipts and shipments
Broussard Bulk Facility (4)(5)	Broussard, Louisiana	43,000 sq. ft. Warehouse 9,200 Bbls.	Lubricants, Fuel	Lubricants and Fuel storage
Jennings Bulk Plant (5)	Jennings, Louisiana	41,000 sq. ft. building space 4,000 Bbls.	Lubricants, Fuel	Lubricants and Fuel storage
Lake Charles (3)	Lake Charles, Louisiana	18,000 sq. ft.Warehouse 6,800 Bbls	Lubricants	Lubricants storage


(3)	This terminal is located on land owned by third parties and leased under a lease that expires in January 2016 and can be extended by us through January 2021. This terminal was acquired from Martin Resource Management on January 31, 2011.


(4)	This terminal is located on land owned by third parties and leased under a lease that expires in November 2015 and can be extended by us through November 2030.


(5)	These terminals were acquired from the purchase of Talen's on December 31, 2012.

Competition. We compete with independent terminal operators and major energy and chemical companies that own their own terminalling and storage facilities. We believe many customers prefer to contract with independent terminal operators rather than terminal operators owned by integrated energy and chemical companies that may have refining or marketing interests that compete with the customers.

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

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

such as asphalt, sulfur, anhydrous ammonia and sulfuric acid. As a result, our facilities typically command higher terminal fees when compared to fees charged for terminalling and storage of other petroleum products.

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

Natural Gas Services Segment

NGL Industry Overview. NGLs are produced through natural gas processing. They are also a by-product of crude oil refining. NGLs include ethane, propane, normal butane, iso butane and natural gasoline.

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

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


•	storage of NGLs purchased in off-peak months;


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


•	product management expertise to obtain supplies when needed.

The following is a summary description of our owned and leased NGL facilities:



NGL Facility	Location	Capacity	Description
Wholesale terminals	Arcadia, Louisiana (1)	2,200,000 barrels	Underground storage
	Breaux Bridge, Louisiana (2)	415,000 barrels	Underground storage
	Hattiesburg, Mississippi (2)	60,000 barrels	Underground storage
	Mt. Belvieu, Texas (2)	65,000 barrels	Underground storage
Retail terminals	Kilgore, Texas	90,000 gallons	Retail propane distribution
	Longview, Texas	30,000 gallons	Retail propane distribution
	Henderson, Texas	12,000 gallons	Retail propane distribution

__________


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


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

Our NGL customers that utilize these assets consist of retail propane distributors, industrial processors and refiners. For the year ended December 31, 2012, we sold approximately 87% of our NGL volume to refiners and industrial processors

and approximately 13% of our NGL volume to independent retail propane distributors located in Texas and the southeastern U.S.

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

NGL Seasonality. The level of NGL supply and demand is subject to changes in domestic production, weather, inventory levels and other factors. While production is not seasonal, residential, refinery, and wholesale demand is highly seasonal. This imbalance causes increases in inventories during summer months when consumption is low and decreases in inventories during winter months when consumption is high. If inventories are low at the start of the winter, higher prices are more likely to occur during the winter. Additionally, abnormally cold weather can put extra upward pressure on prices during the winter because there are less readily available sources of additional supply except for imports, which are less accessible and may take several weeks to arrive. General economic conditions and inventory levels have a greater impact on industrial and refinery use of NGLs than the weather.

We generally maintain consistent margins in our natural gas services business because we attempt to pass increases and decreases in the cost of NGLs directly to our customers. We generally try to coordinate our sales and purchases of NGLs based on the same daily price index of NGLs in order to decrease the impact of NGL price volatility on our profitability.

Redbird Gas Storage

Through our ownership interests in Redbird, we formed Cardinal, a joint venture with ECP, which is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi. At December 31, 2012, we owned an unconsolidated 41.28% interest in Cardinal. Through Redbird, we have the ability to invest in gas storage development projects at the Cardinal level. The Cardinal facilities are discussed below as follows:

Arcadia Gas Storage, LLC ("Arcadia"), located in Bienville Parish, Louisiana, is in service with 7.85 billion cubic feet ("bcf") of working storage capacity, of which 100% is contracted under firm storage service agreements. As of December 31, 2012, the weighted average remaining term of our existing portfolio of third party firm storage contracts was approximately 2.7 years. Additional capacity of 6.5 bcf is under development and is expected to be in service in the third quarter of 2013.

Monroe Gas Storage Company, LLC ("Monroe"), located in Monroe County, Mississippi, is in operation with approximately 9.0 bcf of working storage capacity, of which 100% is contracted under firm storage service agreements. As of December 31, 2012, the weighted average remaining term of our existing portfolio of third party firm storage contracts was approximately 1.5 years.

Perryville Gas Storage, LLC ("Perryville"), located in Franklin Parish, Louisiana, is under development with approximately 8.5 bcf of working storage capacity, of which 100% is contracted under firm storage service agreements with an average contract term of 5.6 years. The project is expected to be in service in the third quarter of 2013.

Cadeville Gas Storage, LLC ("Cadeville"), located in Ouachita Parish, Louisiana, is under development with approximately 17.0 bcf of working storage capacity, of which 100% is contracted under firm storage service agreements with an average contract term of 10.0 years. The project is expected to be in service in the third quarter of 2013.

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

Natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market conditions. The long term demand for storage services in the U.S. is driven primarily by the long-term demand for natural gas and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis. In general and on a long term basis, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations,

should increase the need for and the value of storage services. On a short term basis, storage demand and values are also significantly influenced by operational imbalances, near term seasonal spreads, shorter term spreads and basis differentials.

Sulfur Services Segment

Industry Overview. Sulfur is a natural element and is required to produce a variety of industrial products. In the U.S., approximately 10 million tons of sulfur are consumed annually with the Tampa, Florida area being the largest single market. Currently, all sulfur produced in the U.S. is “recovered sulfur,” or sulfur that is a by-product from oil refineries and natural gas processing plants. Sulfur production in the U.S. is principally located along the Gulf Coast, along major inland waterways and in some areas of the western U.S.

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

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

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

Our Operations and Products. We have an integrated system of transportation assets and facilities relating to our sulfur services. We gather molten sulfur from refiners, primarily located on the Gulf Coast, and from natural gas processing plants, primarily located in the southwestern U.S. We transport sulfur by inland and offshore barges, railcars and trucks. In the U.S., recovered sulfur is mainly kept in liquid form from production to usage at a temperature of approximately 275 degrees Fahrenheit. Because of the temperature requirement, the sulfur industry uses specialized equipment to store and transport molten sulfur. We have the necessary assets and expertise to handle the unique requirements for transportation and storage of molten sulfur.

The terms of our commercial sulfur contracts typically range from one to five years in length. We handle molten sulfur on cost-plus contracts and margin-based contracts and the prices in such contracts are usually tied to a published market indicator and fluctuate according to the price movement of the indicator. We also provide barge transportation and tank storage to large integrated oil companies that produce sulfur and fertilizer manufacturers that consume sulfur under transportation and storage contracts with remaining lives from one to two years in duration.

The sulfur prilling assets located at the Port of Stockton in California are used to process (prill) molten sulfur into pellets. The Stockton facility can process approximately 1,000 metric tons of molten sulfur per day and the resulting dry pellets are stored in bulk until sold into certain U.S. and international agricultural markets. In 2006, we completed the construction of a sulfur priller at our Neches facility in Beaumont, Texas with construction of a second priller completed in 2009. Forming capacity was further increased in 2012 with the addition of a granulator. The two Beaumont prillers along with the granulator have the capacity to process approximately 5,500 metric tons of molten sulfur per day. We process molten sulfur into formed sulfur on take-or-pay fee contracts, providing refiners access to the export market for the sale of their residual sulfur.

We entered the sulfur based fertilizer manufacturing business through acquisitions in 1990 and 1998. We have expended significant resources to replace and update facilities and other assets and to integrate each of the acquired businesses into our existing business resulting in increased the profitability of our fertilizer business. In December 2005, sulfur fertilizer production capacity was added with the purchase of the net operating assets of A & A Fertilizer, Ltd. (“A & A Fertilizer”). This production capacity is located at our Neches deep-water marine terminal near Beaumont, Texas.

In September 2007, we completed construction of a sulfuric acid production facility at our Plainview, Texas location. This facility processes molten sulfur to produce approximately 150,000 tons of sulfuric acid per year. This acid production provides a dedicated supply of raw material sulfuric acid to our ammonium sulfate production plant that was completed in March of 2011. The ammonium sulfate plant produces approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S. The sulfuric acid produced and not consumed by the captive ammonium sulfate production is sold to Martin Resource Management which markets the excess production to third parties.

Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to sulfur and our distribution capabilities. These products allow us to leverage the Sulfur Services segment of our business. Our annual fertilizer and industrial sulfur products sales have grown from approximately 62,000 tons in 1997 to approximately 306,000 tons in 2012 as a result of acquisitions and internal growth.

In the U.S., fertilizer is generally sold to farmers through local dealers. These dealers are typically owned and supplied by much larger wholesale distributors. We sell to these wholesale distributors. Our industrial sulfur products are marketed primarily in the southern U.S., where many paper manufacturers and power plants are located. Our products are sold in accordance with price lists that vary from state to state. These price lists are updated periodically to reflect changes in seasonal or competitive prices. We transport our fertilizer and industrial sulfur products to our customers using third-party common carriers. We utilize rail shipments for large volume and long distance shipments where available.

We manufacture and market the following sulfur-based fertilizer and related sulfur products:

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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 U.S. to direct application agricultural markets. Our agricultural ground sulfur products are used primarily in the western U.S. on grapes and vegetable crops.

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

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Industrial sulfur products. We produce industrial sulfur products such as elemental pastille sulfur, industrial ground sulfur products, and emulsified sulfur. We produce elemental pastille sulfur at our 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. 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.

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Liquid sulfur products. We produce ammonium thiosulfate at our Neches terminal facility in Beaumont, Texas. This agricultural sulfur product is a clear liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid plant nutrient used directly through spray rigs or irrigation systems. It is also blended with other NPK liquids or suspensions as well. Our market is predominantly the Mid-South U.S. and Coastal Bend area of Texas.

Our Sulfur Services Facilities.

We own 56 railcars and lease 120 railcars equipped to transport molten sulfur. We own the following major marine assets and use them to transport molten sulfur from our Beaumont, Texas terminal to our Tampa, Florida terminal as well as provide third party marine transportation services to others:



Asset	Class of Equipment	Capacity/Horsepower	Products Transported
Margaret Sue	Offshore tank barge	10,450 long tons	Molten sulfur
M/V Martin Explorer	Offshore tugboat	7,200 horsepower	N/A
M/V Martin Express	Inland push boat	1,200 horsepower	N/A
MGM 101	Inland tank barge	2,450 long tons	Molten sulfur
MGM 102	Inland tank barge	2,450 long tons	Molten sulfur

We own the following sulfur forming facilities as part of our sulfur services business:



Terminal	Location	Daily Production Capacity	Products Stored
Neches	Beaumont, Texas	5,500 metric tons per day	Molten, prilled and granulated sulfur
Stockton	Stockton, California	1,000 metric tons per day	Molten and prilled sulfur

We lease 79 railcars to transport our fertilizer products. We own the following manufacturing plants as part of our sulfur services business:



Facility	Location	Capacity	Description
Fertilizer plant	Plainview, Texas	150,000 tons/year	Fertilizer production
Fertilizer plant	Beaumont, Texas	120,000 tons/year	Liquid sulfur fertilizer production
Fertilizer plants (two)	Odessa, Texas	70,000 tons/year	Dry sulfur fertilizer production
Fertilizer plant	Seneca, Illinois	36,000 tons/year	Dry sulfur fertilizer production
Fertilizer plant	Salt Lake City, Utah	25,000 tons/year	Blending and packaging
Industrial sulfur plant	Texarkana, Texas	18,000 tons/year	Emulsified sulfur production
Sulfuric acid plant	Plainview Texas	150,000 tons/year	Sulfuric acid production

Competition. We own one of the four vessels currently used to transport molten sulfur between U.S. ports on the Gulf of Mexico and Tampa, Florida. Six phosphate fertilizer manufacturers together consume a vast majority of the sulfur produced in the U.S. and these buy from resellers as well as directly from producers. We compete primarily with U.S. producers that sell directly to consumers with access to transportation and storage assets as well as foreign suppliers from Mexico or Venezuela that may sell into the Florida market. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur products manufacturers. However, the close proximity of our manufacturing plants to our customer base is a competitive advantage for us in the markets we serve and allows us to minimize freight costs and respond quickly to customer requests. Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from Louisiana to California.

Seasonality. Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand during the growing season.

Marine Transportation Segment

Industry Overview. The U.S. inland waterway system is a vast and heavily used transportation system. This inland waterway system is composed of a network of interconnected rivers and canals that serve as water highways and is used to transport vast quantities of products annually. This waterway system extends approximately 26,000 miles, of which 12,000 miles are generally considered significant for domestic commerce.

The Gulf Coast region is a major hub for petroleum refining. The petroleum refining process generates products and by-products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this waterway system by the petroleum and petrochemical industry is a major reason for the current location of U.S. refineries and petrochemical facilities. The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight capacity. The combination of the power source and tank barge freight capacity is called a tow.

Marine Fleet. We utilize a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products produced in oil refining and natural gas processing. Our marine transportation business operates coastwise along the Gulf of Mexico and East Coast and on the U.S. inland waterway system, primarily between domestic ports along the Gulf of Mexico, Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system. Additionally, we participate in Caribbean, Central America, and South American transport. Our inland tows generally consist of one push boat and one to three tank barges, depending upon the horsepower of the push boat, the river or canal capacity and conditions, and customer requirements. Each of our offshore tows consist of one tugboat, with much greater horsepower than an inland push boat, and one large tank barge. We transport asphalt, fuel oil, gasoline, sulfur and other bulk liquids.

The following is a summary description of the marine vessels we use in our marine transportation business:



Class of Equipment	Number in Class	Capacity/Horsepower	Description of Products Carried
Inland tank barges	23	20,000 bbl and under	Asphalt, crude oil, fuel oil, gasoline and sulfur
Inland tank barges	31	20,000 - 30,000 bbl	Asphalt, crude oil, fuel oil and gasoline
Inland push boats	29	400 - 3,800 horsepower	N/A
Offshore tank barges	4	45,000 bbl and 95,000 bbl	Asphalt, fuel oil and NGLs
Offshore tugboats	4	2,400 - 7,200 horsepower	N/A

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

We are a party to a marine transportation agreement under which we provide marine transportation services to Martin Resource Management on a spot contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term.

Competition. We compete primarily with other marine transportation companies. The marine barging industry has experienced significant consolidation in past years. The total number of tank barges that operate in the inland waters of the U.S. has declined over the past 30 years, primarily resulting 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 our competitors. Historically, competition within the marine transportation business was based primarily on price. However, we believe customers are placing an increased emphasis on safety, environmental compliance, quality of service and the availability of a single source of supply of a diversified package of services. In particular, we believe customers are increasingly seeking transportation vendors that can offer marine, land, rail and

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

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

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

Our Relationship with Martin Resource Management

Martin Resource Management is engaged in the following principal business activities:


•	providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;


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


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


•	operating a crude oil gathering business in Stephens, Arkansas;


•	providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;


•	operating an underground NGL storage facility in Arcadia, Louisiana;


•	operating an environmental consulting company;


•	operating an engineering services company;


•	building and marketing of sulfur processing equipment;


•	supplying employees and services for the operation of our business;


•	operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal; and


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

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

Ownership

Management

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

Related Party Agreements

The Omnibus Agreement with Martin Resource Management requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $157.8 million , $142.0 million and $107.9 million of direct costs and expenses for the years ended December 31, 2012 , 2011 and 2010 , respectively. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2012, 2011, and 2010, the Conflicts Committee of our general partner approved reimbursement amounts of $7.6 million, $4.8 million and $3.8 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management’s retained businesses. the Omnibus Agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

The agreements include, but are not limited to, a motor carrier agreement, a terminal services agreement, a marine transportation agreement, a product storage agreement, a product supply agreement, a throughput agreement, and a purchaser use easement, ingress-egress easement and utility facilities easement. Pursuant to the terms of the Omnibus Agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee of our general partner’s board of directors.

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

Commercial

We have been and anticipate that we will continue to be both a significant customer and supplier of products and services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is currently a key component of our integrated distribution network.

We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.2 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

In the aggregate, our purchases of land transportation services, NGL storage services, lube oil product purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 8% of our total cost of products sold during the years ended December 31, 2012 and 2011 , and 9% for the year ended December 31, 2010 . We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for approximately 6% , 7% and 9% of our total revenues for the years ended December 31, 2012 , 2011 and 2010 , respectively. We

have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, MES, and MES provides terminal services to us to handle lubricants, greases and drilling fluids. Additionally, we have entered into a long-term, fee for services-based Tolling Agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

Approval and Review of Related Party Transactions

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

Insurance

Our deductible for onshore physical damage resulting from named windstorms is 5% of the total value located at an individual location subject to an overall minimum deductible of $4.0 million for damage caused by the named windstorm at all locations. Our onshore program currently provides $30.0 million per occurrence for named windstorm events. For non-windstorm events, our deductible applicable to onshore physical damage is $1.5 million per occurrence. Business interruption coverage in connection with a windstorm event is subject to the same $30.0 million per occurrence and aggregate limit as the property damage coverage and a waiting period of 45 days. For non-windstorm events, our waiting period applicable to business interruption is 30 days.

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

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

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

Environmental and Regulatory Matters

Our activities are subject to various federal, state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.

Environmental

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

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, there is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum products and by-products, chemical substances, and wastes as well as the accidental release or spill of such materials into the environment. Consequently, we cannot assure you that we will not incur significant costs and liabilities as result of such handling practices, releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, we cannot provide any assurance that our environmental compliance expenditures will not have a material adverse impact on us in the future.

Superfund

The Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and similar state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of “responsible persons,” including the owner or operator of a site where regulated hazardous substances have been released into the environment and companies that disposed or arranged for the disposal of the hazardous substances found at such site. Under CERCLA, these responsible persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although certain hydrocarbons are not subject to CERCLA’s reach because “petroleum” is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” We are not subject to any notification that we may be potentially responsible for cleanup costs under CERCLA.

Solid Waste

We generate both hazardous and nonhazardous solid wastes which are subject to requirements of the federal Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state statutes. From time to time, the U.S. Environmental Protection Agency (“EPA”) has considered making changes in nonhazardous waste standards that would result in stricter disposal requirements for these wastes. Furthermore, it is possible some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or operating expenses.

We currently own or lease, and have in the past owned or leased, properties that have been used for the manufacturing, processing, transportation and storage of petroleum products and by-products. Solid waste disposal practices within oil and gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that 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 ("CAA"), as amended, and comparable state statutes. Amendments to the CAA adopted in 1990 contain provisions that may result in the imposition of increasingly stringent pollution control requirements with respect to air emissions from the operations of our terminal facilities, processing and storage facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control requirements may include specific equipment or technologies to control emissions, permits with emissions and operational limitations, pre-approval of new or modified projects or facilities producing air emissions, and similar measures. For example, the Neches Terminal we use is located in an EPA-designated ozone non-attainment area, referred to as the Beaumont/Port Arthur non-attainment area, which is subject to a EPA-adopted 8-hour standard for complying with the national standard for ozone. In addition, existing sources of air emissions in the Beaumont/Port Arthur area are already subject to stringent emission reduction requirements. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air emission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are in substantial compliance with applicable requirements of the CAA and analogous state laws.

Global Warming and Climate Change . Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress has from time to time considered climate change-related legislation to restrict greenhouse gas emissions. At least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA , the EPA eventually concluded that it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA's definition of air pollutant has also led the EPA to determine that regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs is required. To that end, EPA promulgated regulations, referred to as the Tailoring Rule, 75 Fed. Red. 31514, to begin gradually subjecting stationary greenhouse gas emission sources to various Clean Air Act programs, including permitting programs applicable to new and existing major sources of greenhouse gas emissions. To date, such requirements have not had a substantial effect upon our operations. Still, new legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect our operations and demand for our services.

Clean Water Act

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Regulations promulgated under these laws require entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System (“NPDES”) and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess penalties for releases of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff and that applicable facilities develop and implement plans for the management of storm water runoff (referred to as storm water pollution prevention plans (“SWPPPs”)) as well as for the prevention and control of oil spills (referred to as spill prevention, control and countermeasure (“SPCC”) plans). As part of the regular overall evaluation of our on-going operations, we are reviewing and, as necessary, updating SWPPPs for certain of our facilities, including facilities recently acquired. In addition, we have reviewed our SPCC plans and, where necessary, amended such plans to comply with applicable regulations adopted by the EPA. We believe that compliance with the conditions of such permits and plans will not have a material effect on our operations.

Oil Pollution Act

The Oil Pollution Act of 1990, as amended (“OPA”) imposes a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The

OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages including natural resource damages. Under OPA, vessels and shore facilities handling, storing, or transporting oil are required to develop and implement oil spill response plans, and vessels greater than 300 tons in weight must provide to the U.S. Coast Guard evidence of financial responsibility to cover the costs of cleaning up oil spills from such vessels. The OPA also requires that all newly constructed tank barges engaged in oil transportation in the U.S. be double hulled and all existing single hull tank barges be retrofitted with double hulls or phased out by 2015. We believe we are in substantial compliance with all of the oil spill-related and financial responsibility requirements. Nonetheless, in the aftermath of the Deepwater Horizon incident in 2010, Congress has from time to time considered oil spill related legislation that could have the effect of substantially increasing financial responsibility requirements and potential fines and damages for violations and discharges subject to the Oil Pollution Act, and similar legislation. Any such changes in law affecting areas where we conduct business could materially affect our operations.

Safety Regulation

The Company’s marine transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international treaties. Tank ships, push boats, tugboats and barges are required to meet construction and repair standards established by the American Bureau of Shipping, a private organization, and the U.S. Coast Guard and to meet operational and safety standards presently established by the U.S. Coast Guard. We believe our marine operations and our terminals are in substantial compliance with current applicable safety requirements.

Occupational Health Regulations

The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Our marine vessel operations are also subject to safety and operational standards established and monitored by the U.S. Coast Guard.

In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. These expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business.

Jones Act

The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels built and registered in the U.S. and owned and manned by U.S. citizens. Since we engage in maritime transportation between locations in the U.S., we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all U.S.-flagged vessels be manned by U.S. citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by U.S. citizen seamen. This requirement significantly increases operating costs of U.S.-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by U.S.-flagged vessel owners. The U.S. Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience.

Merchant Marine Act of 1936

The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the President of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S.’ citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats, tugboats or tank barges.

Employees

We do not have any employees. Under our Omnibus Agreement with Martin Resource Management, Martin Resource Management provides us with corporate staff and support services. These services include centralized corporate functions, such as accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other corporate services. Martin Resource Management employs approximately 835 individuals including 55 employees represented by labor unions who provide direct support to our operations as of March 4, 2013.

Financial Information about Segments

Information regarding our operating revenues and identifiable assets attributable to each of our segments is presented in Note 19 to our consolidated financial statements included in this annual report on Form 10-K.

Access to Public Filings

We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed with the Securities and Exchange Commission (“SEC”) under the Securities and Exchange Act of 1934. These documents may be accessed free of charge on our website at the following address: www.martinmidstream.com. These documents are provided as soon as is reasonably practicable after their filing with the SEC. This website address is intended to be an inactive, textual reference only, and none of the material on this website is part of this report. These documents may also be found at the SEC’s website at www.sec.gov.



Item 1A.	Risk Factors

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

Risks Relating to Our Business

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

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

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

• the costs of acquisitions, if any;


•	the prices of petroleum products and by-products;


•	fluctuations in our working capital;


•	the level of capital expenditures we make;


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


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


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

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

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

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

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

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

We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Although the domestic capital markets have been available to us, global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, continued high unemployment, geopolitical issues and the current weak economic conditions. In addition, the fixed-income markets have experienced periods of extreme volatility, which have negatively impacted market liquidity conditions.

As a result of these conditions, the availability of funds from the credit and capital markets has diminished significantly, and the cost of raising money in the debt and equity capital markets has increased substantially. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers. In addition, lending counterparties under our existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations. These conditions have made, and may continue to make, it difficult to obtain funding for our capital needs. Due to these conditions, we cannot be certain that new debt or equity financing will be available on acceptable terms or at all. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, meet our obligations as they come due or complete future acquisitions or expansion and maintenance capital projects, any of which could have a material adverse effect on our revenues and results of operations.

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

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


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


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


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

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

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

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

Currently, there are numerous international, federal and state-level initiatives and proposals addressing domestic and global climate issues. Within the U.S., most of these proposals would regulate and/or tax, in one fashion or another, the production of carbon dioxide and other "greenhouse gases" to facilitate the reduction of carbon compound emissions to the atmosphere, and provide tax and other incentives to produce and use more "clean energy."

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

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


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


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


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


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

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

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

Our distribution network and operations are primarily concentrated in the Gulf Coast region and along the Mississippi River inland waterway. Weather in these regions is sometimes severe (including tropical storms and hurricanes) and can be a

major factor in our day-to-day operations. Our marine transportation operations can be significantly delayed, impaired or postponed by adverse weather conditions, such as fog in the winter and spring months and certain river conditions. Additionally, our marine transportation operations and our assets in the Gulf of Mexico, including our barges, push boats, tugboats and terminals, can be adversely impacted or damaged by hurricanes, tropical storms, tidal waves or other related events. Demand for our lubricants and the diesel fuel we throughput in our Terminalling and Storage segment can be affected if offshore drilling operations are disrupted by weather in the Gulf of Mexico.

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

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

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


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


•	leakage of NGLs and other petroleum products and by-products;


•	fires and explosions;


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


•	terrorist attacks or sabotage.

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

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

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

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

Increasing energy prices could adversely affect our results of operations.

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

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

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

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

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


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


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


•	worldwide demand for oil and natural gas;


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


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


•	local and international political and economic conditions and policies;


•	technological advances affecting energy production and consumption;


•	weather conditions;


•	environmental regulation; and


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


•	catastrophic events, including hurricanes;


•	environmental remediation;


•	labor difficulties; and


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

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

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

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

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

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

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

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

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 Oil Pollution Act of 1990 ("OPA") provides for the phase out of single-hull vessels and the phase-in of the exclusive operation of double-hull tank vessels in U.S. waters for barges that carry petroleum products that are regulated under OPA. Under OPA, substantially all tank vessels that do not have double hulls will be phased out by 2015 and will not be

permitted to enter United States ports or trade in U.S. waters. The phase-out dates vary based on the age of the vessel and other factors. All but one of our offshore tank barges are double-hull vessels that have no phase out date. We have one single-hull barge that will be phased out of the petroleum product trade by the year 2015. The phase out of these single-hull vessels in accordance with OPA may require us to make substantial capital expenditures, which could adversely affect our operations and market position and reduce our cash available for distribution.

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

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

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

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

Risks Relating to an Investment in the Common Units

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

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

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


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


•	the conversion of subordinated units into common units;


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


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

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

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and

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

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

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

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

If unitholders are dissatisfied with the performance of our general partner, they will have a limited ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. As of December 31, 2012, Martin Resource Management owned 19.2% of our total outstanding common limited partner units.

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

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

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

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

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

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


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


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

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

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

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


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


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


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


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

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

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

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


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


•	the conversion of subordinated units into common units;


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


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

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

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


•	our unitholders' proportionate ownership interest in us will decrease;


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


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


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


•	the market price of the common units may decline; and


•	the ratio of taxable income to distributions may increase.

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

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

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

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

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

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

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

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

Risks Relating to Our Relationship with Martin Resource Management

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

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

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

As of December 31, 2012, Martin Resource Management owned 19.2% of our total outstanding common limited partner units and a 2% general partnership interest in us and all of our incentive distribution rights. Conflicts of interest may arise between Martin Resource Management and our general partner, on the one hand, and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its' own interests and the interests of Martin Resource Management over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management and our general partner could occur in many of our day-to-day operations including, among others, the following situations:


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

•

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


•	Martin Resource Management may engage in limited competition with us;


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

•

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


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


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


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


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


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


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


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

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

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

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

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

Tax Risks

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

The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. In order for us to be classified as a partnership for U.S. federal income tax purposes, more than 90% of our gross income each year must be “qualifying income” under Section 7704 of the U.S. Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). “Qualifying income” includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

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

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

distribution to unitholders would be reduced. Treatment of us as a corporation would result in a reduction in the anticipated cash flow and after-tax return to unitholders and therefore would likely result in a reduction in the value of the common units.

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

A successful IRS contest of the federal income tax positions we take 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.

The IRS may adopt positions that differ from our counsel's conclusions. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by all of our unitholders, debt security holders and our general partner.

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

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

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

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

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

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

We treat a purchaser of our common units as having the same tax benefits without regard to the seller's identity. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation positions that may not conform to all aspects of the Treasury regulations. Any position we take that is inconsistent with applicable Treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.

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

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

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

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

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain events that occurred in previous years, members of Congress have considered substantive changes to the existing U.S. tax laws including the definition of qualifying income under Section 7704(d) of the Internal Revenue Code and the treatment of certain types of income earned from profits interests in partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be enacted. Moreover, President Obama has recently urged Congress to consider tax reform pursuant to a Joint Report by The White House and The Department of the Treasury titled The President's Framework for Business Tax Reform released February 2012. Among the President's proposals is to establish greater parity between large corporations and large non-corporate counterparts which could include entity level taxation for publicly traded partnerships, including us. It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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

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

procedure whereby, if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be allowed to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurred.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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



Item 1B.	Unresolved Staff Comments

None.



Item 2.	Properties

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

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



Item 3.	Legal Proceedings

From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. A description of our legal proceeding is included in Item 8. Financial Statements and Supplementary Data, Note 21. Commitments and Contingencies, and is incorporated herein by reference.



Item 4.	Mine Safety Disclosures

Not applicable.

PART II



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

Our common units are traded on the NASDAQ under the symbol “MMLP.” As of March 1, 2013 there were approximately 100 holders of record and approximately 24,166 beneficial owners of our common units. The following table sets forth the high and low sale prices of our common units for the periods indicated, based on the daily composite listing of stock transactions for the NASDAQ and cash distributions declared per common and subordinated units during those periods:

Fiscal 2012:



	Common Units				Distributions Declared per Unit
Quarters Ended	High		Low		Common		Subordinated ¹
March 31, 2012	$	37.91	$	32.77	$	0.7625	$	—
June 30, 2012	$	35.75	$	29.46	$	0.7625	$	—
September 30, 2012	$	35.65	$	32.39	$	0.7625	$	—
December 31, 2012	$	36.72	$	30.03	$	0.7700	$	—

Fiscal 2011:



	Common Units				Distributions Declared per Unit
Quarters Ended	High		Low		Common		Subordinated ¹
March 31, 2011	$	42.35	$	37.21	$	0.7600	$	—
June 30, 2011	$	41.44	$	36.24	$	0.7625	$	—
September 30, 2011	$	40.05	$	28.43	$	0.7625	$	—
December 31, 2011	$	36.22	$	30.06	$	0.7625	$	—

(1) All of our original 4,253,362 subordinated units which were issued upon the formation of the Partnership and subsequently converted into common units on a one-for-one basis received distributions prior to their conversion. The 889,444 subordinated units issued to Cross Oil Refining & Marketing, Inc. in connection with the November 2009 acquisition of the Smackover refining assets converted to common units in November 2011 and began receiving cash distributions in February 2012.

On March 1, 2013, the last reported sales price of our common units as reported on the NASDAQ was $34.77 per unit.

In November 2012, in connection with our public offering of 3,450,000 common units, our general partner contributed $2.2 million in cash to us in order to maintain its 2% general partner interest in us.

In January 2012, in connection with our public offering of 2,645,000 common units, our general partner contributed $2.0 million in cash to us in order to maintain its 2% general partner interest in us.

In February 2011, in connection with our public offering of 1,874,500 common units, our general partner contributed $1.5 million in cash to us in order to maintain its 2% general partner interest in us.

Within 45 days after the end of each quarter, we distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively made 98% to unitholders and 2% to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Distributions to our general partner increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement. On October 2, 2012, our general partner executed Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (“the Partnership Agreement”). The Partnership Agreement Amendment provides that our general partner, currently the holder of the incentive distribution rights, shall forego

the next $18.0 million in incentive distributions that it would otherwise be entitled to receive. As of March 4, 2013, the amount of incentive distributions the general partner has foregone is $3.4 million.

Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause a default or an event of default, or a default or an event of default exists, under our credit facility. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility.”



Item 6.	Selected Financial Data

The following table sets forth selected financial data and other operating data of the Partnership for the years ended December 31, 2012, 2011, 2010, 2009 and 2008 and is derived from the audited consolidated financial statements of the Partnership.

The following selected financial data are qualified by reference to and should be read in conjunction with the Partnership's Consolidated and Combined Financial Statements and Notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this document.



	2012 ¹			2011 ¹			2010 ¹			2009 ¹			2008 ¹
	(Dollars in thousands, except per unit amounts)
Income Statement Data:
Revenues	$	1,490,361		$	1,242,490		$	880,115		$	651,174		$	1,162,749
Cost of product sold	1,197,531			997,972			665,086			448,799			941,266
Operating expenses	151,020			137,685			113,426			113,074			123,308
Selling, general, and administrative	25,494			20,531			16,865			16,005			17,887
Depreciation and amortization	42,063			40,276			36,884			36,183			31,895
Total costs and expenses	1,416,108			1,196,464			832,261			614,061			1,114,356
Other operating income (loss)	(418		)	1,326			228			6,025			209
Operating income	73,835			47,352			48,082			43,138			48,602

Equity in earnings (loss) of unconsolidated entities	(1,113		)	(4,752		)	2,536			(5,053		)	(2,160		)
Gain from ownership change in unconsolidated entity	—			—			6,413			3,028			—
Gain from contribution of assets to Redbird	—			—			—			—			24,271
Interest expense	(30,665		)	(26,781		)	(35,322		)	(20,357		)	(23,131		)
Debt Prepayment Premium	(2,470		)	—			—			—			—
Other, net	1,092			420			385			443			3,839
Income before income taxes	40,679			16,239			22,094			21,199			51,421
Income taxes	(3,557		)	(2,872		)	(2,622		)	(3,524		)	(2,496		)
Income from continuing operations	37,122			13,367			19,472			17,675			48,925
Income from discontinued operations, net of tax	64,865			9,392			8,061			5,268			16,816
Net income	$	101,987		$	22,759		$	27,533		$	22,943		$	65,741

Net income per limited partner unit – continuing operations	$	1.32		$	0.57		$	0.25		$	0.86		$	1.65
Net income per limited partner unit – discontinued operations	2.64			0.35			0.38			0.31			1.07
Net income per limited partner unit	$	3.96		$	0.92		$	0.63		$	1.17		$	2.72

Weighted average limited partner units	23,361,551			19,545,427			17,525,089			14,680,807			14,529,826

Balance Sheet Data (at Period End):
Total assets	$	1,012,996		$	1,069,108		$	864,425		$	739,161		$	763,211
Due to affiliates	3,316			74,654			24,578			20,073			32,350
Long-term debt	474,992			458,941			372,862			304,372			295,000
Partners' capital (owners' equity)	357,962			337,187			327,960			306,594			287,282

Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	32,678			91,362			39,178			48,673			93,080
Investing activities	(15,036		)	(202,655		)	(91,016		)	(41,600		)	(54,071		)
Financing activities	(12,746		)	100,179			57,262			(9,100		)	(35,139		)

Other Financial Data:
Maintenance capital expenditures	9,195			10,947			4,653			7,601			17,998
Expansion capital expenditures	85,549			67,540			14,916			29,653			117,929
Total capital expenditures	$	94,744		$	78,487		$	19,569		$	37,254		$	135,927

Cash dividends per common unit (in dollars)	$	3.06		$	3.05		$	3.00		$	3.00		$	2.91

¹ We acquired all of the remaining Class A interests of Redbird Gas Storage LLC ("Redbird") and certain specialty lubricant product blending and packaging assets ("Blending and Packaging Assets") of Cross Oil Refining and Marketing, Inc. ("Cross") from Martin Resource Management in October 2012. The acquisitions of the Redbird Class A interests and the Blending and Packaging Assets were considered a transfer of net assets between entities under common control. The acquisition of the Redbird Class A interests and the Blending and Packaging Assets are recorded at amounts based on the historical carrying value of the assets at that date, and we are required to update our historical financial statements to include the activities of the assets as of the date of common control. Our historical financial statements for 2012, 2011, 2010, 2009 and 2008, have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the activities of the Redbird Class A interests and the Blending and Packaging Assets as if we owned these assets for these periods.



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

Overview

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


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


•	Natural gas services;


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


•	Marine transportation services for petroleum products and by-products.

The petroleum products and by-products we 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 U.S. This region is a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry.

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. As of December 31, 2012, Martin Resource Management owned 19.2% of our total outstanding common limited partner units and a 2% general partnership interest in us and all of our incentive distribution rights.

Martin Resource Management has operated our business since 2002. Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.

Recent Developments

During the past year, we continued to experience positive market dynamics in our Terminalling and Storage segment. This is in large part to the rapid development of the Eagle Ford shale basin in South Texas and its need for off-take infrastructure. In addition, we purchased certain specialty lubricant blending and packaging assets as further integration into our existing assets.

Recent Acquisitions

Talen's Marine & Fuel, LLC. On December 31, 2012, we acquired all of the outstanding membership interests in Talen's Marine & Fuel, LLC (“Talen's”) from Quintana Energy Partners, L.P. for $103.4 million, subject to certain post-closing adjustments. Simultaneous with the acquisition, we sold certain working capital-related assets to Martin Energy Services LLC (“MES”), a wholly-owned subsidiary of Martin Resource Management for $56.0 million, reducing our investment in Talen's to $47.4 million. In conjunction with its purchase of certain working capital-related assets, MES entered into various service agreements with Talen's pursuant to which we provide certain terminalling and marine services to MES.

Acquisition of Specialty Lubricant Blending and Product Packaging Assets. On October 2, 2012, we acquired from Cross, certain specialty lubricant product blending and packaging assets, including working capital, for total consideration of $121.8 million in cash at closing, plus a final net working capital adjustment of $0.9 million paid in October of 2012.

Other Developments

Amendment No. 2 to Omnibus Agreement. In connection with the purchase of the Blending and Packaging Assets acquired from Cross, on October 2, 2012, we entered into Amendment No. 2 to to our Omnibus Agreement (the “Amendment”) with Martin Resource Management, Martin Midstream GP LLC (the "General Partner"), and Martin Operating Partnership L.P. (the "Operating Partnership"). The Amendment allows us to provide certain products and services to Martin Resource Management under the Omnibus Agreement by amending the definition of the term “Business” to reflect the operation of the blending and packaging assets acquired by the Partnership pursuant to the purchase agreement.

Disposition of Natural Gas Gathering Assets. On June 18, 2012, we and a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”), entered into a definitive agreement under which CenterPoint would acquire our East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas ("Prism Gas"), which include Woodlawn Pipeline Co., Inc ("Woodlawn"), the Darco Gathering System, the Harrison Gathering System, and the East Harrison Pipeline System, and other natural gas gathering and processing assets also owned by us, for cash in a transaction valued at approximately $275.0 million excluding any transaction costs and purchase price adjustments. The asset sale included our 50% operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint owned the other 50% percent interest. On July 31, 2012, we completed the sale of our East Texas and Northwest Louisiana natural gas gathering and processing assets for net cash proceeds of $273.3 million. Additionally, on September 18, 2012, we completed the sale of our interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy, LLC (“PIPE”) to a private investor group for $1.5 million in cash (the assets described above, collectively, are herein referred to as the "Prism Assets"). Prism Gas Systems I, L.P. and all of its subsidiaries were liquidated and dissolved prior to December 31, 2012.

Debt Financing Activities. On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility. On May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million. See subsequent events section in Item 1. "Business" for discussion surrounding our February 2013 issuance of senior unsecured notes.

For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Credit Facility” within this Item.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated and condensed financial statements included elsewhere herein. We prepared these financial statements in conformity with generally accepted accounting principles. The preparation of these financial statements required us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Our results may differ from these estimates. Currently, we believe that our accounting policies do not require us to make estimates using assumptions about matters that are highly uncertain. However, we have described below the critical accounting policies that we believe could impact our consolidated and condensed financial statements most significantly.

You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements contained in this annual report on Form 10-K. Some of the more significant estimates in these financial statements include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units as it relates to our annual goodwill evaluation.

Derivatives

All derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. Our hedging policy allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges or hedges that become ineffective are being marked to market with all market value adjustments being recorded in the consolidated statements of operations.

Product Exchanges

We enter into product exchange agreements with third parties whereby we agree to exchange NGLs and sulfur with third parties. We record the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method. Product exchanges with the same counterparty are entered into in contemplation of one another and are combined. The net amount related to location differentials is reported in “Product sales” or “Cost of products sold” on the Consolidated Statement of Operations.

Revenue Recognition

Revenue for our four operating segments is recognized as follows:

Terminalling and storage - Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through our terminals at the contracted rate.

For our tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

Natural gas services - NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, we recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.

Sulfur services - Revenue from sulfur product sales is recognized when the customer takes title to the product at our plant or the customer facility. Revenues from sulfur services is recognized as deliveries are made during each monthly period.

Marine transportation - Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip.

Equity Method Investments

We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 350-20, related to goodwill, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock. No portion of the net income from these entities is included in our operating income.

We own 100% of the Class A and Class B equity interests in Redbird. Redbird, as of December 31, 2012 and 2011, owned a 41.28% and 40.08% interest in Cardinal, respectively. We own an unconsolidated 50% interest in Caliber Gathering, LLC ("Caliber").

Goodwill

Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. We are required to identify our reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. We are required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, we would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.

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

We have historically performed our annual impairment testing of goodwill and indefinite-lived intangible assets as of September 30 of each year. During the third quarter of fiscal 2011, we changed the annual impairment testing date from September 30 to August 31. We believe this change, which represents a change in the method of applying an accounting principle, is preferable in the circumstances as the earlier date provides additional time prior to our quarter-end to complete the goodwill impairment testing and report the results in our quarterly report on Form 10-Q.

We have performed the annual impairment tests as of August 31, 2012, August 31, 2011, and September 30, 2010, and we have determined fair value in each reporting unit based on the weighted average of three valuation techniques: (i) the discounted cash flow method; (ii) the guideline public company method; and (iii) the guideline transaction method. At August 31, 2012, August 31, 2011, and September 30, 2010, the estimated fair value of each of our four reporting units was in excess of its carrying value, resulting in no impairment.

No triggering events occurred that would cause us to perform an impairment test at either December 31, 2012 or 2011.

be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.

Environmental Liabilities and Litigation

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

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

Allowance for Doubtful Accounts

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

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

Asset Retirement Obligations

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

Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Such costs could differ significantly when they are incurred. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates due to surface repair, and labor and material costs, revisions to estimated inflation rates and changes in the estimated timing of abandonment. For example, we do not have access to natural gas reserve information related to our gathering systems to estimate when abandonment will occur.

Our Relationship with Martin Resource Management

Martin Resource Management directs our business operations through its ownership and control of our general partner and under the Omnibus Agreement. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2012 , 2011 and 2010 , the Conflicts Committee of our general partner approved reimbursement amounts of $7.6 million, $4.8 million and $3.8 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

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

We are both an important supplier to and customer of Martin Resource Management. Among other things, we sell sulfuric acid and provide marine transportation and terminalling and storage services to Martin Resource Management. We purchase land transportation services, underground storage services, sulfuric acid and marine fuel from Martin Resource

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

Results of Operations

The results of operations for the years ended December 31, 2012 , 2011 , and 2010 have been derived from our consolidated financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating revenues and operating income by segment for the years ended December 31, 2012 , 2011 , and 2010 .

The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all periods.



	Operating Revenues		Revenues Intersegment Eliminations			Operating Revenues after Eliminations		Operating Income (loss)			Operating Income Intersegment Eliminations			Operating Income (loss) after Eliminations
	(In thousands)
Year Ended December 31, 2012:
Terminalling and storage	$	322,175	$	(4,652	)	$	317,523	$	27,944		$	(2,541	)	$	25,403
Natural gas services	825,506		—			825,506		13,924			1,471			15,395
Sulfur services	261,584		—			261,584		37,262			4,647			41,909
Marine transportation	88,815		(3,067		)	85,748		6,751			(3,577		)	3,174
Indirect selling, general and administrative	—		—			—		(12,046		)	—			(12,046		)
Total	$	1,498,080	$	(7,719	)	$	1,490,361	$	73,835		$	—		$	73,835

Year Ended December 31, 2011:
Terminalling and storage	$	283,175	$	(4,414	)	$	278,761	$	21,567		$	(948	)	$	20,619
Natural gas services	611,749		—			611,749		6,267			1,220			7,487
Sulfur services	275,044		—			275,044		27,651			6,944			34,595
Marine transportation	83,971		(7,035		)	76,936		731			(7,216		)	(6,485		)
Indirect selling, general and administrative	—		—			—		(8,864		)	—			(8,864		)
Total	$	1,253,939	$	(11,449	)	$	1,242,490	$	47,352		$	—		$	47,352

Year Ended December 31, 2010:
Terminalling and storage	$	199,744	$	(4,354	)	$	195,390	$	21,810		$	(1,776	)	$	20,034
Natural gas services	442,005		—			442,005		6,780			964			7,744
Sulfur services	165,078		—			165,078		15,886			4,280			20,166
Marine transportation	82,635		(4,993		)	77,642		9,992			(3,468		)	6,524
Indirect selling, general and administrative	—		—			—		(6,386		)	—			(6,386		)
Total	$	889,462	$	(9,347	)	$	880,115	$	48,082		$	—		$	48,082

Our results of operations are discussed on a comparative basis below. There are certain items of income and expense which we do not allocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Our total revenues before eliminations were $1,498.1 million for the year ended December 31, 2012 compared to $1,253.9 million for the year ended December 31, 2011 an increase of $244.2 million , or 19% . Our operating income before eliminations was $73.8 million for the year ended December 31, 2012 compared to $47.4 million for the year ended December 31, 2011 an increase of $26.4 million , or 56% .

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

Terminalling and Storage Segment

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



	Years Ended December 31,
	2012			2011
	(In thousands)
Revenues:
Services	$	94,895		$	81,697
Products	227,280			201,478
Total revenues	322,175			283,175

Cost of products sold	202,966			182,928
Operating expenses	63,499			54,992
Selling, general and administrative expenses	4,671			3,343
Depreciation and amortization	22,976			19,814
	28,063			22,098
Other operating loss	(119		)	(531		)
Operating income	$	27,944		$	21,567

Revenues. Our terminalling and storage revenues increased $39.0 million, or 14%, for the year ended December 31, 2012 compared to the year ended December 31, 2011. The increase is comprised of service revenue of $13.2 million and $25.8 million of product revenue. The service revenue increase is due principally to $12.4 million related to two significant projects, one of which commenced operations in 2012. The other project became operational in late 2011. The increase in product revenue is primarily due to $20.0 million in increased revenues associated with the Blending and Packaging Assets acquired from Cross. Higher volumes accounted for $12.5 million of this increase, and higher prices provided the remaining $7.5 million increase. The remaining product sales increase is due primarily to the conversion of a consigned product delivery agreement to a purchase and sale arrangement.

Cost of products sold. Our cost of products increased $20.0 million, or 11%, for the year ended December 31, 2012 compared to the year ended December 31, 2011. This increase consists of $16.7 attributable to the Blending and Packaging Assets. This increase is comprised of $11.3 million due to higher volumes and $5.4 million due to higher costs. The remaining increase is due principally to the conversion of a consigned product delivery agreement to a purchase and sale arrangement.

Operating Expenses . Operating expenses increased $8.5 million, or 15%, for the year ended December 31, 2012 as compared to the year ended December 31, 2011. The increase includes $6.3 million attributable to new projects placed in service in 2012 and 2011. The remainder of the increase consists primarily of higher repair and maintenance costs of $1.4 million and compensation expense of $0.6 million.

Selling, general and administrative expenses. Selling, general, and administrative expenses increased $1.3 million, or 40% for the year ended December 31, 2012 compared to the year ended December 31, 2011. An increase of $1.0 million is due to

increased marketing expenses related to the Blending and Packaging Assets. The remaining $0.3 million is primarily attributable to increased compensation expense.

Depreciation and amortization. Depreciation and amortization increased $3.2 million, or 16%, for the year ended December 31, 2012 compared to the year ended December 31, 2011. The increase is fully attributable to capital expenditures for new projects.

Other operating loss. Other operating loss for the year ended December 31, 2012 and the year ended December 31, 2011 represents losses on the disposal of property, plant and equipment.

In summary, our terminalling and storage operating income increased $6.4 million, or 30%, for the year ended December 31, 2012 compared to the year ended December 31, 2011.

Natural Gas Services Segment

The following table summarizes our results of operations in our natural gas services segment.



	Years Ended December 31,
	2012		2011
	(In thousands)
Revenues	$	825,506	$	611,749
Cost of products sold	803,195		600,034
Operating expenses	3,550		2,994
Selling, general and administrative expenses	4,236		1,876
Depreciation and amortization	601		578
Operating income	$	13,924	$	6,267

NGLs Volumes (Bbls)	12,080		7,866

Revenues. Our natural gas services revenues increased $213.8 million, or 35% for the year ended December 31, 2012, compared to the same period of 2011. This is primarily attributable to increased sale volumes, somewhat offset by decreased sales prices. NGL sales volumes for the year ended December 31, 2012 increased 54% compared to the same period of 2011, resulting in a positive impact on revenues of $288.2 million. Our NGL average sales price per barrel for the year ended December 31, 2012, decreased $9.44, or 12% compared to the same period of 2011, resulting in a decrease in revenue of $76.1 million.

Cost of products sold . Our cost of products sold increased $203.2 million, or 34%, for the year ended December 31, 2012, compared to the same period of 2011. The percentage increase in NGL cost of products sold was slightly lower than our percentage increase in NGL revenues, resulting in increased margins per barrel of 24% for the year ended December 31, 2012, compared to the same period of 2011.

Operating expenses . Operating expenses increased $0.6 million, or 19%, for the year ended December 31, 2012 compared to the same period of 2011. This is primarily due to increased pipeline maintenance expenses of $0.2 million and increased compensation expense of $0.2 million.

Selling, general and administrative expenses . Selling, general and administrative expenses increased $2.4 million, or 126%, for the year ended December 31, 2012, as compared to the same period of 2011. This is primarily due to increased compensation expense of $1.4 million and an increase in bad debt expense of $0.7 million.

Depreciation and amortization . Depreciation and amortization remained consistent for the year ended December 31, 2012, as compared to the same period of 2011.

In summary, our natural gas services operating income increased $7.7 million, or 122%, for the year ended December 31, 2012, compared to the same period of 2011.

Sulfur Services Segment

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



	Years Ended December 31,
	2012			2011
	(In thousands)
Revenues:
Services	$	11,702		$	11,400
Products	249,882			263,644
Total revenues	261,584			275,044

Cost of products sold	195,314			220,059
Operating expenses	17,404			19,328
Selling, general and administrative expenses	3,975			3,361
Depreciation and amortization	7,371			6,725
	37,520			25,571
Other operating income (loss)	(258		)	2,080
Operating income	$	37,262		$	27,651

Sulfur (long tons)	1,066.1			1,314.5
Fertilizer (long tons)	306.1			271.8
Sulfur services volumes (long tons)	1,372.2			1,586.3

Revenues. Our total sulfur services revenues decreased $13.5 million, or 5%, for the year ended December 31, 2012, compared to the year ended December 31, 2011. Product revenue decreased $13.8 million, or 5%, for the year ended December 31, 2012, compared to the year ended December 31, 2011. A revenue decrease of $35.6 million was the result of a 13% reduction in volumes, offset partially by $21.8 of increased revenue generated by a 10% increase in price. The volume reduction was primarily related to the conversion of a buy/sell contract with a major customer to a fee-based handling contract. Service revenues remained basically the same for both years.

Cost of products sold. Our cost of products sold decreased $24.7 million, or 11%, for the year ended December 31, 2012, compared to the year ended December 31, 2011. The percentage decrease in cost of products sold was higher than our percentage decrease in revenues, resulting in an increase in our margin per ton of 39%.

Operating expenses. Our operating expenses decreased $1.9 million, or 10%, for the year ended December 31, 2012, compared to the year ended December 31, 2011. This was primarily a result of decreased outside towing expenses of $1.8 million and $0.4 million in workers compensation claims. Offsetting that decrease is an increase of $0.3 million in marine fuel expense.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.6 million, or 18%, for the year ended December 31, 2012, compared to the year ended December 31, 2011. This increase is related to an increase of $0.3 million in allocated overhead expense and $0.3 million in compensation expense.

Depreciation and amortization. Depreciation and amortization expense increased $0.6 million, or 10%, for the year ended December 31, 2012, compared to the year ended December 31, 2011. This increase is a result of capital expenditures made during the past twelve months.

Other operating income (loss). Other operating income (loss) was ($0.3) million for the year ended December 31, 2012, compared to $2.1 million for the year ended December 31, 2011. The change is due primarily to a $1.4 million gain on termination of a rail services agreement and $0.7 million business interruption recovery, both of which occurred in 2011.

In summary, our sulfur operating income increased $9.6 million, or 35%, for the year ended December 31, 2012, compared to the year ended December 31, 2011.

Marine Transportation Segment

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



	Years Ended December 31,
	2012			2011
	(In thousands)
Revenues	$	88,815		$	83,971
Operating expenses	70,342			66,771
Selling, general and administrative expenses	566			3,087
Depreciation and amortization	11,115			13,159
	6,792			954
Other operating (loss)	(41		)	(223		)
Operating income	$	6,751		$	731

Revenues . Our marine transportation revenues increased $4.8 million, or 6%, for the year ended December 31, 2012, compared to the same period of 2011. This increase was primarily a result of an increase in our offshore marine operations somewhat offset by a decrease in our inland marine operations. Offshore revenues increased $5.5 million due to increased demand for our two offshore tows, which operate in the spot market. Revenue from inland operations decreased $2.8 million due to a reduction in utilization. Ancillary revenue, primarily fuel, increased $2.2 million.

Operating expenses . Operating expenses increased $3.6 million, or 5%, for the year ended December 31, 2012, compared to the same period of 2011. This increase in operating expenses is due to increased fuel costs of $2.4 million, compensation expense of $1.3 million, repair and maintenance expense of $0.9 million, and a write-off of supplies inventory of $1.2 million. Offsetting these increases are decreases in outside towing of $1.3 million and barge lease expense of $1.0 million.

Selling, general and administrative expenses . Selling, general and administrative expenses decreased $2.5 million, or 82%, for the year ended December 31, 2012, compared to the same period of 2011. This reduction was attributable to the collection of a previously reserved customer receivable of $2.1 million and a $0.4 million decrease in bad debt expense in 2012.

Depreciation and amortization . Depreciation and amortization decreased $2.0 million, or 16%, for the year ended December 31, 2012, compared to the same period of 2011. This decrease was primarily a result of certain assets becoming fully depreciated and a reduction in depreciation from disposal of equipment made in 2012. These reductions are somewhat offset by capital expenditures made in 2012.

Other operating income . Other operating income for the years ended December 31, 2012 and 2011 represents losses on asset dispositions.

In summary, our marine transportation operating income increased $6.0 million for the year ended December 31, 2012 compared to the same period of 2011.

Equity in Earnings of Unconsolidated Entities

Equity in losses from unconsolidated entities was ($1.1) million for the year ended December 31, 2012, compared to ($4.8) million for the year ended December 31, 2011. This $3.7 million decrease in equity in loss is partially attributable to a $2.2 million milestone payment in 2012, while no milestone payment was received in 2011. The positive milestone impact is offset somewhat by ($0.2) million in loss associated with investments entered into during 2012. The remaining $1.7 million decrease in equity in loss is due to the improved operating results of Cardinal in 2012.

Interest Expense

Our interest expense for all operations was $30.1 million for the year ended December 31, 2012 compared to $26.8 million for the same period of 2011, an increase of $3.3 million, or 15%. This increase over 2011 was primarily due to fees received related to the termination of all our interest rate swaps of $2.8 million, reducing interest expense, during third quarter 2011 and decreases in interest expense related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps.

Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses were $12.0 million for the year ended December 31, 2012 compared to $8.9 million for 2011, an increase of $3.1 million or 35%.

Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation for these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Our total revenues before eliminations were $1,253.9 million for the year ended December 31, 2011 compared to $889.5 million for the year ended December 31, 2010 , an increase of $364.4 million , or 41% . Our operating income before eliminations was $47.4 million for the year ended December 31, 2011 compared to $48.1 million for the year ended December 31, 2010 , a decrease of $0.7 million , or 2% .

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

Terminalling and Storage Segment

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



	Years Ended December 31,
	2011			2010
	(In thousands)
Revenues:
Services	$	81,697		$	71,471
Products	201,478			128,273
Total revenues	283,175			199,744

Cost of products sold	182,928			115,308
Operating expenses	54,992			43,360
Selling, general and administrative expenses	3,343			2,180
Depreciation and amortization	19,814			17,330
	22,098			21,566
Other operating income (loss)	(531		)	244
Operating income	$	21,567		$	21,810

Revenues. Our terminalling and storage revenues increased $83.4 million, or 42%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. Of the increase in total revenues, $10.2 million is attributable to services revenue and $73.2 million pertains to product revenues. The increase in services revenue of $10.2 million is primarily related to the

acquisition of certain terminalling assets from Martin Resource Management in February 2011. Product revenue increased $73.2 million compared to the prior year. An increase of $46.3 million is related to product revenues associated with historical operations of the Blending and Packaging Assets. Packaging operations saw an increase in sales volumes of 16%, resulting in an impact on revenues of $33.3 million and an increase in sales prices of 34%, resulting in an impact on revenues of $13.0 million. Of the remaining $26.9 million increase, this is primarily due to the conversion of consigned product delivery agreements with two of our customers to buy/sell product delivery agreements of $22.8 million. The remaining $4.1 million of the increase was due to increases in average selling prices at our Mega Lubricants facility.

Cost of products sold . Our cost of products sold increased $67.6 million, or 59% for the year ended December 31, 2011 compared to the year ended December 31, 2010. Of this increase, $41.5 million relates to the historical operations of the Blending and Packaging Assets. Packaging operations saw an increase in volumes of 16%, resulting in an impact on cost of products sold of $30.3 million and an increase in prices of 37%, resulting in an impact on cost of products sold of $11.2 million. Of the remaining $26.1 million increase, $20.6 million is due to the conversion of consigned product delivery agreements with two of our customers. The remaining increase was due to a $3.9 million increase in our average purchase price of products at our Mega Lubricants facility and $1.5 million of additional marine freight related to the acquisition of certain terminalling assets from Martin Resource Management in February 2011.

Operating expenses. Operating expenses increased $11.6 million, or 27%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. Of this increase, $1.4 million is related to the historical operations of the Blending and Packaging Assets. Of this $1.4 million increase, $0.9 is related to increased manufacturing expenses and $0.5 million relates to increased product development expenses. Of the remaining $10.2 million increase, $5.1 million was due primarily to operating expenses associated with the acquisition of certain terminalling assets from Martin Resource Management in February 2011. Additionally, operating expenses associated with our Blending and Packaging Assets increased $1.6 million, primarily due to $0.7 million related to labor and burden, $0.4 million related to repairs and maintenance, and $0.3 million associated with increased materials and supply expense. The remaining balance of $3.5 million pertains to increases in various areas of operations including $0.9 million related to a new pipeline lease in November 2011 and increases in operating expenses at our specialty terminals of $2.1, of which $0.4 million was for the deductible accrued for expenses associated with the Stanolind tank fire on September 11, 2011.

Selling, general and administrative expenses . Selling, general and administrative expenses increased $1.2 million, or 53%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This is primarily due to increased marketing expenses related to historical operations of the Blending and Packaging Assets.

Depreciation and amortization . Depreciation and amortization increased $2.5 million, or 14%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. Of the increase $1.5 million relates to additional depreciation expense associated with the acquisition of certain terminalling assets from Martin Resource Management in February 2011. Additionally, $0.2 million is related to capital expenditures associated with the historical operations of the Blending and Packaging Assets. The balance of the increase was a result of capital expenditures made in the past 12 months.

Other operating income (loss). Other operating loss for the year ended December 31, 2011 primarily consists of a loss of $0.7 million on the disposition of certain property, plant and equipment at our terminal located in Corpus Christi, Texas. The disposition was executed to facilitate the construction of a new crude terminal adjacent to our existing facility. The loss was partially offset by business interruption insurance recoveries of $0.1 million received.

In summary, terminalling and storage operating income decreased $0.2 million, or 1%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.

Natural Gas Services Segment

The following table summarizes our results of operations in our natural gas services segment.



	Years Ended December 31,
	2011		2010
	(In thousands)
Revenues	$	611,749	$	442,005
Cost of products sold	600,034		428,843
Operating expenses	2,994		3,210
Selling, general and administrative expenses	1,876		2,581
Depreciation and amortization	578		571
	6,267		6,800
Other operating loss	—		(20		)
Operating income	$	6,267	$	6,780

NGLs Volumes (Bbls)	7,866		6,997

Revenues. Our natural gas services revenues increased $169.7 million, or 38%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. During 2011, our NGL average sales price per barrel increased $14.60, or 23%, compared to the same period in 2010. NGL sales volumes increased 12% compared to the same period of 2010.

Costs of product sold . Our cost of products increased $171.2 million, or 40%, for the year ended December 31, 2011 compared to the same period in 2010. The increase in NGL revenues was slightly lower than our increase in NGL cost of products sold as our NGL margins fell $0.39 per barrel, or 21%.

Operating expenses . Operating expenses decreased $0.2 million, or 7% for the year ended December 31, 2011 compared to the same period of 2010 primarily as a result of decreased pipeline maintenance expenses.

Selling, general and administrative expenses . Selling, general and administrative expenses decreased $0.7 million, or 27%, for the year ended December 31, 2011 compared to the same period of 2010. This decrease was primarily a result of the write-off of an uncollectible customer receivable of $0.7 million.

Depreciation and amortization . Depreciation and amortization remained consistent for the year ended December 31, 2011 compared to the same period of 2010.

In summary, our natural gas services operating income decreased $0.5 million, or 8%, for the year ended December 31, 2011, compared to the year ended December 31, 2010.

Sulfur Services Segment

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



	Years Ended December 31,
	2011		2010
	(In thousands)
Revenues:
Services	$	11,400	$	—
Products	263,644		165,078
Total revenues	275,044		165,078

Cost of products sold	220,059		122,483
Operating expenses	19,328		17,013
Selling, general and administrative expenses	3,361		3,422
Depreciation and amortization	6,725		6,262
	25,571		15,898
Other operating income (loss)	2,080		(12		)
Operating income	$	27,651	$	15,886

Sulfur (long tons)	1,314.5		1,129.2
Fertilizer (long tons)	271.8		274.9
Sulfur services volumes (long tons)	1,586.3		1,404.1

Revenues. Our sulfur services revenues increased $110.0 million, or 67%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase was a result of higher market prices in 2011 compared to 2010. The services revenue relates to a new contract that began on January 1, 2011.

Cost of products sold. Our cost of products sold increased $97.6 million, or 80%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase was directly related to the increased price of our raw materials in 2011 compared to 2010. Our overall gross margin per ton increased to $34.66 in 2011 from $30.34 in 2010.

Operating expenses. Our operating expenses increased $2.3 million, or 14%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase consists of marine fuel expense increasing $0.8 million, workers compensation claims of $0.8 million, outside towing of $0.4 million, and property taxes of $0.2 million.

Selling, general, and administrative expenses. Our selling, general, and administrative expenses remained flat for the year ended December 31, 2011, compared to the year ended December 31, 2010.

Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 6%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase was primarily a result of normal capital expenditure activity during the current year.

Other operating income. Other operating income increased $2.1 million for the year ended December 31, 2011 consisting of $1.4 million received for the termination of a rail services agreement and $0.7 million for business interruption insurance recoveries from Hurricane Ike.

In summary, our sulfur services operating income increased $11.8 million, or 74%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.

Marine Transportation Segment

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



	Years Ended December 31,
	2011			2010
	(In thousands)
Revenues	$	83,971		$	82,635
Operating expenses	66,771			57,642
Selling, general and administrative expenses	3,087			2,296
Depreciation and amortization	13,159			12,721
	954			9,976
Other operating income (loss)	(223		)	16
Operating income	$	731		$	9,992

Revenues . Our marine transportation revenues increased $1.3 million, or 2%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase was primarily a result of an increase in our inland marine operations, offset by a decrease in our offshore marine operations. Our inland marine operations increased $7.2 million, of which $2.8 million is attributed to increased utilization of the inland fleet through the utilization of new leased equipment and increases in contract rates. The remaining $4.4 million is due to an increase in ancillary charges. Our offshore revenues decreased $6.3 million primarily due to decreased utilization of the offshore fleet in 2011 of $8.1 million due to various dry dockings and reduced demand for our two offshore tows which operate in the spot market, offset by an increase in ancillary charges of $1.8 million.

Operating expenses . Operating expenses increased $9.1 million, or 16%, for the year ended December 31, 2011 compared to the year ended December 31, 2010, primarily as a result of increased fuel expense of $4.4 million, outside towing expense of $1.7 million, increased repairs and maintenance expense of $1.7 million, operating supplies of $1.0 million, and increased wages and burden costs of $1.7 million. Offsetting these increases was a decrease in barge lease expense of $2.0 million.

Selling, general and administrative expenses . Selling, general and administrative expenses increased $0.8 million, or 34%, for the year ended December 31, 2011 compared to the year ended December 31, 2010, primarily due to the reserve of an uncollectible customer receivable of $0.7 million.

Depreciation and amortization . Depreciation and amortization increased $0.4 million, or 3%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase was primarily a result of capital expenditures made in the last twelve months.

Other operating income. Other operating income for the year ended December 31, 2011 and the year ended December 31, 2010 consisted of gains and losses on the disposal of assets.

In summary, our marine transportation operating income decreased $9.3 million, or 93%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.

Equity in Earnings of Unconsolidated Entities

For the years ended December 31, 2011 and 2010, equity in earnings (loss) of unconsolidated entities relates to our unconsolidated interests in Cardinal.

Equity in earnings (loss) of unconsolidated entities was ($4.8) million for the year ended December 31, 2011, compared to $2.5 million for the year ended December 31, 2010, a decrease of $7.3 million. This decrease is primarily a result of milestone payments received in the amount of $6.6 million during 2010. There were no milestone payments received during 2011. The remaining decrease of $0.7 million is related to changes in the Partnership’s share of earnings in Cardinal.

Gain from change in ownership of unconsolidated entities was $0 for the year ended December 31, 2011, compared to $6.4 million for the year ended December 31, 2010. This change is a result of our share of Redbird’s interest in Cardinal decreasing during 2010 as a result of disproportionate contributions during 2010.

Interest Expense

Our interest expense for all operations was $26.8 million for 2011 compared to $35.3 million for 2010, a decrease of $8.5 million, or 24%. This decrease was primarily due to the termination of all our interest rate swaps at a cost of $3.8 million during

the first quarter 2010, the termination of all our interest rate swaps at a benefit of $2.8 million during the third quarter 2011, and decreases in interest expense related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps, offset by increases due to the issuance of our senior notes at the end of the first quarter 2010. Additionally, offsetting the overall decrease was an increase in interest expense of $0.7 million attributable to the historical operations of the Blending and Packaging Assets.

Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses were $8.9 million for 2011 compared to $6.4 million for 2010, an increase of $2.5 million or 39%.

Liquidity and Capital Resources

General

Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private. During 2012 and 2011, we completed several transactions that have improved our liquidity position, helping fund our acquisitions and organic growth projects. In July 2012, we completed the sale of certain gas gathering and processing assets for approximately $273.3 million. We received $102.8 and $91.4 from follow on public offerings of common units in November and January 2012, respectively. In February 2011, we received net proceeds of $70.3 million from a public offering of common units. Additionally, we made certain strategic amendments to our credit facility which provides for a maximum borrowing capacity of $400.0 million under our revolving credit facility.

As a result of these financing activities, discussed in further detail below, management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances and our current borrowing capacity under the expanded revolving credit facility. However, it may be necessary to raise additional funds to finance our future capital requirements.

Our ability to satisfy our working capital requirements, to fund planned capital expenditures, and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors - Risks related to Our Business” for a discussion of such risks.

Debt Financing Activities

On February 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.25% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $245.1 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership's revolving credit facility.

On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility.

On May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million.

Equity Offerings

On November 26, 2012, we completed a public offering of 3,450,000 common units at a price of $31.16 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $102.8 million. Our general partner contributed $2.2 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce our outstanding indebtedness.

On January 25, 2012, we completed a public offering of 2,645,000 common units at a price of $36.15 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91.4 million. Our general partner contributed $2.0 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce our outstanding indebtedness.

On February 9, 2011, we completed a public offering of 1,874,500 common units at a price of $39.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70.3 million. Our general partner contributed $1.5 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. On February 9, 2011, we made a $65.0 million payment to reduce the outstanding balance under our revolving credit facility.

Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2013.

Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors - Risks Relating to Our Business” for a discussion of such risks.

Cash Flows and Capital Expenditures

In 2012, cash increased $4.9 million as a result of $32.6 million provided by operating activities ($34.0 million provided by continuing operating activities and $1.4 million used in discontinued operating activities), $15.0 million used in investing activities ($286.6 million used in continuing investing activities and $271.6 million provided by discontinued investing activities), and $12.7 million used in financing activities. Working capital negatively affected cash provided by operating activities in 2012 principally due to the increase in accounts and other receivables from higher revenues in our natural gas services segment. In 2011, cash decreased $11.1 million as a result of $91.4 million provided by operating activities ($77.3 million provided by continuing operating activities and $14.1 million provided by discontinued operating activities), $202.7 million used in investing activities ($188.8 million used in continuing investing activities and $13.9 million used in discontinued investing activities), and $100.2 million provided by financing activities. Working capital positively affected cash provided by operating activities in 2011 due to increases in accounts and other receivables, product exchange receivables and inventories caused by price increases principally in our natural gas services and sulfur services segments being funded through larger increases in trade and other accounts payable, product exchange payables and due to affiliates. In 2010, cash increased $5.4 million as a result of $39.1 million provided by operating activities ($29.0 million provided by continuing operating activities and $10.1 million provided by discontinued operating activities), $91.0 million used in investing activities ($47.6 million used in continuing investing activities and $43.4 million used in discontinued investing activities), and $57.3 million provided by financing activities. Working capital negatively affected cash provided by operating activities in 2010 principally due to increases in accounts and other receivables, product exchange receivables and inventories caused by higher prices in our natural gas services and sulfur services segments which exceeded the increase in trade and other accounts payable and product exchange payables.

For 2012, our cash used in continuing investing activities of $286.6 million consisted primarily of capital expenditures, acquisitions, investments in and contributions to unconsolidated entities. For 2012, cash provided by discontinued investing activities of $271.6 million consisted primarily of the disposal of assets, capital expenditures, and investments in and returns of investments from unconsolidated entities. For 2011, our cash used in continuing investing activities of $188.8 million consisted primarily of capital expenditures, acquisitions, and investments in and contributions to unconsolidated entities. For 2011, our cash used in discontinued investing activities of $13.9 million consisted primarily of capital expenditures, and investments in and returns of investments from unconsolidated entities. For 2010, our cash used in continuing investing activities of $47.6 million consisted primarily of capital expenditures, acquisitions, and contributions to unconsolidated entities. For 2010, our cash used in discontinued investing activities of $43.4 million consisted primarily of capital expenditures, acquisitions, and investments in and returns of investments from unconsolidated entities.

For 2012, 2011 and 2010 our capital expenditures for property and equipment and plant turnaround costs related to continuing activities were $95.7 million, $79.3 million, and $19.2 million, respectively. For 2012, 2011 and 2010 our capital expenditures for property and equipment related to discontinued activities were $1.1 million, $1.3 million, and $1.4 million, respectively.

As to each period:

•

In 2012, we spent $85.0 million for expansion capital expenditures and $8.6 million for maintenance capital expenditures (including $5.0 million for maintenance in the fourth quarter of 2012), and $2.1 million for plant turnaround costs related to continuing operations. Our expansion capital expenditures were made in connection with marine vessel conversions and construction projects associated with our terminalling and storage and sulfur services businesses. Our maintenance capital expenditures were primarily made in our terminalling and storage, marine and sulfur services divisions for routine operating equipment improvements. In 2012, we spent $0.6 million for expansion and $0.5 million for maintenance capital expenditures (no maintenance capital expenditures were made in the fourth quarter of 2012) related to discontinued operations.

•

In 2011, we spent $67.4 million for expansion capital expenditures and $9.8 million for maintenance capital expenditures (including $0.3 million for maintenance in the fourth quarter of 2011), and $2.1 million for plant turnaround costs related to continuing operations. Our expansion capital expenditures were made in connection with marine vessel conversions and construction projects associated with our terminalling and storage and sulfur services businesses. Our maintenance capital expenditures were primarily made in our marine and sulfur services divisions for routine operating equipment improvements. In 2011, we spent $0.2 million for expansion and $1.1 million for maintenance capital expenditures (including $0.5 million for maintenance in the fourth quarter of 2011) related to discontinued operations.

•

In 2010, we spent $14.1 million for expansion capital expenditures and $4.1 million for maintenance (including $0.9 million for maintenance in the fourth quarter of 2010), and $1.1 million for plant turnaround costs related to continuing operations. Our expansion capital expenditures were made in connection with marine vessel conversions and construction projects associated with our terminalling and storage and sulfur services businesses. Our maintenance capital expenditures were primarily made in our terminalling and storage and sulfur services divisions for routine operating equipment improvements. In 2010, we spent $0.8 million for expansion and $0.6 million for maintenance capital expenditures (including $0.3 million for maintenance in the fourth quarter of 2010) related to discontinued operations.

In 2012, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of $706.0 million and borrowings of long-term debt under our credit facilities of $727.0 million, cash distributions paid to common and subordinated unitholders of $76.5 million, payments of notes payable and capital lease obligations of $6.6 million, purchase of treasury units of $0.2 million, funding from affiliate for investments in Cardinal of $2.2 million and payments of debt issuance costs of $0.2 million. Additional financing activities consisted of contributions of $4.2 million from our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $194.2 million, excess purchase price over carrying value of acquired assets of $142.1 million, and excess carrying value of assets over the purchase price paid by Martin Resource Management of $4.3 million.

In 2011, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of $442.0 million and borrowings of long-term debt under our credit facilities of $529.0 million, cash distributions paid to common and subordinated unitholders of $64.5 million, payments of notes payable and capital lease obligations of $1.1 million, purchase of treasury units of $0.5 million, funding from affiliate for investments in Cardinal of $30.8 million and

payments of debt issuance costs of $3.6 million. Additional financing activities consisted of contributions of $1.5 million from our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $70.3 million and excess purchase price over carrying value of acquired assets of $19.7 million.

In 2010, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of $441.9 million and borrowings of long-term debt under our credit facilities of $503.9 million, cash distributions paid to common and subordinated unitholders of $56.7 million, payments of notes payable and capital lease obligations of $0.1 million, purchase of treasury units of $0.1 million, funding from affiliate for investments in Cardinal of $12.6 million and payments of debt issuance costs of $7.4 million. Additional financing activities consisted of contributions of $1.1 million from our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $78.6 million, redemption of common units of $28.1 million and excess purchase price over carrying value of acquired assets of $4.6 million.

Capital Resources

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

As of December 31, 2012, we had $478.2 million of outstanding indebtedness, consisting of outstanding borrowings of $173.4 million (net of unamortized discount) under our Senior Notes, $296.0 million under our revolving credit facility, $3.0 million under a note payable, and $5.8 million under capital lease obligations.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2012, is as follows (dollars in thousands):



	Payments due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Revolving credit facility	$	296,000	$	—	$	—	$	296,000	$	—
Senior unsecured notes	173,388		—		—		—		173,388
Note payable	2,971		2,971		—		—		—
Capital leases including current maturities	5,839		235		651		4,953		—
Non-competition agreements	100		50		50		—		—
Throughput commitment	49,151		4,796		10,059		10,716		23,580
Operating leases	58,215		12,781		31,818		8,054		5,562
Interest expense: ¹
Revolving credit facility	27,442		8,347		16,694		2,401		—
Senior unsecured notes	82,832		15,531		31,062		31,062		5,177
Note payable	71		71		—		—		—
Capital leases	3,112		912		1,688		512		—
Total contractual cash obligations	$	699,121	$	45,694	$	92,022	$	353,698	$	207,707

¹Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.

Letter of Credit . At December 31, 2012, we had outstanding irrevocable letters of credit in the amount of $0.1 million, which were issued under our revolving credit facility.

Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.

Description of Our Long-Term Debt

Senior Notes

We and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of us (collectively, the “Issuers”), entered into (i) a Purchase Agreement, dated as of March 23, 2010 (the “Purchase Agreement”), by and among the Issuers, certain subsidiary guarantors (the “Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets Corporation and UBS Securities, LLC, as representatives of a group of initial purchasers (collectively, the “Initial Purchasers”), (ii) an Indenture, dated as of March 26, 2010 (the “Indenture”), among the Issuers, the Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”) and (iii) a Registration Rights Agreement, dated as of March 26, 2010 (the “Registration Rights Agreement”), among the Issuers, the Guarantors and the Initial Purchasers, in connection with a private placement to eligible purchasers of $200 million in aggregate principal amount of the Issuers’ 8.875% senior unsecured notes due 2018 (the “Senior Notes”). We completed the aforementioned Senior Notes offering on March 26, 2010 and received proceeds of approximately $197.2 million, after deducting initial purchaser discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility.

Indenture

Interest and Maturity. On March 26, 2010, the Issuers issued the Senior Notes pursuant to the Indenture in a transaction exempt from registration requirements under the Securities Act. The Senior Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S under the Securities Act. The Senior Notes will mature on April 1, 2018. The interest payment dates are April 1 and October 1.

Optional Redemption . Prior to April 1, 2013, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the Senior Notes issued under the Indenture at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the Senior Notes with the proceeds of certain equity offerings. Prior to April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on April 1, 2014, 102.219% for the 12-month period beginning on April 1, 2015 and 100.00% for the 12-month period beginning on April 1, 2016, and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Senior Notes.

On April 24, 2012 we notified the Trustee of our intention to exercise a partial redemption of the our Senior Notes pursuant to the Indenture. On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility.

Certain Covenants . The Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in its subsidiaries; (ii) pay distributions on, redeem or repurchase its units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate.

denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a continuing Event of Default, the Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding Senior Notes, by notice to the Issuers and the Trustee, may declare the Senior Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the Senior Notes to become due and payable.

Registration Rights Agreement. Under the Registration Rights Agreement, the Issuers and the Guarantors filed with the SEC a registration statement to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. We exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018.

Credit Facility

On November 10, 2005, we entered into a $225.0 million multi-bank credit facility, which has subsequently been amended, including most recently on May 10, 2012 (the "Credit Facility"), when we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million.

As of December 31, 2012, we had approximately $296.0 million outstanding under the revolving credit facility and $0.1 million of letters of credit issued, leaving approximately $103.9 million available under our credit facility for future revolving credit borrowings and letters of credit.

The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. During the current fiscal year, draws on our credit facility have ranged from a low of $35.0 million to a high of $361.0 million.

The credit facility is guaranteed by substantially all of our subsidiaries. Obligations under the credit facility are secured by first priority liens on substantially all of our assets and those of the guarantors, including, without limitation, inventory, accounts receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our subsidiaries and certain of our equity method investees.

We may prepay all amounts outstanding under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, equity issuances and debt incurrences. We used the proceeds from our disposition of the Prism Assets to pay down outstanding indebtedness.

Indebtedness under the credit facility bears interest, at our option, at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee on all letters of credit issued under the credit facility, and we pay a commitment fee which ranges from 0.375% to 0.50% per annum on the unused revolving credit availability under the credit facility. The letter of credit fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the new credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:



Leverage Ratio	Base Rate Loans		Eurodollar Rate Loans		Letters of Credit
Less than 2.25 to 1.00	1.00	%	2.00	%	2.00	%
Greater than or equal to 2.25 to 1.00 and less than 3.00 to 1.00	1.25	%	2.25	%	2.25	%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00	1.50	%	2.50	%	2.50	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00	1.75	%	2.75	%	2.75	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00	2.00	%	3.00	%	3.00	%
Greater than or equal to 4.50 to 1.00	2.25	%	3.25	%	3.25	%

The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%. The applicable margin for existing LIBOR borrowings is 3.00%. Effective January 1, 2013, the applicable margin for existing LIBOR borrowings decreased to 2.25%. Effective April 1, 2013, the applicable margin for existing LIBOR borrowings will increase to 2.75%.

The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio is 5.00 to 1.00. The maximum permitted senior leverage ratio (as defined in the new credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.25 to 1.00. The minimum consolidated interest coverage ratio (as defined in the new credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.75 to 1.00.

In addition, the credit facility contains various covenants that, among other restrictions, limit our and our subsidiaries’ ability to:


•	grant or assume liens;


•	make investments (including investments in our joint ventures) and acquisitions;


•	enter into certain types of hedging agreements;


•	incur or assume indebtedness;


•	sell, transfer, assign or convey assets;


•	repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us to make quarterly distributions to unitholders so long as no default or event of default exists under the credit facility;


•	change the nature of our business;


•	engage in transactions with affiliates;


•	enter into certain burdensome agreements;


•	make certain amendments to the Omnibus Agreement and our material agreements;


•	make capital expenditures; and


•	permit our joint ventures to incur indebtedness or grant certain liens.

Each of the following will be an event of default under the credit facility:


•	failure to pay any principal, interest, fees, expenses or other amounts when due;


•	failure to meet the quarterly financial covenants;


•	failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan document, subject to cure periods for certain failures;


•	the failure of any representation or warranty to be materially true and correct when made;


•	our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount;


•	bankruptcy or other insolvency events involving us or any of our subsidiaries;


•	judgments against us or any of our subsidiaries, in excess of a threshold amount;


•	certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount;


•	a change in control (as defined in the credit facility);


•	the termination of any material agreement or certain other events with respect to material agreements;


•	the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral; and


•	any of our joint ventures incurs debt or liens in excess of a threshold amount.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, or if Ruben Martin is not the chief executive officer of our general partner and a successor acceptable to the administrative agent and lenders providing more than 50% of the commitments under our credit facility is not appointed, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, either a bankruptcy event with respect to Martin Resource Management or a judgment with respect to Martin Resource Management could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us.

If an event of default relating to bankruptcy or other insolvency events occurs with respect to us or any of our subsidiaries, all indebtedness under our credit facility will immediately become due and payable. If any other event of default exists under our credit facility, the lenders may terminate their commitments to lend us money, accelerate the maturity of the indebtedness outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral. Any event of default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations as well as our ability to make distributions to unitholders.

If any default occurs under our credit facility, or if we are unable to make any of the representations and warranties in the credit facility, we will be unable to borrow funds or have letters of credit issued under our credit facility.

As of March 4, 2013, our outstanding indebtedness includes $72.0 million under our credit facility.

We are subject to interest rate risk on our credit facility and may enter into interest rate swaps to reduce this risk.

Effective September 2010, we entered into an interest rate swap that swapped $40.0 million of fixed rate to floating rate. The floating rate cost is the applicable three-month LIBOR rate. This interest rate swap was not accounted for using hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.

Effective September 2010, we entered into an interest rate swap that swapped $60.0 million of fixed rate to floating rate. The floating rate cost is the applicable three-month LIBOR rate. This interest rate swap was not accounted for using hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.

Subsequent Event - Senior Unsecured Notes Issuance

Seasonality

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

Impact of Inflation

Inflation did not have a material impact on our results of operations in 2012, 2011 or 2010. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2012, 2011 or 2010.



Item 7A.	Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 3.58% as of December 31, 2012. As of March 4, 2013, we had total indebtedness outstanding under our credit facility of $72.0 million, all of which was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on December 31, 2012, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $0.7 million annually.

We are not exposed to changes in interest rates with respect to our Senior Notes as these obligations are fixed rate. The estimated fair value of the Senior Notes was approximately $187.1 million as of December 31, 2012, based on market prices of similar debt at December 31, 2012. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately an $6.2 million decrease in fair value of our long-term debt at December 31, 2012.



Item 8.	Financial Statements and Supplementary Data

The following financial statements of Martin Midstream Partners L.P. (Partnership) are listed below:



	Page
Report of Independent Registered Public Accounting Firm	73
Report of Independent Registered Public Accounting Firm on Internal Controls	74
Consolidated Balance Sheets as of December 31, 2012 and 2011	75
Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010	76
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	79
Consolidated Statements of Changes in Capital for the years ended December 31, 2012, 2011 and 2010	80
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	81
Notes to Consolidated Financial Statements	82

Report of Independent Registered Public Accounting Firm

The Board of Directors

Martin Midstream GP LLC:

We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for each of the years in the three-year period ended December 31, 2012. These financial statements are the responsibility of Martin Midstream’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (U.S.). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2012 and 2011 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (U.S.), Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 4, 2013 expressed an unqualified opinion on the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

March 4, 2013

Report of Independent Registered Public Accounting Firm on Internal Controls

The Board of Directors

Martin Midstream GP LLC:

We have audited Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Martin Midstream’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A(b). Our responsibility is to express an opinion on Martin Midstream’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (U.S.). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (U.S.), the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 4, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

March 4, 2013

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	December 31, 2012
	2012			2011 ¹
Assets
Cash	$	5,162		$	266
Accounts and other receivables, less allowance for doubtful accounts of $2,805 and $3,384, respectively	190,652			143,036
Product exchange receivables	3,416			17,646
Inventories	95,987			93,254
Due from affiliates	13,343			5,968
Fair value of derivatives	—			622
Other current assets	2,777			4,366
Assets held for sale	3,578			212,787
Total current assets	314,915			477,945

Property, plant and equipment, at cost	767,344			651,460
Accumulated depreciation	(256,963		)	(218,202		)
Property, plant and equipment, net	510,381			433,258

Goodwill	19,616			8,337
Investment in unconsolidated entities	154,309			132,605
Debt issuance costs, net	10,244			13,330
Other assets, net	3,531			3,633
	$	1,012,996		$	1,069,108
Liabilities and Partners’ Capital
Current portion of long-term debt and capital lease obligations	$	3,206		$	1,261
Trade and other accounts payable	140,045			136,124
Product exchange payables	12,187			37,313
Due to affiliates	3,316			74,654
Income taxes payable	10,239			926
Fair value of derivatives	—			362
Other accrued liabilities	9,489			11,054
Liabilities held for sale	—			501
Total current liabilities	178,482			262,195

Long-term debt and capital leases, less current maturities	474,992			458,941
Deferred income taxes	—			9,697
Other long-term obligations	1,560			1,088
Total liabilities	655,034			731,921

Partners’ capital	357,962			336,561
Accumulated other comprehensive income	—			626
Total partners’ capital	357,962			337,187
Commitments and contingencies
	$	1,012,996		$	1,069,108

¹ Financial information has been revised to include balances attributable to Redbird Class A interests and the Blending and Packaging Assets acquired from Cross. See Note 2(a) – Principles of Presentation and Consolidation.

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)



	Year Ended December 31,
	2012¹			2011¹			2010¹
Revenues:
Terminalling and storage *	$	90,243		$	77,283		$	67,117
Marine transportation *	85,748			76,936			77,642
Sulfur services *	11,702			11,400			—
Product sales: *
Natural gas services	825,506			611,749			442,005
Sulfur services	249,882			263,644			165,078
Terminalling and storage	227,280			201,478			128,273
	1,302,668			1,076,871			735,356
Total revenues	1,490,361			1,242,490			880,115

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	801,724			598,814			427,657
Sulfur services *	194,952			219,697			122,121
Terminalling and storage	200,855			179,461			115,308
	1,197,531			997,972			665,086
Expenses:
Operating expenses *	151,020			137,685			113,426
Selling, general and administrative *	25,494			20,531			16,865
Depreciation and amortization	42,063			40,276			36,884
Total costs and expenses	1,416,108			1,196,464			832,261
Other operating income (loss)	(418		)	1,326			228
Operating income	73,835			47,352			48,082

Other income (expense):
Equity in earnings (loss) of unconsolidated entities	(1,113		)	(4,752		)	2,536
Gain from ownership change in unconsolidated entity	—			—			6,413
Debt prepayment premium	(2,470		)	—			—
Interest expense	(30,665		)	(26,781		)	(35,322		)
Other, net	1,092			420			385
Total other income (expense)	(33,156		)	(31,113		)	(25,988		)
Net income before taxes	40,679			16,239			22,094
Income tax expense	(3,557		)	(2,872		)	(2,622		)
Income from continuing operations	37,122			13,367			19,472
Income from discontinued operations, net of income taxes	64,865			9,392			8,061
Net income	101,987			22,759			27,533
Less general partner's interest in net income	(4,748		)	(5,289		)	(3,869		)
Less pre-acquisition (income) loss allocated to Parent	(4,622		)	1,583			(11,511		)
Less beneficial conversion feature	—			(1,108		)	(1,108		)
Limited partner's interest in net income	$	92,617		$	17,945		$	11,045

¹ Financial information for 2012, 2011 and 2010 has been revised to include results attributable to the Redbird Class A interests and the Blending and Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.

*Related Party Transactions Shown Below

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)

*Related Party Transactions Included Above



	Year Ended December 31,
	2012¹		2011¹		2010¹
Revenues:
Terminalling and storage	$	64,669	$	54,211	$	46,823
Marine transportation	17,494		23,478		28,194
Product Sales	7,201		9,081		7,903
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	27,512		16,749		7,517
Sulfur services	16,968		18,314		16,061
Terminalling and Storage	48,375		45,089		32,489
Expenses:
Operating expenses	58,834		58,051		48,390
Selling, general and administrative	13,678		8,610		7,237

¹ Financial information for 2012, 2011, and 2010 has been revised to include results attributable to the Redbird Class A interests and the Blending and Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)



	Year Ended December 31,
	2012		2011		2010
Allocation of net income attributable to:
Limited partner interest:
Continuing operations	$	30,915	$	11,193	$	4,441
Discontinued operations	61,702		6,752		6,604
	92,617		17,945		11,045
General partner interest:
Continuing operations	1,585		3,106		2,736
Discontinued operations	3,163		2,183		1,133
	4,748		5,289		3,869
Net income attributable to:
Continuing operations	32,500		14,299		7,177
Discontinued operations	64,865		8,935		7,737
	$	97,365	$	23,234	$	14,914

Net income attributable to limited partners:
Basic:
Continuing operations	$	1.32	$	0.57	$	0.25
Discontinued operations	2.64		0.35		0.38
	$	3.96	$	0.92	$	0.63

Weighted average limited partner units - basic	23,362		19,545		17,525

Diluted:
Continuing operations	$	1.32	$	0.57	$	0.25
Discontinued operations	2.64		0.35		0.38
	$	3.96	$	0.92	$	0.63

Weighted average limited partner units - diluted	23,365		19,547		17,526

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)



	Year Ended December 31,
	2012 ¹			2011 ¹			2010 ¹
Net income	$	101,987		$	22,759		$	27,533
Other comprehensive income adjustments:
Changes in fair values of commodity cash flow hedges	126			1,011			143
Commodity cash flow hedging gains reclassified to earnings	(752		)	(1,822		)	(617		)
Changes in fair value of interest rate cash flow hedges	—			—			(241		)
Interest rate cash flow hedging losses reclassified to earnings	—			18			4,210
Other comprehensive income (loss)	(626		)	(793		)	3,495
Comprehensive income	$	101,361		$	21,966		$	31,028

¹ Financial information for 2012, 2011 and 2010 has been revised to include results attributable to the Redbird Class A Interests and the Blending and Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL

(Dollars in thousands)



	Partners’ Capital
	Parent Net Investment ¹			Common					Subordinated					General Partner			Accumulated Comprehensive Income
	Parent Net Investment ¹			Units		Amount			Units		Amount			Amount			Amount			Total
Balances – December 31, 2009	$	41,643		16,057,832		$	245,683		889,444		$	16,613		$	4,731		$	(2,076	)	$	306,594
Net Income	11,511			—		12,153			—		—			3,869			—			27,533
Recognition of beneficial conversion feature	—			—		(1,108		)	—		1,108			—			—			—
Follow-on public offerings	—			2,650,000		78,600			—		—			—			—			78,600
Redemption of common units	—			(1,000,000	)	(28,070		)	—		—			—			—			(28,070		)
General partner contribution	—			—		—			—		—			1,089			—			1,089
Excess purchase price over carrying value of acquired assets	—			—		(4,590		)	—		—			—			—			(4,590		)
Cash distributions ($3.00 per unit)	—			—		(51,886		)	—		—			(4,810		)	—			(56,696		)
Unit-based compensation	—			3,500		113			—		—			—			—			113
Purchase of treasury units	—			(3,500	)	(108		)	—		—			—			—			(108		)
Adjustment in fair value of derivatives	—			—		—			—		—			—			3,495			3,495
Balances – December 31, 2010	53,154			17,707,832		250,787			889,444		17,721			4,879			1,419			327,960

Net income (loss)	(1,583		)	—		19,053			—		—			5,289			—			22,759
Recognition of beneficial conversion feature	—			—		(1,108		)	—		1,108			—			—			—
Follow-on public offering	—			1,874,500		70,330			—		—			—			—			70,330
General partner contribution	—			—		—			—		—			1,505			—			1,505
Conversion of subordinated units to common units	—			889,444		18,829			(889,444	)	(18,829		)	—			—			—
Cash distributions ($3.05 per unit)	—			—		(58,252		)	—		—			(6,245		)	—			(64,497		)
Excess purchase price over carrying value of acquired assets	—			—		(19,685		)	—		—			—			—			(19,685		)
Unit-based compensation	—			14,850		190			—		—			—			—			190
Purchase of treasury units	—			(14,850	)	(582		)	—		—			—			—			(582		)
Adjustment in fair value of derivatives	—			—		—			—		—			—			(793		)	(793		)
Balances – December 31, 2011	51,571			20,471,776		279,562			—		—			5,428			626			337,187

Net income (loss)	4,622			—		92,617			—		—			4,748			—			101,987
Follow-on public offering	—			6,095,000		194,170			—		—			—			—			194,170
General partner contribution	—			—		—			—		—			4,145			—			4,145
Cash distributions ($3.06 per unit)	—			—		(70,679		)	—		—			(5,849		)	—			(76,528		)
Excess purchase price over carrying value of acquired assets	—			—		(142,075		)	—		—			—			—			(142,075		)
Excess carrying value of assets over the purchase price paid by Martin Resource Management	—			—		(4,268		)	—		—			—			—			(4,268		)
Unit-based compensation	—			—		385			—		—			—			—			385
Purchase of treasury units	—			—		(222		)	—		—			—			—			(222		)
Contributions to parent	(56,193		)	—		—			—		—			—			—			(56,193		)
Adjustment in fair value of derivatives	—			—		—			—		—			—			(626		)	(626		)
Balances – December 31, 2012	$	—		26,566,776		$	349,490		—		$	—		$	8,472		$	—		$	357,962

¹ Financial information for 2012, 2011 and 2010 has been revised to include results attributable to the Redbird Class A interests and the Blending and Packaging Assets acquired from Cross prior to October 2, 2012 . See Note 2(a) – Principles of Presentation and Consolidation.

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)



	Year Ended December 31,
	2012¹			2011¹			2010¹
Cash flows from operating activities:
Net income	$	101,987		$	22,759		$	27,533
Less: Income from discontinued operations	(64,865		)	(9,392		)	(8,061		)
Net income from continuing operations	37,122			13,367			19,472
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	42,063			40,276			36,884
Amortization of deferred debt issue costs	3,290			3,755			4,814
Amortization of discount on notes payable	581			351			269
Deferred income taxes	402			622			452
(Gain) loss on disposition or sale of property, plant, and equipment	795			898			(229		)
Gain on sale of equity method investment	(486		)	—			—
Equity in (earnings) loss of unconsolidated entities	1,113			4,752			(2,536		)
Gain on ownership change in unconsolidated entity	—			—			(6,413		)
Other	385			190			113
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(56,856		)	(34,626		)	(20,009		)
Product exchange receivables	14,230			(8,547		)	(4,967		)
Inventories	(2,733		)	(28,714		)	(20,815		)
Due from affiliates	(20,135		)	5,551			(175		)
Other current assets	3,046			(1,996		)	(1,455		)
Trade and other accounts payable	17,595			50,904			14,116
Product exchange payables	(25,126		)	14,961			14,366
Due to affiliates	18,976			11,874			(5,714		)
Income taxes payable	367			(943		)	(8		)
Other accrued liabilities	(1,463		)	1,063			5,185
Change in other non-current assets and liabilities	872			3,500			(4,307		)
Net cash provided by continuing operating activities	34,038			77,238			29,043
Net cash provided by (used in) discontinued operating activities	(1,360		)	14,124			10,135
Net cash provided by operating activities	32,678			91,362			39,178
Cash flows from investing activities:
Payments for property, plant, and equipment	(93,640		)	(77,202		)	(18,179		)
Acquisitions, net of cash acquired	(224,603		)	(16,815		)	(16,747		)
Proceeds from sale of acquired assets	56,000			—			—
Payments for plant turnaround costs	(2,107		)	(2,103		)	(1,090		)
Proceeds from sale of property, plant, and equipment	44			1,025			994
Proceeds from sale of equity method investment	531			—			—
Investments in unconsolidated entities	(775		)	(59,319		)	—
Milestone distributions from ECP	2,208			—			6,625
Return of investments from unconsolidated entities	5,980			1,432			—
(Contributions to) unconsolidated entities for operations	(30,279		)	(35,765		)	(19,253		)
Net cash (used in) continuing investing activities	(286,641		)	(188,747		)	(47,650		)
Net cash provided by (used in) discontinued investing activities	271,605			(13,908		)	(43,366		)
Net cash (used in) investing activities	(15,036		)	(202,655		)	(91,016		)
Cash flows from financing activities:
Payments of long-term debt	(706,000		)	(442,000		)	(441,868		)
Payments of notes payable and capital lease obligations	(6,556		)	(1,132		)	(111		)
Proceeds from long-term debt	727,000			529,000			503,856
Net proceeds from follow on public offerings	194,170			70,330			78,600
General partner contributions	4,145			1,505			1,089
Redemption of common units	—			—			(28,070		)
Excess purchase price over carrying value of acquired assets	(142,075		)	(19,685		)	(4,590		)
Excess carrying value of assets over the purchase price paid by Martin Resource Management	(4,268		)	—			—
Purchase of treasury units	(222		)	(582		)	(108		)
Increase (decrease) in affiliate funding of investments in unconsolidated entities	(2,208		)	30,828			12,628
Payments of debt issuance costs	(204		)	(3,588		)	(7,468		)
Cash distributions paid	(76,528		)	(64,497		)	(56,696		)
Net cash provided by (used in) financing activities	(12,746		)	100,179			57,262

Net increase (decrease) in cash	4,896			(11,114		)	5,424
Cash at beginning of period	266			11,380			5,956
Cash at end of period	$	5,162		$	266		$	11,380

Supplemental schedule of non-cash investing and financing activities:
Purchase of assets under note payable	$	—		$	—		$	7,354

¹ Financial information for 2010, 2011, and 2012 has been revised to include results attributable to the Redbird Class A interests and the Blending and Packaging Assets acquired from Cross prior to October 2, 2012. See Note 2(a) – Principles of Presentation and Consolidation.

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)


(1)	Organization and Description of Business

Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the U.S. Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants; natural gas services; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marine transportation services for petroleum products and by-products.

The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, the Partnership's primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the U.S. Gulf Coast region, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry.

In 2011, the Partnership and Martin Resource Management Corporation (“Martin Resource Management” or “Parent”) formed Redbird Gas Storage LLC (“ Redbird ”), a natural gas storage joint venture to invest in Cardinal Gas Storage Partners LLC (“Cardinal”). Cardinal is a joint venture between Redbird and Energy Capital Partners (“ECP”) that is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi. The Partnership owns 100% of the Class A and Class B equity interests in Redbird . As of December 31, 2012 and 2011, Redbird owned an unconsolidated 41.28% and 40.08% interest in Cardinal, respectively. This investment is accounted for by the equity method.


(2)	Significant Accounting Policies

(a) Principles of Presentation and Consolidation

The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”), 810-10 and to assess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10. No such variable interest entities exist as of December 31, 2012 or 2011.

As discussed in Note 5, on July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets. These assets, along with additional gathering and processing assets discussed in Note 5 are collectively referred to as the "Prism Assets". The Partnership has classified the Prism Assets, including related liabilities as held for sale at December 31, 2011 and has presented the results of operations and cash flows as discontinued operations for the years ended December 31, 2012, 2011 and 2010, respectively. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the net assets and operations and cash flows of the Prism Assets as assets held for sale and discontinued operations, respectively.

On October 2, 2012, the Partnership, which owned 10.74% of the Class A interests and 100% of the Class B interests, acquired all of the remaining Class A interests in Redbird from Martin Underground Storage, Inc., a subsidiary of Martin Resource Management. Redbird was formed by the Partnership and Martin Resource Management in 2011 to invest in Cardinal.

On October 2, 2012, the Partnership acquired from Cross Oil Refining and Marketing, Inc. ("Cross"), a wholly-owned subsidiary of Martin Resource Management, certain specialty lubricant product blending and packaging assets (“Blending and Packaging Assets”).

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The acquisitions of the Redbird Class A interests and the Blending and Packaging Assets were considered a transfer of net assets between entities under common control. The acquisitions of the Redbird Class A interests and the Blending and Packaging Assets are recorded at amounts based on the historical carrying value of these assets at October 2, 2012, and the Partnership is required to update its historical financial statements to include the activities of the Redbird Class A interests and the Blending and Packaging Assets as of the date of common control. The Partnership’s accompanying historical financial statements have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the activities of the Redbird Class A interests and the Blending and Packaging Assets as if the Partnership owned these assets for the periods presented. Net income attributable to the Redbird Class A interests and the activities of the Blending and Packaging Assets for periods prior to the Partnership’s acquisition of the assets is not allocated to the general and limited partners for purposes of calculating net income per limited partner unit. See Note (2)(p).

(b) Product Exchanges

The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange NGLs and sulfur with third parties. The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method. Product exchanges with the same counterparty are entered into in contemplation of one another and are combined. The net amount related to location differentials is reported in “Product sales” or “Cost of products sold” on the Consolidated Statement of Operations.

Inventories are stated at the lower of cost or market. Cost is determined by using the FIFO method for all inventories.

(d) Revenue Recognition

Terminalling and Storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate. For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

Natural Gas Services – NGL distribution revenue is recognized when product is delivered by truck to the Partnership's NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.

Sulfur Services – Revenue from sulfur product sales is recognized when the customer takes title to the product. Revenue from sulfur services is recognized as deliveries are made during each monthly period.

Marine Transportation – Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip.

(e) Equity Method Investments

The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under certain provisions of ASC 350-20, related to goodwill, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock. No portion of the net income from these entities is included in the Partnership’s operating income.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The Partnership owns 100% of the Class A and Class B equity interests in Redbird. Redbird, as of December 31, 2012 and 2011, owned a 41.28% and 40.08% interest in Cardinal, respectively. The Partnership owns an unconsolidated 50% interest in Caliber Gathering, LLC ("Caliber").

The Partnership's subsidiary, legal name of Prism Gas Systems I, L.P., owned unconsolidated 50% interests in three investees, which were sold in 2012. See Note 5.

Each of these interests is accounted for under the equity method of accounting.

(f) Property, Plant, and Equipment

Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.

Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized on a straight line basis over the estimated useful life of the asset.

Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.

(g) Goodwill and Other Intangible Assets

Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.

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

The Partnership has historically performed its annual impairment testing of goodwill and indefinite-lived intangible assets as of September 30 of each year. During the third quarter of fiscal 2011, the Partnership changed the annual impairment testing date from September 30 to August 31. The Partnership believes this change, which represents a change in the method of applying an accounting principle, is preferable in the circumstances as the earlier date provides additional time prior to our quarter-end to complete the goodwill impairment testing and report the results in our quarterly report on Form 10-Q.

The Partnership has performed the annual impairment tests as of August 31, 2012, August 31, 2011, and September 30, 2010, and determined fair value in each reporting unit based on the weighted average of three valuation techniques: (i) the discounted cash flow method; (ii) the guideline public company method; and (iii) the guideline transaction method. At August 31, 2012, August 31, 2011, and September 30, 2010, the estimated fair value of each of the four reporting units was in excess of its carrying value, resulting in no impairment.

No triggering events occurred that would cause the Partnership to perform an impairment test at either December 31, 2012 or 2011.

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

(h) Debt Issuance Costs

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Debt issuance costs relating to the Partnership’s revolving credit facility and senior notes are deferred and amortized over the terms of the debt arrangements.

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $204 , $3,588 and $7,468 in the years ended December 31, 2012, 2011 and 2010, respectively.

Due to a reduction in the number of lenders under the Partnership’s multi-bank credit agreement, $0 , $494 and $634 of the existing debt issuance costs were determined not to have continuing benefit and were expensed during 2012, 2011 and 2010, respectively. Remaining unamortized deferred issuance costs are amortized over the term of the revised debt arrangement.

Amortization of debt issuance costs, which is included in interest expense, totaled $3,290 , $3,755 and $4,814 for the years ended December 31, 2012, 2011 and 2010, respectively. Accumulated amortization amounted to $6,014 and $2,723 at December 31, 2012 and 2011, respectively.

(i) Impairment of Long-Lived Assets

In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. The Partnership has not identified any triggering events in 2012, 2011 or 2010 that would require an assessment for impairment of long-lived assets.

(j) Asset Retirement Obligations

Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an Asset Retirement Obligation (“ARO”) at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. The Partnership’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment.

(k) Derivative Instruments and Hedging Activities

In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2011, the Partnership designated a portion of its derivative instruments as qualifying cash flow hedges. As of December 31, 2012, the Partnership did not have any hedging instruments outstanding. Fair value changes for these hedges have been recorded in accumulated other comprehensive income as a component of equity.

(l) Comprehensive Income

Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the Partnership includes unrealized gains and losses on derivative financial instruments. In accordance with ASC 815-10, the

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

(m) Use of Estimates

Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S. Actual results could differ from those estimates.

(n) Unit Grants

In April 2012, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 6,250 treasury units purchased by the Partnership in the open market for $222 . These units vest in 25% increments beginning in January 2013 and will be fully vested in January 2016.

In May 2011, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 5,750 treasury units purchased by the Partnership in the open market for $235 and 500 treasury units from forfeitures. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.

In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for $347 . On July 31, 2012, 6,850 of these units were fully vested to certain employees in connection with the sale of the Prism Assets. The remaining 2,250 units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015.

In August 2010, the Partnership issued 1,500 restricted common units to each of two new non-employee directors under its long-term incentive plan from 500 treasury units purchased by the Partnership in the open market for $16 and 2,500 common units from forfeited unit grants. These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.

In May 2010, the Partnership issued 1,000 restricted common units to each of its non-employee directors under its long-term incentive plan from treasury units purchased by the Partnership in the open market for $92 . These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.

The Partnership accounts for these transaction under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees. The cost resulting from the unit-based payment transactions was $ 385 , $ 190 , and $ 113 for the years ended December 31, 2012, 2011 and 2010, respectively.

(o) Incentive Distribution Rights

The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights (“IDRs”) in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the partnership agreement of the Partnership (the “Partnership Agreement”), and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement. On October 2, 2012, the Partnership Agreement was amended to provide that the General Partner shall forego the next $18,000 in incentive distributions that it would otherwise be entitled to receive. No incentive distributions were allocated to the general partner from July 1, 2012 through December 31, 2012, which would have been payable to the general partner on November 14, 2012 for the third quarter distribution and February 14, 2013 for the fourth quarter distribution.

The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

For the years ended December 31, 2012, 2011 and 2010, the general partner received $2,857 , $4,901 , and $3,623 in incentive distributions.

(p) Net Income per Unit

The Partnership follows the provisions of ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the IDR would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement.

For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the beneficial conversion feature is added back to net income available to common limited partners, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method.

The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:



	Years Ended December 31,
	2012		2011			2010
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	37,122	$	13,367		$	19,472
Less pre-acquisition income (loss) allocated to Parent	4,622		(1,583		)	11,511
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	954		2,878			2,562
Distributions payable on behalf of general partner interest	522		789			839
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	109		(561		)	(665		)
Less beneficial conversion feature	—		651			784
Limited partners’ interest in net income	$	30,915	$	11,193		$	4,441



	Years Ended December 31,
	2012		2011			2010
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	64,865	$	9,392		$	8,061
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	1,903		2,023			1,061
Distributions payable on behalf of general partner interest	1,040		555			348
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	220		(395		)	(276		)
Less beneficial conversion feature	—		457			324
Limited partners’ interest in net income	$	61,702	$	6,752		$	6,604

The Partnership allocates the General Partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The weighted average units outstanding for basic net income per unit were 23,361,551 , 19,545,427 and 17,525,089 for years ended December 31, 2012, 2011 and 2010, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 3,018 , 1,278 and 900 units for the years ended December 31, 2012, 2011 and 2010, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(q) Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2012, 2011 and 2010, the Conflicts Committee of the Partnership's general partner approved reimbursement amounts of $7,593 , $4,771 and $3,791 , respectively, reflecting the Partnership's allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

(r) Environmental Liabilities and Litigation

The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

(s) Accounts Receivable and Allowance for Doubtful Accounts.

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable.

(t) Deferred Catalyst Costs

The cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 24 to 36 months.

(u) Deferred Turnaround Costs

The Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 24 to 36 months.

(v) Income Taxes

With respect to the Partnership’s taxable subsidiary (Woodlawn Pipeline Co., Inc.) and the Blending and Packaging Assets prior to the date of acquisition from Cross, income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

As discussed further in Note 18, the assets of the Partnership's taxable subsidiary Woodlawn Pipeline Co., Inc were disposed of on July 31, 2012. The entity was dissolved on December 31, 2012.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(w) Prior period correction of an immaterial error

The statement of cash flows for the year ended December 31, 2010 has been revised to correct an immaterial error of $6,625 in the equity in loss of unconsolidated entities (which is an adjustment to reconcile net income to net cash provided by operating activities) and affiliate funding of investments in unconsolidated entities (which is included in cash flows from financing activities). The correction of this immaterial error decreases net cash provided by operating activities, increases net cash provided by financing activities, and had no effect on the Partnership's cash and cash equivalents, investments in unconsolidated entities, net income or partners' capital.


(3)	Recent Accounting Pronouncements

In February 2013, the FASB amended the provisions of ASC 220 related to accumulated other comprehensive income , which does not change the current requirements for reporting net income or other comprehensive income in financial statements. The standard requires a company to provide information about the amounts reclassified out of accumulated other comprehensive income by component. The company is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The standard is effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. The adoption of this pronouncement is not anticipated to have a material impact on Partnership’s financial position or results of operations.

In September 2011, the FASB amended the provisions of ASC 350 related to testing goodwill for impairment. This update simplifies the goodwill impairment assessment by allowing a company to first review qualitative factors to determine the likelihood of whether the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, the company would not be required to perform the two-step goodwill impairment test for that reporting unit. This update is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. This amended guidance was adopted by the Partnership effective January 1, 2012.

In June 2011, the FASB amended the provisions of ASC 220 related to other comprehensive income. This newly issued guidance: (1) eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity; (2) requires the consecutive presentation of the statement of net income and other comprehensive income; and (3) requires an entity to present reclassification adjustments on the face of the financial statements from other comprehensive income to net income. The amendments in this guidance do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income nor do the amendments affect how earnings per share is calculated or presented. This guidance is required to be applied retrospectively and is effective for fiscal years and interim periods within those years beginning after December 15, 2011. This amended guidance was adopted by the Partnership effective January 1, 2012. As this new guidance only requires enhanced disclosure, adoption did not impact the Partnership’s financial position or results of operations.


(4)	Acquisitions

Talen's Marine & Fuel, LLC

On December 31, 2012, the Partnership acquired all of the outstanding membership interests in Talen's Marine & Fuel, LLC (“Talen's”) from Quintana Energy Partners, L.P. for $103,368 , subject to certain post-closing adjustments, including the assumption of a note payable in the amount of $2,971 . Through this acquisition, the Partnership acquired certain terminalling facilities and other terminalling related assets located along the Texas and Louisiana gulf coast. This transaction was funded by borrowings under the Partnership's revolving credit facility. Simultaneous with the acquisition, the Partnership sold certain working capital-related assets and a customer relationship intangible asset to Martin Energy Services LLC (“MES”), a wholly-owned subsidiary of Martin Resource Management for $56,000 . Due to the Talen's acquisition, MES entered into various service agreements with Talen's pursuant to which we provide certain terminalling and marine services to MES. The excess carrying value of the assets over the purchase price paid by Martin Resource Management at the sales date was $4,268 and was

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

recorded as an adjustment to partners' capital. The remaining net assets retained by the Partnership were recorded at fair value of $43,100 in the following preliminary purchase price allocation:



Purchase price paid to acquire Talen's	$	103,368
Less proceeds received from Martin Resource Management for assets sold (described above)	(56,000		)
Less excess of carrying value of assets sold to Martin Resource Management over the purchase price paid by Martin Resource Management	(4,268		)
Total	$	43,100



Cash	$	5,096
Accounts and other receivables, net	2,682
Assets held for sale	3,578
Other current assets	1,547
Property, plant and equipment	23,838
Goodwill	11,279
Notes payable	(2,971		)
Current liabilities	(1,480		)
Other liabilities	(469		)
Total	$	43,100

The Partnership has not obtained all of the information necessary to finalize the purchase price allocation. The final purchase price allocation is expected to be completed during second quarter 2013.

Lubricant Blending and Packaging Assets

On October 2, 2012, the Partnership purchased the Blending and Packaging Assets from Cross. The consideration consisted of $121,767 in cash at closing, plus a final net working capital adjustment of $907 paid in October of 2012. The purchase was funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these blending and packaging assets was recorded at the historical carrying value of the assets at the acquisition date, which were as follows:



Accounts receivable, net	$	20,599
Inventory	18,730
Other current assets	769
Property, plant and equipment, net	24,692
Current liabilities	(2,424		)
Total	$	62,366

The excess purchase price over the historical carrying value of the assets at the acquisition date was $60,308 and was recorded as an adjustment to partners' capital.

Redbird Class A Interests

On October 2, 2012, the Partnership acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150,000 in cash. The Partnership began making Class A investments in Redbird during the fourth quarter of 2011. Prior to the transaction, the Partnership owned a 10.74% Class A interest and a 100% Class B interest in Redbird . This transaction was funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these interests was recorded at the historical carrying value of the interests at the acquisition date. The Partnership recorded an investment in consolidated

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

entities of $68,233 and the excess of the purchase price over the carrying value of the Class A interests of $81,767 was recorded as an adjustment to partners' capital.

Redbird Class B Interests

On May 31, 2011, the Partnership acquired all of the Class B equity interests in Redbird for approximately $59,319 . This amount was recorded as an investment in an unconsolidated entity. Concurrent with the closing of this transaction, Cardinal acquired all of the outstanding equity interests in Monroe Gas Storage Company, LLC (“Monroe”) as well as an option on development rights to an adjacent depleted reservoir facility. This acquisition was funded by borrowings under the Partnership’s revolving credit facility.

Terminalling Facilities

On January 31, 2011, the Partnership acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for $36,500 . These assets are located across the Louisiana Gulf Coast. This acquisition was funded by borrowings under the Partnership’s revolving credit facility.

These terminalling assets were acquired by Martin Resource Management in its acquisition of L&L Holdings, LLC (“L&L”) on January 31, 2011. During the second quarter of 2011, Martin Resource Management finalized the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the terminalling assets acquired by the Partnership. The Partnership recorded an adjustment in the amount of $19,685 to reduce property, plant and equipment and partners’ capital for the difference between the purchase price and the fair value of the terminalling assets acquired based on Martin Resource Management’s final purchase price allocation.

On August 26, 2010, the Partnership acquired certain shore-based marine terminalling assets from Martin Resource Management for $11,700 . The net book value of the acquired assets was $7,331 and was recorded in property, plant and equipment. The remaining $4,395 was recorded as an adjustment to partners’ capital. These assets are located in Theodore, Alabama and Pascagoula, Mississippi.

Marine Equipment

On December 22, 2010, the Partnership acquired a 60,000 bbl offshore tank barge from Martin Resource Management for a total purchase price of $17,000 . The Partnership paid cash in the amount of $9,600 and assumed a note payable to a third party for $7,400 . The net book value of the acquired assets was $16,805 and was recorded in property, plant, and equipment. The remaining $195 was recorded as an adjustment to partners’ capital.


(5)	Discontinued Operations and Divestitures

On July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas Systems I, L.P. (“Prism Gas”), a wholly-owned subsidiary of the Partnership, and other natural gas gathering and processing assets also owned by the Partnership to a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”). The Partnership received net cash proceeds from the sale of $273,269 . The asset sale included the Partnership’s 50% operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint owned the other 50% percent interest.

Additionally, on September 18, 2012, the Partnership completed the sale of its interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy, LLC (“PIPE”) to a private investor group for $1,530 .

The assets described above collectively are referred to herein as the Prism Assets.

The Partnership classified the results of operations of the Prism Assets which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the consolidated and condensed statements of operations for all periods presented. The assets and liabilities to be sold met the accounting criteria to be classified as held for sale and were aggregated and reported on separate lines in the consolidated and condensed balance sheet at December 31, 2011.

The assets and liabilities classified held for sale as of December 31, 2011 were as follows:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



	2011
Assets
Inventories	$	486
Property, plant and equipment	78,324
Accumulated depreciation	(18,438		)
Goodwill	28,931
Investment in unconsolidated entities	107,549
Other assets, net	15,935
Assets held for sale	$	212,787

Liabilities
Other long-term obligations	$	501
Liabilities held for sale	$	501

The Prism Assets’ operating results, which are included in income from discontinued operations, were as follows:



	Year Ended December 31,
	2012			2011			2010

Total revenues from third parties ¹	$	66,876		$	121,338		$	112,477
Total costs and expenses and other, net, excluding depreciation and amortization	(64,562		)	(115,957		)	(110,061		)
Depreciation and amortization	(2,320		)	(5,512		)	(4,452		)
Other operating income (loss) ²	61,858			—			(92		)
Equity in earnings of unconsolidated entities ³	4,611			9,412			9,792
Income from discontinued operations before income taxes	66,463			9,281			7,664
Income tax (expense) benefit	(1,598		)	111			397
Income from discontinued operations, net of income taxes	$	64,865		$	9,392		$	8,061

¹ Total revenues from third parties excludes intercompany revenues of $26,431 , $67,141 , and $56,390 for the years ended December 31, 2012, 2011, 2010, respectively.

² The Partnership recognized a gain on the sale of the Prism Assets of $61,848 in income from discontinued operations for the year ended December 31, 2012.

³ Represents equity in earnings of Waskom, Matagorda, and PIPE for the years ended December 31, 2012, 2011 and 2010.


(6)	Inventories

Components of inventories at December 31, 2012 and 2011 were as follows:



	2012		2011
Natural gas liquids	$	33,610	$	25,178
Sulfur	14,892		24,335
Sulfur based products	17,824		14,857
Lubricants	27,366		26,589
Other	2,295		2,295
	$	95,987	$	93,254


(7)	Property, Plant and Equipment

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

At December 31, 2012 and 2011 , property, plant, and equipment consisted of the following:



	Depreciable Lives	2012		2011
Land	—	$	22,235	$	19,790
Improvements to land and buildings	10-25 years	104,788		78,815
Transportation equipment	3-7 years	1,757		1,787
Storage equipment	5-20 years	86,870		67,360
Marine vessels	4-25 years	246,536		228,043
Operating equipment	3-20 years	272,192		197,661
Furniture, fixtures and other equipment	3-20 years	3,510		2,674
Construction in progress		29,456		55,330
		$	767,344	$	651,460

Depreciation expense for the year ended December 31, 2012 , 2011 and 2010 was $40,724 , $37,869 , and $34,796 , respectively, which includes amortization of fixed assets acquired under capital lease obligations of $280 for each of the years ended 2012 , 2011 and 2010 . Gross assets under capital leases were $7,764 at December 31, 2012 and 2011 . Accumulated amortization associated with capital leases was $955 and $675 at December 31, 2012 and 2011 , respectively.

(8) Goodwill and Other Intangibles

The following table represents the goodwill balance at December 31, 2011, changes during the year, and the resulting balances at December 31, 2012:



			Talen's		Disposal of
	2011		Acquisition ¹		Prism Assets ²			2012
Carrying amount of goodwill:
Terminalling and storage	$	883	$	9,469	$	—		$	10,352
Natural gas services	79		—		—			79
Sulfur services	5,349		—		—			5,349
Marine transportation	2,026		1,810		—			3,836
	8,337		11,279		—			19,616
Goodwill classified as held for sale	28,931		—		(28,931		)	—
Total goodwill	$	37,268	$	11,279	$	(28,931	)	$	19,616

¹ These changes represent the amounts allocated to goodwill during the purchase price allocation of Talen's, of which $9,469 and $1,810 was allocated to the Terminalling and storage and Marine transportation segments, respectively. See Note 4.

² This change represents goodwill disposed of as part of the Partnership's divestiture of the Prism Assets. See Note 5.

Other intangible assets subject to amortization consist of covenants not-to-compete, customer contracts associated with gathering and processing assets and a transportation contract associated with the residue gas pipeline.

The unamortized balance of other intangible assets, classified in the consolidated balance sheets as other assets, net, amounted to $198 and $338 at December 31, 2012 and 2011 , respectively. The unamortized balance of other intangible assets, net, classified in the consolidated balance sheets as assets held for sale, amounted to $0 and $15,935 at December 31, 2012 and 2011 , respectively.

Aggregate amortization expense for amortizing intangible assets included in continuing operations was $140 , $140 , and $226 , for the years ended December 31, 2012 , 2011 and 2010 , respectively, and accumulated amortization amounted to $1,200 and $1,060 at December 31, 2012 and 2011 , respectively.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Estimated amortization expenses for the years subsequent to December 31, 2012 are as follows: 2013 - $140 ; 2014 - $58 ; 2015 - $0 ; 2016 - $0 ; 2017 - $0 ; subsequent years - $0 .

(9) Leases

The Partnership has numerous non-cancelable operating leases primarily for terminal facilities and transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine vessel charters. Certain of the Partnership's marine vessels have been acquired under capital leases.

The Partnership’s future minimum lease obligations as of December 31, 2012 consist of the following:



Fiscal year	Operating Leases		Capital Leases

2013	$	12,781	$	1,148
2014	11,589		1,169
2015	10,683		1,169
2016	9,546		5,465
2017	5,346		—
Thereafter	8,270		—
Total	$	58,215	8,951
Less amounts representing interest costs			3,112
Present value of net minimum capital lease payments			5,839
Less current portion			235
Present value of net minimum capital lease payments, excluding current portion			$	5,604

Rent expense for continuing operating leases for the years ended December 31, 2012 , 2011 and 2010 was $15,801 , $19,280 and $15,710 , respectively. The amount recognized in interest expense for capital leases was $945 , $972 , and $991 for the years ended December 31, 2012 , 2011 and 2010 , respectively.

(10) Investments in Unconsolidated Entities and Joint Ventures

As discussed in detail in Note 5, the Partnership sold its 50% interests in Waskom, Matagorda, and PIPE in 2012. The equity in earnings associated with these investments during the periods owned is recorded in income from discontinued operations for the years ended December 31, 2012, 2011, and 2010.

On May 1, 2008, certain assets and liabilities were contributed to acquire a 50% ownership interest in Cardinal. In conjunction with this transaction, ECP contributed cash for a 50% ownership interest in Cardinal.

The initial carrying amount of the investment in Cardinal was less than the contributed underlying net assets. Of the basis difference, $1,250 relates to differences in the carrying value of fixed assets contributed as compared to amounts recorded by Cardinal, and is being amortized over 40 years, the approximate useful life of the underlying assets. Such amortization amounted to $31 for each of the three years ending December 31, 2012, 2011 and 2010. The remaining basis difference is a permanent difference that will be realized upon sale of the investment in Cardinal.

ECP is also required to make $25,000 in cash contributions to Cardinal once certain “milestones” are met, which relate to future progress on projects currently underway. The agreement requires such contributions be made to Cardinal and then distributed to the Partnership. These are the equivalent of additional purchase price for the assets originally contributed by the Partnership and, therefore, are recognized as equity in earnings of equity method investees in the consolidated statements of

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

operations. Milestone payments totaling $2,208 , $0 , and $6,625 were made during 2012, 2011 and 2010, respectively. As of December 31, 2012, ECP has made $13,249 in cumulative milestone payments.

On May 24, 2011, Redbird was formed to hold membership interests in Cardinal. On May 27, 2011, initial contributions consisted of all of Martin Resource Management’s membership interests in Cardinal for 100% of the Class A interests in Redbird. Simultaneously, the Partnership acquired 100% of the Class B interests in Redbird for approximately $59,319 . Concurrent with the closing of this transaction, Redbird contributed the cash to Cardinal which used the cash, along with a contribution from ECP, to acquire all of the outstanding equity interests in Monroe Gas Storage Company, LLC as well as an option on development rights to an adjacent depleted reservoir facility. As discussed in Notes 2 and 4, on October 2, 2012, the Partnership, acquired the remaining Class A interests in Redbird. As this acquisition is considered a transfer of net assets between entities under common control, the acquisition is recorded at the historical carrying value of these assets at that date. The Partnership is required to retrospectively update its historical financial statements to include the activities of the Class A interests in Redbird as of the date of common control. The Partnership's accompanying historical financial statements for the years ended December 31, 2012, 2011, and 2010 have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the Redbird Class A interests (including predecessor activities related to the amounts contributed to form Cardinal and Cardinal activities prior to the formation of Redbird) as if the Partnership owned these assets for these periods.

Due to different funding levels to Cardinal by the partners in 2010, the initial 50% ownership by the Company has decreased. Because of that decrease in ownership, the Company has realized a partial sale of its ownership to ECP which has resulted in gains in the statement of operations for the year ending December 31, 2010 of $6,413 . As of December 31, 2012, Redbird owns an unconsolidated 41.28% interest in Cardinal.

During the second quarter of 2012, the Partnership acquired an unconsolidated 50% interest in Caliber Gathering, LLC (“Caliber”) and Pecos Valley Producer Services, LLC (“Pecos Valley”). The Partnership sold its interest in Pecos Valley during the third quarter of 2012 for $531 , resulting in a gain of $486 recorded in other, net in the Partnership's consolidated statement of operations for the year ended December 31, 2012.

These investments are accounted for by the equity method.

The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s consolidated balance sheets and the components of equity in earnings of unconsolidated entities included in the Partnership’s consolidated statements of operations:



	December 31, 2012		December 31, 2011
Investment in Waskom ¹	$	—	$	102,896
Investment in PIPE ¹	—		1,291
Investment in Matagorda ¹	—		3,362
Investment in unconsolidated entities classified as assets held for sale	—		107,549

Investment in Cardinal	153,749		132,605
Investment in Caliber	560		—
Investment in unconsolidated entities	154,309		132,605
Total Investment in unconsolidated entities	$	154,309	$	240,154

¹ As of December 31, 2011, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated balance sheets as assets held for sale.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



	Years Ended December 31,
	2012		2011		2010
Equity in earnings of Waskom ¹	$	4,172	$	9,143	$	9,831
Equity in loss of PIPE ¹	(60)		(45)		(180		)
Equity in earnings of Matagorda ¹	499		314		141
Equity in earnings of discontinued operations	4,611		9,412		9,792

Equity in earnings (loss) of Cardinal	(943)		(4,752)		2,536
Equity in loss of Caliber	(190)		—		—
Equity in earnings (loss) of Pecos Valley	20		—		—
Equity in earnings (loss) of unconsolidated entities	(1,113)		(4,752)		2,536
Total equity in earnings of unconsolidated entities	$	3,498	$	4,660	$	12,328

¹ For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included on the consolidated statements of operations and cash flows as discontinued operations.

Select financial information for significant unconsolidated equity method investees is as follows:



	As of December 31,				Years ended December 31,
	Total Assets		Partners’ Capital		Revenues		Net Income
2012
Waskom	$	—	$	—	$	66,662	$	8,986
2011
Waskom	$	146,655	$	126,863	$	129,119	$	19,385
2010
Waskom	$	122,057	$	107,508	$	124,122	$	20,762



	As of December 31,						Years ended December 31,
	Total Assets		Long-Term Debt		Members’ Equity		Revenues		Net Loss
2012
Cardinal	$	690,491	$	211,180	$	457,316	$	31,999	$	(5,932	)
2011
Cardinal	$	561,375	$	122,064	$	422,935	$	19,471	$	(11,534	)
2010
Cardinal	$	313,802	$	98,112	$	200,815	$	4,751	$	(15,150	)

As of December 31, 2012 and 2011, the Partnership’s interest in cash of the unconsolidated equity method investees is $1,265 and $1,155 , respectively.

(11) Fair Value Measurements

The Partnership follows the provisions of ASC 820 related to fair value measurements and disclosures, which established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of this guidance had no impact on the Partnership’s financial position or results of operations.

ASC 820 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value into one of the following categories:

Level 1: Quoted market prices in active markets for identical assets or liabilities.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

Level 3: Unobservable inputs that are not corroborated by market data.

The Partnership’s derivative instruments, which consist of commodity and interest rate swaps, are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets, which is considered Level 2. Refer to Note 12 for further information on the Partnership’s derivative instruments and hedging activities.

The following items are measured at fair value on a recurring and non-recurring basis and are subject to the disclosure requirements of ASC 820 at December 31, 2012 and 2011:



	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	December 31, 2012		(Level 1)		(Level 2)		(Level 3)
Liabilities
Senior notes	$	187,066	$	—	$	187,066	$	—
Total liabilities	$	187,066	$	—	$	187,066	$	—



	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	December 31, 2011		(Level 1)		(Level 2)		(Level 3)
Assets
Natural gas derivatives	$	622	$	—	$	622	$	—
Total assets	$	622	$	—	$	622	$	—
Liabilities
Crude oil derivatives	$	245	$	—	$	245	$	—
Natural gas liquids derivatives	117		—		117		—
Senior notes	210,500		—		210,500		—
Total liabilities	$	210,862	$	—	$	210,862	$	—

FASB ASC 825-10-65, Disclosures about Fair Value of Financial Instruments , requires that the Partnership disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for the Partnership’s financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:


•	Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable and due from/to affiliates — the carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as such these have been excluded from the table above.

•

Long-term debt including current portion — The carrying amount of the revolving loan facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The estimated fair value of the Senior Notes is based on market prices of similar debt. The carrying amount of the Partnership's note payable to bank as of December 31, 2012 is not deemed to be significantly different than the fair value.

(12) Derivative Instruments and Hedging Activities

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The Partnership’s results of operations are materially impacted by changes in crude oil, natural gas and NGL prices and interest rates. In an effort to manage its exposure to these risks, the Partnership periodically enters into various derivative instruments, including commodity and interest rate hedges. The Partnership is required to recognize all derivative instruments as either assets or liabilities at fair value on the Partnership’s consolidated balance sheets and to recognize certain changes in the fair value of derivative instruments on the Partnership’s Consolidated Statements of Operations.

The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of its hedge contracts, including assessing the possibility of counterparty default. If the Partnership determines that a derivative is no longer expected to be highly effective, the Partnership discontinues hedge accounting prospectively and recognizes subsequent changes in the fair value of the hedge in earnings.

All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings. The Partnership is exposed to the risk that periodic changes in the fair value of derivatives qualifying for hedge accounting will not be effective, as defined, or that derivatives will no longer qualify for hedge accounting. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is recorded to earnings. Likewise, if a hedge ceases to qualify for hedge accounting, any change in the fair value of derivative instruments since the last period is recorded to earnings; however, any amounts previously recorded to AOCI would remain there until such time as the original forecasted transaction occurs, then would be reclassified to earnings or if it is determined that continued reporting of losses in AOCI would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods, then the losses would be immediately reclassified to earnings. If a forecasted hedge transaction is no longer probable of occurring, any gain or loss in AOCI is reclassified to earnings.

For derivative instruments that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. The effective portion of the derivative represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. To the extent the change in the fair value of the hedge does not perfectly offset the change in the fair value of the hedged item; the ineffective portion of the hedge is immediately recognized in earnings.

(a) Commodity Derivative Instruments

The Partnership is not currently exposed to market risks associated with commodity prices and from time to time has used derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership is focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

Due to the sale of the Prism Assets completed on July 31, 2012, as of December 31, 2012 , the Partnership has terminated and settled all of its commodity derivative instruments. For the year ended December 31, 2012 , changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in AOCI as a component of partners’ capital.

(b) Impact of Commodity Cash Flow Hedges

Crude Oil. For the years ended December 31, 2012, 2011 and 2010, net gains and losses on swap hedge contracts increased crude revenue (included in income from discontinued operations) by $496 , $775 and $27 , respectively.

Natural Gas. For the years ended December 31, 2012, 2011 and 2010, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $813 , $332 and $601 , respectively.

Natural Gas Liquids. For the years ended December 31, 2012, 2011 and 2010, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $1,066 , $254 and $207 , respectively.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

For information regarding fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note.

The Partnership is exposed to market risks associated with interest rates. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt and term loan credit facilities. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in AOCI until such time as the hedged item is recognized in earnings.

In August 2011, the Partnership terminated all of its existing interest swap agreements with an aggregate notional amount of $100,000 , which it had entered to hedge its exposure to changes in the fair value of Senior Notes. These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings. A termination benefit of $2,800 was received on the early extinguishment of the interest rate swap agreements in August 2011.

In March 2010, in connection with a pay down of the Partnership’s revolving credit facility, the Partnership terminated all of its existing cash flow hedge agreements with an aggregate notional amount of $140,000 , which it had entered to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. Termination fees of $3,850 were paid on the early extinguishment of all interest rate swap agreements in March 2010. The amounts remaining in AOCI were reclassified into interest expense over the original term of the terminated interest rate derivatives.

The Partnership recognized increases in interest expense of $0 , $5,779 and $6,327 for the years ended December 31, 2012 , 2011 and 2010 , respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges.

For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” below.

Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items



	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
	Fair Values					Fair Values
		December 31,					December 31,
	Balance Sheet Location	2012		2011		Balance Sheet Location	2012		2011
Derivatives designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	622	Fair value of derivatives	$	—	$	245
Total derivatives designated as hedging instruments		$	—	$	622		$	—	$	245

Derivatives not designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	117
Total derivatives not designated as hedging instruments		$	—	$	—		$	—	$	117

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



Effect of Derivative Instruments on the Consolidated Statement of Operations For the Years Ended December 31, 2012, 2011 and 2010
								Effective Portion									Ineffective Portion and Amount Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives							Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income								Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011		2010				2012		2011			2010				2012		2011		2010
Derivatives designated as hedging instruments:
Interest Rate contracts	$	—	$	—	$	(241	)	Interest Expense	$	—	$	(18	)	$	(4,210	)	Interest Expense	$	—	$	—	$	—
Commodity contracts	126		1,011		143			Income from Discontinued Operations	748		1,785			547			Income from Discontinued Operations	4		37		70
Total derivatives designated as hedging instruments	$	126	$	1,011	$	(98	)		$	748	$	1,767		$	(3,663	)		$	4	$	37	$	70



	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012		2011			2010
Derivatives not designated as hedging instruments:
Interest rate contracts	Interest expense	$	—	$	5,797		$	(2,117	)
Commodity contracts	Income from discontinued operations	1,623		(461		)	219
Total derivatives not designated as hedging instruments		$	1,623	$	5,336		$	(1,898	)

No amounts are expected to be reclassified into earnings for the subsequent 12 - month period for commodity cash flow hedges.

(13) Related Party Transactions

As of December 31, 2012 , Martin Resource Management owned 5,093,267 of the Partnership’s common units representing approximately 19.2% of the Partnership’s outstanding common limited partnership units. The Partnership’s general partner is a wholly-owned subsidiary of Martin Resource Management. The Partnership’s general partner owns a 2.0% general partner interest in the Partnership and the Partnership’s incentive distribution rights. The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of December 31, 2012 , of approximately 19.2% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

The following is a description of the Partnership’s material related party agreements:

Omnibus Agreement

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

100

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Non-Competition Provisions . Martin Resource Management has agreed for so long as it controls the general partner of the Partnership, not to engage in the business of:

• providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;

• providing marine transportation of petroleum products and by-products;

• distributing NGLs; and

• manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.

This restriction does not apply to:


•	the ownership and/or operation on the Partnership’s behalf of any asset or group of assets owned by it or its affiliates;


•	any business operated by Martin Resource Management, including the following:


◦	providing land transportation of various liquids;


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


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


◦	operating a small crude oil gathering business in Stephens, Arkansas;


◦	operating an underground NGL storage facility in Arcadia, Louisiana;


◦	operating an environmental consulting company;


◦	operating an engineering services company; and


◦	building and marketing sulfur processing equipment.


•	any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000 ;


•	any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 or more if the Partnership has been offered the opportunity to purchase the business for fair market value and the Partnership declines to do so with the concurrence of the conflicts committee; and

•

any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5,000 or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business.

Services. Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

Effective October 1, 2012, through December 31, 2013, the Conflicts Committee of the board of directors of the general partner of the Partnership (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses

101

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

of $10,622 , which will be effective for the 15 - month period. The Partnership reimbursed Martin Resource Management for $7,593 , $4,772 , and $3,791 of indirect expenses for the years ended December 31, 2012, 2011, and 2010, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

These indirect expenses are intended to cover the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the general partner of the Partnership.

Related Party Transactions . The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the conflicts committee of the Partnership's general partner. For purposes of the Omnibus Agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read “Services” above.

License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted the Partnership a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates.

Amendment and Termination . The Omnibus Agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the Conflicts Committee of the Partnership’s general partner if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. Such amendments were approved by the Conflicts Committee of the Partnership’s general partner. The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.

Motor Carrier Agreement

Motor Carrier Agreement. The Partnership is a party to a motor carrier agreement effective January 1, 2006 as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGL's as well as other liquid products.

Term and Pricing. The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one year 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 Partnership has the right to terminate this agreement at any time by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustments which are mutually agreed 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.

Marine Agreements

Marine Transportation Agreement . The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.

102

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil. Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement. The Partnership is a party to an agreement under which the Partnership provides terminal services to Martin Resource Management. This agreement was amended and restated as of October 27, 2004, and was set to expire in December 2006, but automatically renewed and will continue to automatically renew on a month-to-month basis until either party terminates the agreement by giving 60 days written notice. The per gallon throughput fee the Partnership charges under this agreement may be adjusted annually based on a price index.

Miscellaneous Terminal Services Agreements. The Partnership is currently party to several terminal services agreements and from time to time the Partnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.

Talen's Agreements . In connection with the Talen's acquisition, three new agreements were executed, all with effective dates of December 31, 2012. Under the terms of these contracts, Talen's provides terminal services and marine transportation services to Martin Resource Management.

Other Agreements

Cross Tolling Agreement. The Partnership is a party to an agreement with Cross, dated November 25, 2009, under which it processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The Tolling Agreement has a 22 year term which expires November 25, 2031. Under this Tolling Agreement, Martin Resource Management agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel. Any additional barrels are processed at a modified price per barrel. In addition, Martin Resource Management agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement . The Partnership is party to an agreement dated August 1, 2008 under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations. This agreement, as amended, will remain in place until the Partnership terminates it by providing 180 days’ written notice. Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.

The tables below summarize the related party transactions that are included in the related financial statement captions on the face of the Partnership’s Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the consolidated financial statement and do not reflect a statement of profits and losses for related party transactions.

The impact of related party revenues from sales of products and services is reflected in the consolidated financial statement as follows:

103

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



Revenues:	2012		2011		2010
Terminalling and storage	$	64,669	$	54,211	$	46,823
Marine transportation	17,494		23,478		28,194
Product sales:
Natural gas services	113		716		591
Sulfur services	6,022		8,151		7,146
Terminalling and storage	1,066		214		166
	7,201		9,081		7,903
	$	89,364	$	86,770	$	82,920

The impact of related party cost of products sold is reflected in the consolidated financial statement as follows:



Cost of products sold:
Natural gas services	$	27,512	$	16,749	$	7,517
Sulfur services	16,968		18,314		16,061
Terminalling and storage	48,375		45,089		32,489
	$	92,855	$	80,152	$	56,067

The impact of related party operating expenses is reflected in the consolidated financial statement as follows:



Operating expenses
Marine transportation	$	28,495	$	29,870	$	26,730
Natural gas services	1,855		1,590		1,349
Sulfur services	6,646		6,573		5,271
Terminalling and storage	21,838		20,018		15,040
	$	58,834	$	58,051	$	48,390

The impact of related party selling, general and administrative expenses is reflected in the consolidated financial statement as follows:



Selling, general and administrative:
Marine transportation	$	60	$	65	$	—
Natural gas services	2,498		1,069		1,048
Sulfur services	2,964		2,704		2,398
Terminalling and storage	563		—		—
Indirect overhead allocation, net of reimbursement	7,593		4,772		3,791
	$	13,678	$	8,610	$	7,237

(14) Long-Term Debt and Capital Leases

At December 31, 2012 and 2011 , long-term debt consisted of the following:

104

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



	2012		2011
$200,000 ** Senior notes, 8.875% interest, net of unamortized discount of $1,612 and $2,192, respectively, issued March 2010 and due April 2018, unsecured	$	173,388	$	197,808
$400,000 Revolving loan facility at variable interest rate (3.58%* weighted average at December 31, 2012), due April 2016 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees***	296,000		250,000
$3,315 Note payable to bank, interest rate at 4.75%, maturity date of October 2029, unsecured	2,971		—
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured by equipment	—		6,363
Capital lease obligations	5,839		6,031
Total long-term debt and capital lease obligations	478,198		460,202
Less current portion	3,206		1,261
Long-term debt and capital lease obligations, net of current portion	$	474,992	$	458,941

* Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25% . The applicable margin for existing LIBOR borrowings is 3.00% . Effective January 1, 2013, the applicable margin for existing LIBOR borrowings decreased to 2.25% . Effective April 1, 2013, the applicable margin for existing LIBOR borrowings will increase to 2.75% .

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

*** Effective October 2008, the Partnership entered into a cash flow hedge that swapped $40,000 of floating rate to fixed rate. The fixed rate cost was 2.82% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 2.58% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in October 2010, but were terminated in March 2010.

*** Effective January 2008, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to fixed rate. The fixed rate cost was 3.40% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 3.050% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges matured in January 2010.

*** Effective September 2007, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to fixed rate. The fixed rate cost was 4.61% plus the Partnership’s applicable LIBOR borrowing spread. Effective March 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 4.31% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in September 2010, but were terminated in March 2010.

*** Effective November 2006, the Partnership entered into an interest rate swap that swapped $30,000 of floating rate to fixed rate. The fixed rate cost was 4.77% plus the Partnership’s applicable LIBOR borrowing spread. This cash flow hedge matured in March 2010.

105

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

*** Effective March 2006, the Partnership entered into a cash flow hedge that swapped $75,000 of floating rate to fixed rate. The fixed rate cost was 5.25% plus the Partnership’s applicable LIBOR borrowing spread. Effective February 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 5.10% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in November 2010, but were terminated in March 2010.

**** Pursuant to the Indenture under which the Senior Notes were issued, the Partnership has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings. On April 24, 2012, the Partnership notified the Trustee of its intention to exercise a partial redemption of the Partnership’s Senior Notes pursuant to the Indenture. On May 24, 2012, the Partnership redeemed $25,000 of the Senior Notes from various holders using proceeds of the Partnership’s January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under the Partnership’s revolving credit facility. In conjunction with the redemption, the Partnership incurred a debt prepayment premium in the amount of $2,219 , which is included in the consolidated statement of operations for the year ended December 31, 2012.

(a) Senior Notes

In March 2010, the Partnership and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of the Partnership (collectively, the “Issuers”), entered into (i) a Purchase Agreement, dated as of March 23, 2010 (the “Purchase Agreement”), by and among the Issuers, certain subsidiary guarantors (the “Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets Corporation and UBS Securities, LLC, as representatives of a group of initial purchasers (collectively, the “Initial Purchasers”), (ii) an Indenture, dated as of March 26, 2010 (the “Indenture”), among the Issuers, the Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”) and (iii) a Registration Rights Agreement, dated as of March 26, 2010 (the “Registration Rights Agreement”), among the Issuers, the Guarantors and the Initial Purchasers, in connection with a private placement to eligible purchasers of $200,000 in aggregate principal amount of the Issuers’ 8.875% unsecured senior notes due 2018 (the “Senior Notes”). The Partnership completed the aforementioned Senior Notes offering on March 26, 2010, and received proceeds of approximately $197,200 , after deducting initial purchasers’ discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership’s revolving credit facility.

Indenture . On March 26, 2010, the Issuers issued the Senior Notes pursuant to the Indenture in a transaction exempt from registration requirements under the Securities Act. The Senior Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S under the Securities Act.

Interest and Maturity . The Senior Notes will mature on April 1, 2018. The interest payment dates are April 1 and October 1.

Optional Redemption . Prior to April 1, 2013, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the Senior Notes issued under the Indenture at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the Senior Notes with the proceeds of certain equity offerings. Prior to April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the 12-month period beginning on April 1, 2014, 102.219% for the 12-month period beginning on April 1, 2015 and 100.00% for the 12-month period beginning on April 1, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Senior Notes.

Certain Covenants . The Indenture restricts the Partnership’s ability and the ability of certain of its subsidiaries to: (i) sell assets including equity interests in its subsidiaries; (ii) pay distributions on, redeem or repurchase its units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to the Partnership; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate.

106

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Events of Default . The Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the Senior Notes; (ii) default in payment when due of the principal of, or premium, if any, on the Senior Notes; (iii) failure by the Partnership to comply with certain covenants relating to asset sales, repurchases of the Senior Notes upon a change of control and mergers or consolidations; (iv) failure by the Partnership for 180 days after notice to comply with its reporting obligations under the Securities Exchange Act of 1934; (v) failure by the Partnership for 60 days after notice to comply with any of the other agreements in the Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by the Partnership or any of its restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20,000 or more, subject to a cure provision; (vii) failure by the Partnership or any of its restricted subsidiaries to pay final judgments aggregating in excess of $20,000 , which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Issuers or any of the Partnership’s restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership. Upon a continuing Event of Default, the Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding Senior Notes, by notice to the Issuers and the Trustee, may declare the Senior Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, will automatically cause the Senior Notes to become due and payable.

Registration Rights Agreement. Under the Registration Rights Agreement, the Issuers and the Guarantors filed with the SEC a registration statement an offer to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. The Partnership exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018.

(b) Credit Facility

On November 10, 2005, the Partnership entered into a multi-bank $225,000 credit facility, which has subsequently been amended including most recently on May 10, 2012 (the “Credit Facility”), when the Partnership amended the Credit Facility to increase the maximum amount of borrowings and letters of credit available under the Credit Facility from $375,000 to $400,000 .

Under the Credit Facility, as of December, 2012, the Partnership had $296,000 outstanding under the revolving Credit Facility. As of December 31, 2012, irrevocable letters of credit issued under the Credit Facility totaled $120 . As of December 31, 2012, the Partnership had $103,880 available under its revolving Credit Facility. The Credit Facility is used for ongoing working capital needs and general partnership purposes and to finance permitted investments, acquisitions and capital expenditures. During the current fiscal year, draws on the Credit Facility ranged from a low of $35,000 to a high of $361,000 .

The Partnership’s obligations under the Credit Facility are secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time without penalty.

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

The Credit Facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio is 5.00 to 1.00 . The maximum

107

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

permitted senior leverage ratio (as defined in the Credit Facility but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.25 to 1.00 . The minimum consolidated interest coverage ratio (as defined in the Credit Facility but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.75 to 1.00 . The Partnership was in compliance with the covenants contained in the Credit Facility as of December 31, 2012.

The Credit Facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls the Partnership’s general partner, or if Ruben Martin is not the Chief Executive Officer of the Partnership’s general partner or a successor acceptable to the administrative agent and lenders providing more than 50% of the commitments under the Credit Facility is not appointed, the lenders under the Credit Facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under the Credit Facility if it is deemed to have a material adverse effect on the Partnership. Any event of default and corresponding acceleration of outstanding balances under the Credit Facility could require the Partnership to refinance such indebtedness on unfavorable terms and would have a material adverse effect on the Partnership’s financial condition and results of operations as well as its ability to make distributions to unitholders.

The Partnership is required to make certain prepayments under the Credit Facility. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the Credit Facility, it must prepay indebtedness under the Credit Facility with all such proceeds in excess of $15,000 . The Partnership must prepay revolving loans under the Credit Facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the Credit Facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the Credit Facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by April 15, 2016. 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.

In March 2010, the Partnership terminated all of its existing interest rate swaps resulting in termination fees of $3,850 . In August, 2011, the Partnership terminated all of its existing interest rate swap agreements with an aggregate notional amount of $100,000 , which it had entered to hedge its exposure to changes in the fair value of Senior Notes. These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings. The Partnership received a termination benefit of $2,800 upon cancellation of these swap agreements.

The Partnership paid cash interest in the amount of $29,239 , $22,818 , and $23,663 for the years ended December 31, 2012, 2011 and 2010, respectively. Capitalized interest was $1,136 , $624 , and $130 for the years ended December 31, 2012, 2011 and 2010, respectively.

(15) Equity Offerings

On November 26, 2012, the Partnership completed a public offering of 3,450,000 common units at a price of $31.16 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters’ discounts, commissions and offering expenses were $102,809 . The Partnership’s general partner contributed $2,194 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

On January 25, 2012, the Partnership completed a public offering of 2,645,000 common units at a price of $36.15 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91,361 . The Partnership’s general partner contributed $1,951 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

On February 9, 2011, the Partnership completed a public offering of 1,874,500 common units at a price of $39.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,874,500 common units, net of underwriters’ discounts, commissions and

108

offering expenses were $70,330 . The Partnership’s general partner contributed $1,505 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to reduce the outstanding balance under its revolving credit facility.

(16) Partners' Capital

As of December 31, 2012 , partners’ capital consists of 26,566,776 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owned 5,093,267 of the Partnership's common limited partnership units representing approximatley 19.2% of the Partnership's outstanding common limited partnership units and a 2% general partnership interest.

The Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

Distributions of Available Cash

The Partnership distributes all of its Available Cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

(17) Stanolind Tank Damage

During the third quarter of 2011, a single tank fire occurred at the Partnership’s Stanolind Terminal in Beaumont, Texas. This specific tank stores No. 6 oil for Martin Resource Management under a throughput agreement. The tank contained approximately 3,200 barrels of No. 6 oil at the time the incident occurred, all of which is the property of Martin Resource Management.

Physical damage to the Partnership’s asset caused by the fire as well as the related removal and recovery costs, are fully covered by the Partnership’s non-windstorm insurance policy subject to a deductible of $443 , which has been expensed and included in “operating expenses” in the consolidated statements of operations for the year ended December 31, 2011.

Insurance proceeds received as a result of the this claim will be used to replace the tank and, in the event the proceeds exceed the net book value of the tank that was destroyed, the Partnership will recognize a gain equal to the amount of the excess.

(18) Income Taxes

The operations of a partnership are generally not subject to income taxes because its income is taxed directly to its partners, except as discussed below.

The activities of the Blending and Packaging Assets prior to the acquisition by the Partnership were subject to federal and state income taxes. Accordingly, income taxes have been included in the Blending and Packaging Assets' operating results from January 1, 2010 through October 2, 2012. Related payables/receivables are included in Due to affiliates and Other current assets, respectively, on the consolidated balance sheet.

Woodlawn, a subsidiary of the Partnership, is subject to income taxes due to its corporate structure. The assets of Woodlawn were sold July 31, 2012 and the corporation was liquidated December 31, 2012 . Income tax expense related to Woodlawn is recorded in discontinued operations. A current federal income tax expense of $8,681 , $11 and $0 , related to the operation of the subsidiary, were recorded for the years ended December 31, 2012 , 2011 and 2010 , respectively.

The Partnership established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired Woodlawn assets and liabilities at the date of acquisition. The basis differences related primarily to property, plant

109

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

and equipment. A deferred tax benefit of $7,657 , $139 and $415 related to the Woodlawn basis differences was recorded for the years ended December 31, 2012 , 2011 and 2010 , respectively. A deferred tax expense of $402 , $622 , and $452 related to the Cross basis differences was recorded for the year ended December 31, 2012 , 2011 and 2010 , respectively. A deferred tax liability of $0 and $9,697 related to these basis differences existed at December 31, 2012 and 2011 , respectively. The deferred tax liability related to the Prism Assets was reversed upon the sale of those assets as discussed further in Note 5.

Effective January 1, 2007, the Partnership became subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the consolidated statements of operations. The Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $1,575 , $713 and $932 were recorded in income tax expense for the years ended December 31, 2012 , 2011 and 2010 , respectively.

An income tax liability of $10,239 , and $926 existed at December 31, 2012 and 2011 , respectively.

The components of income tax expense from operations recorded for the years ended December 31, 2012 , 2011 and 2010 are as follows:



	2012			2011		2010
Current:
Federal	$	10,516		$	1,303	$	1,043
State	1,894			975		1,145
	12,410			2,278		2,188
Deferred:
Federal	(7,255		)	483		37
Total income tax expense	$	5,155		$	2,761	$	2,225

Total income tax expense was allocated to continuing and discontinued operations as follows:

Income tax expense from continuing operations:



	2012		2011		2010
Current:
Federal	$	1,835	$	1,292	$	1,043
State	1,320		958		1,127
	3,155		2,250		2,170
Deferred:
Federal	402		622		452
Total income tax expense from continuing operations	$	3,557	$	2,872	$	2,622

Income tax expense (benefit) from discontinued operations:



	2012			2011			2010
Current:
Federal	$	8,681		$	11		$	0
State	574			17			18
	9,255			28			18
Deferred:
Federal	(7,657		)	(139		)	(415		)
Total income tax expense (benefit) from discontinued operations	$	1,598		$	(111	)	$	(397	)

110

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(19) Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

The accounting policies of the operating segments are the same as those described in Note 2 of the Notes to Consolidated Financial Statements. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all periods. See Note 5.



	Operating Revenues		Intersegment Eliminations			Operating Revenues After Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures

Year Ended December 31, 2012:
Terminalling and storage	$	322,175	$	(4,652	)	$	317,523	$	22,976	$	25,403		$	72,877
Natural gas services	825,506		—			825,506		601		15,395			434
Sulfur services	261,584		—			261,584		7,371		41,909			11,477
Marine transportation	88,815		(3,067		)	85,748		11,115		3,174			8,852
Indirect selling, general, and administrative	—		—			—		—		(12,046		)	—
Total	$	1,498,080	$	(7,719	)	$	1,490,361	$	42,063	$	73,835		$	93,640

Year Ended December 31, 2011:
Terminalling and storage	$	283,175	$	(4,414	)	$	278,761	$	19,814	$	20,619		$	48,287
Natural gas services	611,749		—			611,749		578		7,487			620
Sulfur services	275,044		—			275,044		6,725		34,595			16,158
Marine transportation	83,971		(7,035		)	76,936		13,159		(6,485		)	12,137
Indirect selling, general, and administrative	—		—			—		—		(8,864		)	—
Total	$	1,253,939	$	(11,449	)	$	1,242,490	$	40,276	$	47,352		$	77,202

Year Ended December 31, 2010:
Terminalling and storage	$	199,744	$	(4,354	)	$	195,390	$	17,330	$	20,034		$	8,656
Natural gas services	442,005		—			442,005		571		7,744			257
Sulfur services	165,078		—			165,078		6,262		20,166			7,107
Marine transportation	82,635		(4,993		)	77,642		12,721		6,524			2,159
Indirect selling, general, and administrative	—		—			—		—		(6,386		)	—
Total	$	889,462	$	(9,347	)	$	880,115	$	36,884	$	48,082		$	18,179

Revenues from one customer in the natural gas services segment were $150,246 , $137,177 and $92,265 for the years ended December 31, 2012 , 2011 and 2010 , respectively. Revenues from one customer in the sulfur services segment were $87,820 , $111,172 and $50,357 for the years ended December 31, 2012 , 2011 and 2010 , respectively.

111

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The Partnership's assets by reportable segment, which exclude assets held for sale of $212,787 as of December 31, 2011, are as follows:



	2012		2011
Total assets:
Terminalling and storage	$	376,330	$	282,106
Natural gas services	331,064		268,502
Sulfur services	155,639		162,289
Marine transportation	149,963		143,424
Total assets	$	1,012,996	$	856,321

(20) Quarterly Financial Information

Consolidated Quarterly Income Statement Information



	(Unaudited)
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2012
Revenues	$	348,326		$	333,844		$	354,091		$	454,100
Operating Income	19,781			19,215			16,245			18,594
Equity in earnings of unconsolidated entities	233			1,215			(678		)	(1,883		)
Income from continuing operations	10,742			8,461			8,743			9,176
Income from discontinued operations	1,725			1,984			63,603			(2,447		)
Net income	$	12,467		$	10,445		$	72,346		$	6,729
Limited partners' interest in net income per limited partner unit	$	0.40		$	0.25		$	3.07		$	0.27

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2011
Revenues	$	281,802		$	292,413		$	321,117		$	347,158
Operating Income	14,871			11,916			9,177			11,388
Equity in earnings of unconsolidated entities	(705		)	(1,368		)	(1,425		)	(1,254		)
Income from continuing operations	4,757			4,952			2,285			1,373
Income from discontinued operations	2,433			3,030			2,265			1,664
Net income	$	7,190		$	7,982		$	4,550		$	3,037
Limited partners' interest in net income per limited partner unit	$	0.31		$	0.37		$	0.20		$	0.06

(21) Commitments and Contingencies

From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.

On October 2, 2012, the Partnership announced that the ongoing litigation and disputes since May 2008 involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all the lawsuits and disputes. In connection with the settlement, Martin Resource Management transferred 1,500,000 common units of the Partnership to KCM, LLC.

(22) Condensed Consolidating Financial Information

112

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The Partnership has no significant operations independent of its subsidiaries. As of December 31, 2012, the Partnership's obligations under the outstanding Senior Notes (see Note 14) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than Redbird and MOP Midstream Holdings, LLC ("MMH"). Redbird is a holding company for the Partnership's investment in Cardinal. MMH is a holding company for the Partnership's investment in Caliber. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures. Separate financial statements for each of the Partnership's guarantor subsidiaries are not provided because such information would not be material to its investors or lenders. Neither the Parent nor Martin Midstream Finance Corp. (collectively, the "Co-Issuers") have independent assets or operations, therefore the Co-Issuers' financial information has been combined with the financial information of the guarantor subsidiaries. The tables below present condensed consolidating financial information for the Partnership and its combined guarantor subsidiaries, and combined non-guarantor subsidiaries as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.



Condensed Consolidating Balance Sheet
December 31, 2012

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Total current assets	$	552,282		$	—		$	(237,367	)	$	314,915
Property, plant and equipment, net	510,381			—			—			510,381
Investment in unconsolidated entities	—			154,309			—			154,309
Investment in subsidiary	(83,058		)	—			83,058			—
Total other assets	33,391			—			—			33,391
	$	1,012,996		$	154,309		$	(154,309	)	$	1,012,996

Liabilities and partners’ capital
Total current liabilities	$	178,482		$	237,367		$	(237,367	)	$	178,482
Long-term debt and capital leases, less current maturities	474,992			—			—			474,992
Other long-term obligations	1,560			—			—			1,560
Partners’ capital	357,962			(83,058		)	83,058			357,962
Total liabilities & partner's capital	$	1,012,996		$	154,309		$	(154,309	)	$	1,012,996



Condensed Consolidating Balance Sheet
December 31, 2011

	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets	$	579,196	$	—	$	(101,251	)	$	477,945
Property, plant and equipment, net	433,258		—		—			433,258
Investment in unconsolidated entities	—		132,605		—			132,605
Investment in subsidiary	124		—		(124		)	—
Total other assets	25,300		—		—			25,300
	$	1,037,878	$	132,605	$	(101,375	)	$	1,069,108

Liabilities and partners’ capital
Total current liabilities	$	262,195	$	101,251	$	(101,251	)	$	262,195
Long-term debt and capital leases, less current maturities	458,941		—		—			458,941
Other long-term obligations	10,785		—		—			10,785
Partners’ capital	305,957		31,354		(124		)	337,187
Total liabilities & partner's capital	$	1,037,878	$	132,605	$	(101,375	)	$	1,069,108

113

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



Condensed Consolidating Statements of Operations
Year ended December 31, 2012

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated

Total revenues	$	1,490,361		$	—		$	—	$	1,490,361
Total costs and expenses	1,416,108			—			—		1,416,108
Other operating (loss)	(418		)	—			—		(418		)
Operating income	73,835			—			—		73,835
Equity in (loss) of unconsolidated entities	—			(1,113		)	—		(1,113		)
Equity in (loss) of subsidiary	(627		)	—			627		—
Debt prepayment premium	(2,470		)	—			—		(2,470		)
Interest expense	(30,665		)	—			—		(30,665		)
Other, net	606			486			—		1,092
Net income before taxes	40,679			(627		)	627		40,679
Income tax (expense)	(3,557		)	—			—		(3,557		)
Income from continuing operations	37,122			(627		)	627		37,122
Income from discontinued operations, net of income taxes	64,865			—			—		64,865
Net income	$	101,987		$	(627	)	$	627	$	101,987



Condensed Consolidating Statements of Operations
Year ended December 31, 2011

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated

Total revenues	$	1,242,490		$	—		$	—	$	1,242,490
Total costs and expenses	1,196,464			—			—		1,196,464
Other operating income	1,326			—			—		1,326
Operating income	47,352			—			—		47,352
Equity in earnings (loss) of unconsolidated entities	—			(4,752		)	—		(4,752		)
Equity in net income of subsidiary	(4,752		)	—			4,752		—
Interest expense	(26,781		)	—			—		(26,781		)
Other, net	420			—			—		420
Net income before taxes	16,239			(4,752		)	4,752		16,239
Income tax (expense)	(2,872		)	—			—		(2,872		)
Income from continuing operations	13,367			(4,752		)	4,752		13,367
Income from discontinued operations, net of income taxes	9,392			—			—		9,392
Net income	$	22,759		$	(4,752	)	$	4,752	$	22,759

114

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



Condensed Consolidating Statements of Operations
Year ended December 31, 2010

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated

Total revenues	$	880,115		$	—	$	—		$	880,115
Total costs and expenses	832,261			—		—			832,261
Other operating income	228			—		—			228
Operating income	48,082			—		—			48,082
Equity in earnings of unconsolidated entities	—			2,536		—			2,536
Gain from ownership change in unconsolidated entity	—			6,413		—			6,413
Equity in net income of subsidiary	8,949			—		(8,949		)	—
Interest expense	(35,322		)	—		—			(35,322		)
Other, net	385			—		—			385
Net income before taxes	22,094			8,949		(8,949		)	22,094
Income tax (expense)	(2,622		)	—		—			(2,622		)
Income from continuing operations	19,472			8,949		(8,949		)	19,472
Income from discontinued operations, net of income taxes	8,061			—		—			8,061
Net income	$	27,533		$	8,949	$	(8,949	)	$	27,533



Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2012

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated

Net cash provided by operating activities	$	32,678		$	—		$	—		$	32,678
Net cash provided by (used in) investing activities	$	(96,803	)	$	(90,568	)	$	172,335		$	(15,036	)
Net cash provided by (used in) financing activities	$	69,021		$	90,568		$	(172,335	)	$	(12,746	)



Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2011

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated

Net cash provided by operating activities	$	91,362		$	—		$	—		$	91,362
Net cash used in investing activities	$	(202,655	)	$	(93,652	)	$	93,652		$	(202,655	)
Net cash provided by financing activities	$	100,179		$	93,652		$	(93,652	)	$	100,179

115

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2010

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated

Net cash provided by operating activities	$	39,178		$	—		$	—		$	39,178
Net cash used in investing activities	$	(91,016	)	$	(12,628	)	$	12,628		$	(91,016	)
Net cash provided by financing activities	$	57,262		$	12,628		$	(12,628	)	$	57,262

(23) Subsequent Events

NGL Marine Equipment Purchase. On February 28, 2013, the Partnership purchased from affiliates of Florida Marine Transporters, Inc. six liquefied petroleum gas pressure barges and two commercial push boats for approximately $50,800 . The purchase was funded with borrowings under the Partnership's revolving credit facility.

Issuance of Senior Notes. On February 11, 2013, the Partnership completed a private placement of $250.0 million in aggregate principal amount of 7.25% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. The Partnership received proceeds of approximately $245.1 million , after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership's revolving credit facility.

Quarterly Distribution. On January 24, 2013, The Partnership declared a quarterly cash distribution of $0.77 per common unit for the fourth quarter of 2012, or $3.08 per common unit on an annualized basis, which was paid on February 14, 2013 to unitholders of record as of February 7, 2013.

Common Unit Grants. On January 2, 2013, the Partnership issued 57,500 restricted common units under the Partnership's long-term incentive plan to the executive officers of the general partner and certain Martin Resource Management employees who provide services to the Partnership. These restricted units vest 100% on January 1, 2016.



Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.



Item 9A.	Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures . In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d)-15(e) of the Exchange Act) as of December 31, 2012. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of December 31, 2012.

(b) Management’s Report on Internal Control Over Financial Reporting . Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report appearing on page 74.

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There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.



Item 9B.	Other Information

None

117

PART III



Item 10.	Directors, Executive Officers and Corporate Governance

Management of Martin Midstream Partners L.P.

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

Three directors of our general partner serve on a Conflicts Committee to review specific matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards established by NASDAQ to serve on an audit committee of a board of directors ; provided, however that a director with a family member who is a partner with a foreign affiliate in the international cooperative of our registered independent public accounting firm shall be deemed to meet such independence standards if such director meets all other independence standards of NASDAQ and the board of our general partner affirmatively determines that such family relationship will not impair such director's independent judgment as a member of the Conflicts Committee. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The current members of our Conflicts Committee are outside directors, Joe N. Averett, Jr., C. Scott Massey and Charles H. Still, all of whom meet the independence standards established by NASDAQ, except as referenced above.

The Audit Committee reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. The current members of our Audit Committee are outside directors, C. Scott Massey, Byron R. Kelley and Charles H. Still, all of whom meet the independence standards established by NASDAQ.

The Compensation Committee oversees compensation decisions for the officers of our general partner as well as the compensation plans described below. The current members of our Compensation Committee are our outside directors, Joe N. Averett, Jr., C. Scott Massey, Byron R. Kelley and Charles H. Still.

The current members of our Nominating Committee are our outside directors, Joe N. Averett, Jr, Byron R. Kelley and Charles H. Still.

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. Directors and executive officers are elected for one-year terms.

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Name	Age	Position with the General Partner
Ruben S. Martin	61	President, Chief Executive Officer and Director
Robert D. Bondurant	54	Executive Vice President and Chief Financial Officer
Randall L. Tauscher	47	Executive Vice President and Chief Operating Officer
Wesley M. Skelton	65	Executive Vice President, Chief Administrative Officer and Controller
Chris Booth	43	Executive Vice President, General Counsel and Secretary
C. Scott Massey	60	Director
Joe N. Averett, Jr.	70	Director
Charles H. Still	70	Director
Byron R. Kelley	65	Director

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 holds a Bachelor of Science degree in industrial management from the University of Arkansas. Mr. Martin was selected to serve as a director on our general partner's board of directors due to his depth of knowledge of the Partnership, including its strategies, its operations, his business judgment and his position within the Partnership.

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 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.

Randall L. Tauscher serves as Executive Vice President and Chief Operating Officer of our general partner. Mr. Tauscher has served in this capacity since August 2011. From November 2007 through July 2011, Mr. Tauscher served as Executive Vice President. Prior to joining Martin, Mr. Tauscher was employed by Koch Industries for over 18 years, most recently as Senior Vice President of the Koch Carbon Division. Mr. Tauscher earned a Bachelor of Business Administration degree from Kansas State University.

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.

Chris Booth serves as Executive Vice President, General Counsel and Secretary of our general partner. Mr. Booth has served as an officer of our general partner since February 2006. Mr. Booth joined Martin Resource Management in October 2005. Prior to joining Martin Resource Management, Mr. Booth was an attorney with the law firm of Mehaffy Weber located in Beaumont, Texas. Mr. Booth holds a Doctor of Jurisprudence degree and a Masters of Business Administration degree with a concentration in finance from the University of Houston. Additionally, Mr. Booth holds a Bachelor of Science degree in business management from LeTourneau University. Mr. Booth is an attorney licensed to practice in the State of Texas.

C. Scott Massey serves as a member of the board of directors of our general partner. Mr. Massey has served as a Director since June 2002. Mr. Massey has been self employed as a Certified Public Accountant since 1998. From 1977 to 1998, Mr. Massey worked for KPMG Peat Marwick, LLP in various positions, including, most recently, as a Partner in the firm's Tax Practice - Energy, Real Estate, Timber from 1986 to 1998. Mr. Massey received a Bachelor of Business Administration degree from the University of Texas at Austin and a Doctor of Jurisprudence degree from the University of Houston. Mr. Massey is a Certified Public Accountant, licensed in the states of Louisiana and Texas. Mr. Massey was selected to serve as a director on our general partner's board of directors due to his extensive background in public accounting and taxation. Mr. Massey qualifies as an “audit committee financial expert” under the SEC guidelines.

Joe N. Averett, Jr . serves as a member of the board of directors of our general partner. Mr. Averett has served as a Director since June 2010. Mr. Averett has served as served on the board of directors of Penn Virginia Corporation and Capital

119

One Mutual Funds. He was the President and Chief Executive Officer of Crystal Gas Storage, Inc., a provider of natural gas storage, from 1985 to 2003. Prior to joining Crystal Gas Storage, Inc., Mr. Averett was the Chief Financial Officer of P&O Falco, Inc. and Langham Petroleum. Mr. Averett was also the Treasurer and Chief Financing Officer for the Pennzoil Company. Mr. Averett has also served in Washington, D.C., as the United States Presidential Executive in the Treasury Department, Office of the Secretary, tasked with economic policy. Mr. Averett holds a Bachelor of Business Administration degree in finance from Texas A&M University. Mr. Averett was selected to serve as a director on our general partner's board of directors due to his extensive business experience.

Charles H. Still serves as a member of the board of directors of our general partner. Mr. Still has served as a Director since July 2010. Currently, Mr. Still is of counsel with the law firm of Fulbright & Jaworski L.L.P. Mr. Still was an associate and partner in Fulbright & Jaworski L.L.P. from 1968 until his retirement in 2008. Mr. Still is currently on the board of directors of OYO Geospace Corporation. Mr. Still holds a Doctor of Jurisprudence degree from the University of Texas and a Bachelor of Business Administration in accounting from Texas Tech University. He is an Adjunct Professor of Law at the University of Texas. Mr. Still was selected to serve as a director on our general partner's board of directors due to his extensive corporate legal experience.

Byron R. Kelley serves as a member of the board of directors of our general partner and also served as an Advisory Director from April 2011 to August 2012. Mr. Kelley is currently CEO, President and a member of the board of directors of CVR Partners, LP, a chemical company engaged in the production of nitrogen based fertilizers. Prior to joining CVR Partners in June of 2011 he served as President, Chief Executive Officer and a member of the board of directors of Regency GP, LLC from April 2008 to November 2010. From 2004 through March of 2008, Mr. Kelley served as Senior Vice President and Group President of Pipeline and Field Services at CenterPoint Energy. Preceding his work at CenterPoint, Mr. Kelley served as Executive Vice President of Development, Operations and Engineering, and as President of El Paso Energy International. Mr. Kelley is a past member and Chairman of the board of directors of the Interstate National Gas Association and previously served as one of the association's representatives on the United States Natural Gas Council of America. Mr. Kelley received a Bachelor of Science degree in civil engineering from Auburn University. Mr. Kelley was selected to serve as a director on our general partner's board of directors due to his extensive corporate business experience.

Independence of Directors

Messrs. Massey, Still, Averett, and Kelley qualify as “independent” in accordance with the published listing requirements of NASDAQ and applicable securities laws. The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of us and has not engaged in various types of business dealings with us. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the directors reviewed and discussed information provided by the directors and us with regard to each director's business and personal activities as they may relate to us and our management.

Board Meetings and Committees

From January 1, 2012 to December 31, 2012, the board of directors of our general partner held 15 meetings. All directors then in office attended each of these meetings, either in person, by teleconference or by videoconference with the exception of Ruben S. Martin, who was not in attendance at the meeting of the board of directors on the date of June 13, 2012, and Joe N. Averett, Jr., who was not in attendance at the meeting of the board of directors on the date of July 27, 2012. Additionally, the board of directors undertook action one time during 2012 without a meeting by acting through written unanimous consent. We have standing conflicts, audit, compensation and nominating committees of the board of directors of our general partner. The board of directors of our general partner appoints the members of the Audit, Compensation, Nominating and Conflicts Committees. Each member of the Audit Committee is an independent director in accordance with NASDAQ and applicable securities laws. Each of the board committees has a written charter approved by the board. Copies of each charter are posted on our website at www.martinmidstream.com under the “Corporate Governance” section. The current members of the committees, the number of meetings held by each committee from January 1, 2012 to December 31, 2012, and a brief description of the functions performed by each committee are set forth below:

Conflicts Committee (12 meetings). The members of the Conflicts Committee are Messrs. Averett (chairman), Massey and Still. All of the members of the Conflicts Committee attended all meetings of the committee for the period noted above. The primary responsibility of the Conflicts Committee is to review matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or

120

employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by NASDAQ; provided, however that a director with a family member who is a partner with a foreign affiliate in the international cooperative of our registered independent public accounting firm shall be deemed to meet such independence standards if such director meets all other independence standards of NASDAQ and the board of our general partner affirmatively determines that such family relationship will not impair such director's independent judgment as a member of the Conflicts Committee. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

Audit Committee (4 meetings). Additionally, the Audit Committee undertook action one time during 2012 without a meeting by acting through written unanimous consent. The members of the Audit Committee are Messrs. Massey (chairman), Still and Kelley. All of the members attended all meetings of the Audit Committee for the period noted above. The primary responsibilities of the Audit Committee are to assist the board of directors in its general oversight of our financial reporting, internal controls and audit functions, and it is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors. The members of the Audit Committee of the board of directors of our general partner each qualify as “independent” under standards established by the SEC for members of Audit Committees, and the Audit Committee includes at least one member who is determined by the board of directors to meet the qualifications of an “audit committee financial expert” in accordance with SEC rules, including that the person meets the relevant definition of an “independent” director. C. Scott Massey is the independent director who has been determined to be an audit committee financial expert. Unitholders should understand that this designation is a disclosure requirement of the SEC related to Mr. Massey's experience and understanding with respect to certain accounting and auditing matters. The designation does not impose on Mr. Massey any duties, obligations or liability that are greater than are generally imposed on him as a member of the Audit Committee and board of directors, and his designation as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the Audit Committee or board of directors.

Compensation Committee (3 meetings). The members of the Compensation Committee are Messrs. Kelley (chairman), Massey, Still and Averett. All of the members attended all meetings of the Compensation Committee for the period noted above. The primary responsibility of the Compensation Committee is to oversee compensation decisions for the outside directors of our general partner and executive officers of our general partner (in the event they are to be paid by our general partner) as well as our long-term incentive plan.

Nominating Committee (2 meetings). The members of the nominating committee are Messrs. Still (chairman), Averett and Kelley. All of the members attended all meetings of the Compensation Committee for the period noted above. The primary responsibility of the nominating committee is to select and recommend nominees for election to the board of directors of our general partner.

Code of Ethics and Business Conduct

Our general partner has adopted a Code of Ethics and Business Conduct applicable to all of our general partner's employees (including any employees of Martin Resource Management who undertake actions with respect to us or on our behalf), including all officers, and including our general partner's independent directors, who are not employees of our general partner, with regard to their activities relating to us. The Code of Ethics and Business Conduct incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. They also incorporate our expectations of our general partner's employees (including any employees of Martin Resource Management who undertake actions with respect to us or on our behalf) that enable us to provide accurate and timely disclosure in our filings with the Securities and Exchange Commission and other public communications. The Code of Ethics and Business Conduct is publicly available on our website under the “Corporate Governance” section (at www.martinmidstream.com). This website address is intended to be an inactive, textual reference only, and none of the material on this website is part of this report. If any substantive amendments are made to the Code of Ethics and Business Conduct or if we or our general partner grant any waiver, including any implicit waiver, from a provision of the code to any of our general partner's executive officers and directors, we will disclose the nature of such amendment or waiver on that website or in a report on Form 8-K.

Section 16(a) Beneficial Ownership Reporting Compliance

Our general partner's directors and officers and beneficial owners of more than 10% of a registered class of our equity securities are required to file reports of ownership and reports of changes in ownership with the SEC and NASDAQ. Directors, officers and beneficial owners of more than 10% of our equity securities are also required to furnish us with copies of all such

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reports that are filed. Based solely on our review of copies of such forms and amendments, we believe directors, officers and greater than 10% beneficial owners complied with all filing requirements during the year ended December 31, 2012.

Reimbursement of Expenses of our General Partner

Our general partner does not receive a management fee or other compensation for its management of our partnership. However, our general partner and its affiliates are reimbursed for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We reimbursed Martin Resource Management for $157.8 million of direct costs and expenses for the twelve months ended December 31, 2012 compared to $142.0 million for the twelve months ended December 31, 2011. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

Indirect general and administrative and corporate overhead costs relate to centralized corporate functions that we share with Martin Resource Management, including certain accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other corporate services. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2012, 2011 and 2010, the Conflicts Committee of our general partner approved reimbursement amounts of $7.6, $4.8 and $3.8 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence — Agreements — Omnibus Agreement.”



Item 11.	Executive Compensation

Compensation Discussion and Analysis

Background

We are required to provide information regarding the compensation program in place as of December 31, 2012, for the CEO, CFO and the three other most highly-compensated executive officers of our general partner as reflected in the summary compensation table set forth below (the “Named Executive Officers”). This section should be read in conjunction with the detailed tables and narrative descriptions regarding compensation below.

We are a master limited partnership and have no employees. We are managed by the executive officers of our general partner. These executive officers are employed by Martin Resource Management, a private corporation that has significant operations that are separate from ours. The executive officers of our general partner are also the executive officers of Martin Resource Management and devote significant time to the management of Martin Resource Management’s operations. We reimburse Martin Resource Management for a portion of the indirect general and administrative expenses, including compensation expense relating to the service of these individuals that are allocated to us pursuant to the omnibus agreement between us and our general partner, as amended on October 1, 2012 ("Omnibus Agreement"). Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2012, 2011 and 2010, the Conflicts Committee of our general partner approved reimbursement amounts of $7.6, $4.8 and $3.8 million, respectively, reflecting our allocable share of such expenses. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Agreements — Omnibus Agreement” for a discussion of the Omnibus Agreement.

Compensation Objectives

As we do not directly compensate the executive officers of our general partner, we do not have any set compensation programs. The elements of Martin Resource Management’s compensation program discussed below, along with Martin Resource Management’s other rewards, are intended to provide a total rewards package designed to yield competitive total cash compensation, drive performance and reward contributions in support of the businesses of Martin Resource Management and other Martin Resource Management affiliates, including us, for which the Named Executive Officers perform services. Although we bear an allocated portion of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers, we do not have control over such costs and do not establish or direct the compensation policies or

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practices of Martin Resource Management. During 2012, Martin Resource Management paid compensation based on the performance of Martin Resource Management but did not set any specific performance-based criteria and did not have any other specific performance-based objectives.

Elements of Compensation

Martin Resource Management’s executive officer compensation package includes a combination of annual cash, long-term incentive compensation and other compensation. Elements of compensation which to the Named Executive Officers may be eligible to receive from Martin Resource Management consist of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to Martin Resource Management employee benefit plans and (4) where appropriate, other compensation, including limited perquisites.

Annual Base Salary . Base salary is intended to provide fixed compensation to the Named Executive Officers for their performance of core duties with respect to Martin Resource Management and its affiliates, including us, and to compensate for experience levels, scope of responsibility and future potential. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance. The base salaries of the Named Executive Officers are reviewed on an annual basis, as well as at the time of promotion and other changes in responsibilities or market conditions.

Discretionary Annual Cash Awards. In addition to the annual base salary, the Named Executive Officers may be eligible to receive discretionary annual cash awards that, if awarded, are paid in a lump sum near the end of the fiscal year. These cash awards are designed to provide the Named Executive Officers with competitive incentives to help drive performance and promote achievement of Martin Resource Management’s business objectives. Named Executive Officers may also be eligible to receive a cash award based upon their services provided to us in the event that any such Named Executive Officer has devoted a significant amount of their time to working for us. Any such award is determined in accordance with the same methodologies as the discretionary annual cash awards for Martin Resource Management, as described below.

Employee Benefit Plan Awards. The Named Executive Officers may be eligible to receive awards pursuant to Martin Midstream Partners L.P. Long-Term Incentive Plan and Martin Resource Management employee benefit plans. These employee benefit plan awards are designed to reward the performance of the Named Executive Officers by providing annual incentive opportunities tied to the annual performance of Martin Resource Management. In particular, these awards are provided to the Named Executive Officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of the business objectives of Martin Resource Management.

Other Compensation. Martin Resource Management generally does not pay for perquisites for any of the Named Executive Officers, other than general recreational activities at certain Martin Resource Management’s properties located in Texas, including aircraft. No perquisites are paid for services rendered to us. Martin Resource Management provides an executive life insurance policy and long term disability policy for the Named Executive Officers with the annual premiums being paid by Martin Resource Management. Martin Resource Management does not provide any greater allocation toward employee health insurance premiums than is provided for all other employees covered on the health benefits plan.

Compensation Methodology

The compensation policies and philosophy of Martin Resource Management govern the types and amount of compensation granted to each of the Named Executive Officers. The board of directors and Conflicts Committee of our general partner do have responsibility for evaluating and determining the reasonableness of the total amount we are charged under the Omnibus Agreement for managerial, administrative and operational support, including compensation of the Named Executive Officers, provided by Martin Resource Management.

Our allocation for the costs incurred by Martin Resource Management in providing compensation and benefits to its employees who serve as the Named Executive Officers is governed by the Omnibus Agreement. In general, this allocation is based upon estimates of the relative amounts of time that these employees devote to the business and affairs of our general partner and to the business and affairs of Martin Resource Management. We bear substantially less than a majority of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers.

When setting compensation for the Named Executive Officers, the elements of compensation above are considered holistically to provide an appropriate combination of compensation. Annual base salaries are determined by the Compensation Committee of Martin Resource Management following an individual performance review of each Named Executive Officer. Further, Martin Resource Management, with the approval of Mr. Ruben Martin, the Chief Executive Officer of Martin Resource Management, normally reviews market data and relevant compensation surveys when setting base compensation and,

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when appropriate, engages compensation consultants. Except in the case of an exceptional amount of time devoted to us, discretionary annual cash awards are based on the performance of Martin Resource Management. Annual discretionary cash awards, if any, are calculated first by allocating a portion of Martin Resource Management’s earnings as determined by Martin Resource Management’s Compensation Committee for distribution to key employees of Martin Resource Management. Upon such allocation, Mr. Martin with input from appropriate business leaders determines the allocation and distribution of the bonus pool among such employees, including the Named Executive Officers. With respect to employee benefit plan awards, Mr. Martin makes a recommendation to the Compensation Committee of Martin Resource Management as to whether such awards should be awarded to any employees. Any such employee plan awards are then approved by the Compensation Committee and distributed to the employees, including Named Executive Officers, accordingly.

Any awards granted under our long-term incentive plan, which to date have consisted of the grant of restricted common units to the independent directors and employees of our general partner, are approved by the Compensation Committee.

The Named Executive Officers who serve on the Compensation Committee of Martin Resource Management play a role in setting the compensation as base salaries, discretionary annual cash awards and employee benefit awards are set by that committee. Current members of the Martin Resource Management Compensation Committee are Mr. Ruben Martin, Chief Executive Officer, Mr. Robert Bondurant, Chief Financial Officer, Mr. Randall Tauscher, Chief Operating Officer, Mr. Wesley Skelton, Chief Administrative Officer and Controller and Mrs. Melanie Mathews, Vice President-Human Resources. Further, as is explained above, Mr. Martin, as Chief Executive Officer, also has significant authority in setting base salaries, discretionary annual cash award allocations and amounts and employee benefit award distributions.

Determination of 2012 Compensation Amounts

During 2012, elements of all compensation paid to the Named Executive Officers by Martin Resource Management consisted of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to Martin Resource Management employee benefit plans; and (4) other compensation, including limited perquisites. With respect to the Named Executive Officers, they were paid an allocated portion of their base salaries and in one case, a cash award, based upon their service to us.

Annual Base Salary. The portions of the annual base salaries paid by Martin Resource Management to the Named Executive Officers, which are allocable to us under our Omnibus Agreement with Martin Resource Management, are reflected in the summary compensation table below. Based upon the agreement of our general partner with Martin Resource Management, we have reimbursed Martin Resource Management for approximately 42.0% of the aggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management during 2012. The foregoing agreement has been developed based on an assessment of the estimated percentage of the time spent by the Named Executive Officers managing our affairs, relative to the affairs of Martin Resource Management ranging from approximately 30% to 67%. Our Named Executive Officers are Mr. Ruben Martin, the President and Chief Executive Officer of our general partner, Mr. Robert Bondurant, an Executive Vice President and Chief Financial Officer of our general partner, Mr. Wesley Skelton, an Executive Vice President, Controller and Chief Administrative Officer of our general partner, Mr. Randall Tauscher, an Executive Vice President and Chief Operating Officer of our general partner and Mr. Chris Booth, the Executive Vice President, General Counsel and Secretary of our general partner. Annual base salaries of the Named Executive Officers were increased during 2012 by Martin Resource Management by 3%.

Discretionary Annual Cash Awards. Discretionary annual cash awards paid to the Named Executive Officers which are allocable to us are reflected in the summary compensation table below.

Employee Benefit Plan Awards and Other Compensation. No employee benefit plan awards or other compensation were granted to the Named Executive Officers in 2012 based upon their service to us.

Martin Midstream Partners L.P. Long-Term Incentive Plan

Our general partner has adopted the Martin Midstream Partners L.P. Long-Term Incentive Plan ("LTIP") for employees and directors of our general partner and its affiliates who perform services for us. The LTIP was amended in January 2006 to clarify the Partnership’s ability to grant restricted common units under the LTIP and to remove provisions relating to grants of distribution equivalent rights and phantom units.

The LTIP consists of two components, restricted units and unit options. The LTIP currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333

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of which may be awarded in the form of unit options. The plan is administered by the Compensation Committee of our general partner’s board of directors.

Our general partner’s board of directors or the Compensation Committee, in their discretion, may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or the Compensation Committee also have the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be reserved for issuance under the plan subject to any applicable unitholder approval. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

Restricted Units. A restricted unit is a unit that is granted to grantees with certain vesting restrictions. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. A phantom unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine under the plan. The Compensation Committee will determine the period over which restricted units or phantom units granted to employees and directors will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units or phantom units will vest upon a change of control of us, our general partner or Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management.

If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted units or phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of restricted units or phantom units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any affiliate of our general partner or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units or phantom units, the total number of common units outstanding will increase.

We intend the issuance of the common units upon vesting of the restricted units or phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

On April 30, 2012, we issued 1,250 restricted common units to each of our four non-employee directors under our LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2013, 2014 2015, and 2016.

On May 2, 2011, we issued 1,250 restricted common units to a non-employee advisory director under our LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015.

On February 28, 2011, we issued 1,250 restricted common units to each of four non-employee directors under our LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015.

On August 2, 2010, we issued 1,500 restricted common units to each of two new independent, non-employee directors under our LTIP. These restricted common units vest in equal installments of 375 units on January 24, 2011, 2012, 2013 and 2014, respectively.

On May 3, 2010, we issued 1,000 restricted common units to each of our three independent, non-employee directors under our LTIP. These restricted common units vest in equal installments of 250 units on January 24, 2011, 2012, 2013 and 2014, respectively.

On August 3, 2009, we issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan from treasury shares purchased by us in the open market for $78. These units vest in 25% increments beginning in January 2010 and will be fully vested in January 2013.

On May 5, 2008, we issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan from treasury shares purchased by us in the open market for $93. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.

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Unit Options. The LTIP currently permits the grant of options covering common units. As of March 4, 2013, we have not granted any common unit options to directors or employees of our general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, in the discretion of the committee, may not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner, Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.

Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any affiliate of our general partner or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will pay us the proceeds it received from the optionee.

Martin Resource Management Employee Benefit Plans

Martin Resource Management has employee benefit plans for its employees who perform services for us. The following summary of these plans is not complete but outlines the material provisions of these plans.

Martin Resource Management Purchase Plan for Units of Martin Midstream Partners L.P . Martin Resource Management maintains a purchase plan for our Units to provide employees of Martin Resource Management and its affiliates who perform services for us the opportunity to acquire an equity interest in us through the purchase of our common units. Each individual employed by Martin Resource Management or an affiliate of Martin Resource Management that provides services to us is eligible to participate in the purchase plan. Enrollment in the purchase plan by an eligible employee will constitute a grant by Martin Resource Management to the employee of the right to purchase common units under the purchase plan. The right to purchase common units granted by the Company under the purchase plan is for the term of a purchase period.

During each purchase period, each participating employee may elect to make contributions to his bookkeeping account each pay period in an amount not less than one percent of his compensation and not more than fifteen percent of his compensation. The rate of contribution shall be designated by the employee at the time of enrollment. On each purchase date (the last day of such purchase period), Units will be purchased for each participating employee at the fair market value of such Units. The fair market value of the Units to be purchased during such purchase period shall mean the closing sales price of a Unit on the purchase date.

Martin Resource Management Employee Stock Ownership Plan. Martin Resource Management maintains an employee stock profit sharing plan that covers employees who satisfy certain minimum age and service requirements (“ESOP”). Under the terms of the ESOP, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the ESOP and invested primarily in the common stock of Martin Resource Management. Participants in the Martin ESOP become 100% vested upon completing six years of vesting service or upon their attainment of normal retirement age, permanent disability or death during employment. Any forfeitures of non-vested accounts may be used to pay administrative expenses and restore previous forfeitures of employees rehired before incurring five consecutive breaks-in-service. Any remaining forfeitures will be allocated to the accounts of employed participants. Participants are not permitted to make contributions including rollover contributions to the ESOP.

Martin Resource Management Employees' Stock Profit Sharing Plan. Martin Resource Management maintains an employee stock profit sharing plan that covers employees who satisfy certain minimum age and service requirements. This employee stock ownership plan is referred to as the “Martin Employees' Stock Profit Sharing Plan.” Under the terms of the plan, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the Martin Employees’ Stock Profit Sharing Plan and invested primarily in the common stock of Martin Resource Management. Participants in the Martin Employees’ Stock Profit Sharing Plan become 100% vested upon completing three years of vesting service or upon their attainment of age 65, permanent disability or death during employment. Any forfeitures of non-vested accounts are allocated to the accounts of employed participants. Except for rollover contributions, participants are not permitted to make contributions to the Martin Employees’ Stock Profit Sharing Plan.

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Martin Resource Management 401(k) Profit Sharing Plan. Martin Resource Management maintains a profit sharing plan that covers employees who satisfy certain minimum age and service requirements. This profit sharing plan is referred to as the “401(k) Plan.” Eligible employees may elect to participate in the 401(k) Plan by electing pre-tax contributions up to 30% of their regular compensation and/or a portion of their discretionary bonuses. Matching contributions are made to the 401(k) Plan equal to 100% of the first 3% of eligible compensation, and 50% of the next 2% of eligible compensation. Martin Resource Management may make annual discretionary profit sharing contributions in an amount at the plan year end as determined by the board of directors of Martin Resource Management. Participants in the 401(k) Plan become 100% vested in matching contributions immediately and become vested in the discretionary contributions made for them upon completing five years of vesting service or upon their attainment of age 65, permanent disability or death during employment.

Martin Resource Management Non-Qualified Option Plan. In September 1999, Martin Resource Management adopted a stock option plan designed to retain and attract qualified management personnel, directors and consultants. Under the plan, Martin Resource Management is authorized to issue to qualifying parties from time to time options to purchase up to 2,000 shares of its common stock with terms not to exceed ten years from the date of grant and at exercise prices generally not less than fair market value on the date of grant. In November 2007, Martin Resource Management adopted an additional stock option plan designed to retain and attract qualified management personnel, directors and consultants.

Other Compensation

Martin Resource Management generally does not pay for perquisites for any of our named executive officers other than general recreational activities at certain Martin Resource Management’s properties located in Texas and use of Martin Resource Management vehicles, including aircraft.

SUMMARY COMPENSATION TABLE

The following table sets forth the compensation expense that was allocated to us for the services of the named executive officers for the years ended December 31, 2012, 2011 and 2010.



Name and Principal Position	Year	Salary ($)		Bonus ($)		Total Compensation
Ruben S. Martin, President and Chief Executive Officer	2012	$	283,593	$	—	$	283,593
	2011	$	124,371	$	—	$	124,371
	2010	$	100,099	$	—	$	100,099
Robert D. Bondurant, Executive Vice President and Chief Financial Officer	2012	$	151,307	$	—	$	151,307
	2011	$	125,761	$	—	$	125,761
	2010	$	53,857	$	—	$	53,857
Randall L. Tauscher, Executive Vice President and Chief Operating Officer	2012	$	224,502	$	—	$	224,502
	2011	$	210,548	$	—	$	210,548
	2010	$	163,644	$	107,500	$	271,144
Wesley M. Skelton, Executive Vice President, Controller and Chief Administrative Officer	2012	$	133,380	$	—	$	133,380
	2011	$	124,371	$	—	$	124,371
	2010	$	117,404	$	—	$	117,404
Donald R. Neumeyer, Former Executive Vice President(1)	2012 (1)	$	72,363	$	—	$	72,363
	2011	$	75,211	$	—	$	75,211
	2010	$	52,653	$	—	$	52,653
Chris H. Booth, Executive Vice President, General Counsel and Secretary	2012	$	94,755	$	—	$	94,755
	2011	$	88,814	$	—	$	88,814
	2010	$	86,830	$	—	$	86,830

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(1) Represents salary earned through date of resignation on October 31, 2012.

Director Compensation

As a partnership, we are managed by our general partner. The board of directors of our general partner performs for us the functions of a board of directors of a business corporation. Directors of our general partner are entitled to receive total quarterly retainer fees of $12,500 each which are paid by the general partner. Martin Resource Management employees who are a member of the board of directors of our general partner do not receive any additional compensation for serving in such capacity. Officers of our general partner who also serve as directors will not receive additional compensation. All directors of our general partner are entitled to reimbursement for their reasonable out-of-pocket expenses in connection with their travel to and from, and attendance at, meetings of the board of directors or committees thereof. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

The following table sets forth the compensation of our board members for the period from January 1, 2012 through December 31, 2012.



Name	Fees Earned Paid in Cash ($)		Stock Awards ($)		Total ($)
Ruben S. Martin	N/A		N/A		N/A
C. Scott Massey (2)	$	50,000	$	44,000	$	94,000
Howard Hackney (1) (2)	$	37,500	$	44,000	$	81,500
Joe N. Averett, Jr. (2)	$	50,000	$	44,000	$	94,000
Charles H. “Hank” Still (2)	$	50,000	$	44,000	$	94,000
Byron R. Kelley (2)	$	50,000	$	44,000	$	94,000

(1) Represents fees paid to Howard Hackney through his date of resignation on July 30, 2012.

(2) On April 30, 2012, the Partnership issued 1,250 restricted common units to each of five non-employee directors, C. Scott Massey, Howard Hackney, Joe N. Averett, Jr., Byron R. Kelley, and Charles H. “Hank” Still, under our LTIP. These restricted common units vest in equal installments of 312.5 units on January 24, 2013, 2014, 2015 and 2016, respectively. In calculating the fair value of the award, we multiplied the closing price of our common units on the NASDAQ on the date of grant, April 30, 2012, by the number of restricted common units granted to each director.

COMPENSATION REPORT OF THE COMPENSATION COMMITTEE

The Compensation Committee of the general partner of Martin Midstream Partners L.P. has reviewed and discussed the Compensation Discussion and Analysis section of this report with management of the general partner of Martin Midstream Partners L.P. and, based on that review and discussions, has recommended that the Compensation Discussion and Analysis be included in this report.

Members of the Compensation Committee:

Byron R. Kelley, Committee Chair

Joe N. Averett Jr.

C. Scott Massey

Charles H. Still

Compensation Committee Interlocks and Insider Participation

Other than these independent directors, no other officer or employee of our general partner or its subsidiaries is a member of the Compensation Committee. Employees of Martin Resource Management, through our general partner, are the individuals who work on our matters.

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Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the beneficial ownership of our units as of March 4, 2013 held by beneficial owners of 5% or more of the units outstanding, by directors of our general partner, by each executive officer and by all directors and executive officers of our General Partner as a group.



Name of Beneficial Owner(1)	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned(2)
Martin Resource Management Corporation(3)	5,093,267		19.1%
Martin Resource, LLC(3)	4,203,823		15.8%
Cross Oil Refining & Marketing Inc.(3)	889,444		3.3%
Ruben S. Martin(4)	5,163,288	5,162,873	19.4%
Wesley M. Skelton	6,624		—
Robert D. Bondurant	16,010		—
Chris Booth	4,207		—
Randall Tauscher	12,132		—
C. Scott Massey(5)(6)	15,500		—
Joe N. Averett, Jr.(5)(6)	9,000		—
Charles H. Still((5)6)	6,000		—
Byron R. Kelley(5)(6)	2,500		—
All directors and executive officers as a group (9 persons)(6)	5,235,261		19.7%


(1)	The address for Martin Resource Management Corporation and all of the individuals listed in this table, unless otherwise indicated, is c/o Martin Midstream Partners L.P., 4200 Stone Road, Kilgore, Texas 75662.


(2)	The percent of class shown is less than one percent unless otherwise noted.

(3)

Martin Resource Management is the owner of Martin Resource, LLC and Cross Oil Refining & Marketing Inc., and as such may be deemed to beneficially own the common units held by Martin Resource LLC and Cross Oil Refining & Marketing Inc. The 4,203,823 common units beneficially owned by Martin Resource Management through its ownership of Martin Resource, LLC have been pledged as security to a third party to secure payment for a loan made by such third party. The 889,444 common units beneficially owned by Martin Resource Management through its ownership of Cross Oil Refining & Marketing Inc. have been pledged as security to a third party to secure payment for a loan made by such third party.

(4)

Includes 5,093,267 common units beneficially owned by Martin Resource Management through its ownership of Martin Resource, LLC and Cross Oil Refining & Marketing, Inc. Ruben S. Martin beneficially owns securities in Martin Resource Management representing approximately 19.4% of the voting stock thereof and serves as its Chairman of the Board and President. As a result, Ruben S. Martin may be deemed to be the beneficial owner of the common units and the subordinated units owned by Martin Resource Management.


(5)	On April 30, 2012, we issued 1,250 restricted common units to each of five non-employee directors under our long-term incentive plan. These restricted common units vest in equal installments of 312.5 units on January 24, 2013, 2014 2015, and 2016.

On May 2, 2011, we issued 1, 250 restricted common units to a non-employee advisory director. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.

On May 2, 2011, we issued 1,250 restricted common units to each of four non-employee directors. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.

On August 2, 2010, we issued 1,500 restricted common units to each of two new non -employee directors. These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.

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On May 3, 2010, we issued 1,000 restricted common units to each of its non-employee directors. These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.

On August 3, 2009, we issued 1,000 restricted common units to each of our three independent directors. These units vest in 25% increments beginning in January 2010 and will be fully vested in January 2013.

On May 5, 2008, we issued 1,000 restricted common units to each of our three independent directors. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.

On May 3, 2007, we issued 1,000 restricted common units to each of our three independent directors. These units vest in 25% increments beginning in January 2008 and were fully vested in January 2011.

On January 24, 2006, we issued 1,000 restricted common units to each of our three independent directors. These units vest in 25% increments beginning in January 2007 and were fully vested in January 2010.

Mr. Massey may be deemed to be the beneficial owner of 1,000 common units held by his wife.


(6)	The total for all directors and executive officers as a group includes the common units directly owned by such directors and executive officers as well as the common units beneficially owned by Martin Resource Management as Ruben S. Martin may be deemed to be the beneficial owner thereof.

Martin Resource Management owns our general partner and, together with our general partner, owns approximately 19.1% of our outstanding common limited partner units as of March 4, 2013. The table below sets forth information as of March 4, 2013 concerning (i) each person owning beneficially in excess of 5% of common stock of Martin Resource Management, and (ii) the beneficial common stock ownership of (a) each director of Martin Resource Management, (b) each executive officer of Martin Resource Management, and (c) all such executive officers and directors of Martin Resource Management as a group. Except as indicated, each individual has sole voting and investment power over all shares listed opposite his or her name.



	Beneficial Ownership of Common Stock
Name of Beneficial Owner(1)	Number of Shares	Percent of Outstanding
Martin Employees' Stock Profit Sharing Trust (2)	48,050.00	26.6	%
Martin Resource Management ESOP Trust (3)	95,112.50	37.0	%
Wilmington Trust Retirement and Institutional Services Company (3)	95,112.50	37.0	%
CNRT, LLC (4)	56,666.67	31.4	%
RSM III Investments, Ltd. (5).	56,666.67	31.4	%
Ruben S. Martin III Dynasty Trust (6)	16,000.00	8.9	%
Martin Transport, Inc. (7)	1,000.00	*
Ruben S. Martin (4) (7) (8)	62,300.00	34.5	%
Wesley M. Skelton (2) (9) (10) (11)	50,750.00	28.1	%
Robert D. Bondurant(9) (10) (11)	5,000.00	2.8	%
Randall L. Tauscher (9)(11)	2,125.00	1.2	%
Executive officers and directors as a group (4 individuals)	120,175.00	66.5	%

* Represents less than 1.0%


(1)	The business address of each shareholder, director and executive officer of Martin Resource Management Corporation is c/o Martin Resource Management Corporation, 4200 Stone Road, Kilgore, Texas 75662.


(2)	Wesley M. Skelton is a co-trustee of the Martin Employees' Stock Profit Sharing Trust and exercises shared control over the voting and disposition of the securities owned by this trust. As a result, he may be deemed to be the beneficial owner of the securities held by such trust; thus, the number of shares of common stock reported herein as

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beneficially owned by him includes the 48,050 shares owned by such trust. Mr. Skelton disclaims beneficial ownership of these 48,050 shares.

(3)

Wilmington Trust Retirement and Institutional Services Company ("Wilmington") is the trustee of the Martin Resource Management ESOP Trust and exercises control over the voting and disposition of the securities owned by this trust. As a result, Wilmington may be deemed to be the beneficial owner of the securities held by such trust; thus, the number of shares of common stock reported herein as beneficially owned by Wilmington includes the 18,450 shares owned by such trust. The trust also owns 76,662.50 convertible preferred shares which may be converted into common shares on a one-to-one basis at any time and thus, the number of shares of preferred stock reported herein as beneficially owned by Wilmington includes the preferred shares owned by such trust. Wilmington disclaims beneficial ownership of these 95,112.50 shares.

(4)

Ruben S. Martin is the president of RSM III Management Corp., which is the general partner of RSM III Investments Ltd., which is the sole member of CNRT, LLC. Courtney Stovall and Robin Martin, as managers of CNRT, LLC exercise control over the voting of the securities owned by this entity. However, as a result of his position with the general partner of the sole member of this entity, Ruben S. Martin may be deemed to be the beneficial owner of the securities held by such entity; thus, the number of shares of common stock reported herein as beneficially owned by such individual includes the 56,666.67 shares owned by such entity.


(5)	RSM III Investments Ltd. is the sole member of CNRT, LLC and, as such, may be deemed to be the beneficial owner of the securities owned by CNRT, LLC.


(6)	Bill Bankston is the trustee of the Ruben S. Martin III Dynasty Trust and exercises control over the voting and disposition of the securities owned by the trust. As a result, he may be deemed to be the beneficial owner of the securities held by the trust. These 16,000 shares have been pledged as security to a third party to secure payment for a loan made by such third party.

(7)

Ruben S. Martin beneficially owns securities in Martin Resource Management representing approximately 34.5% of the voting stock thereof and serves as its Chairman of the Board and President. Martin Transport, Inc. is a wholly owned subsidiary of Martin Resource Management. As a result, Ruben S. Martin may be deemed to be the beneficial owner of the securities held by Martin Transport, Inc.; thus, the number of shares of common stock reported herein as beneficially owned by Ruben S. Martin includes the 1,000 shares owned by Martin Transport, Inc.


(8)	Ruben S. Martin directly owns 4,633.33 shares of common stock.


(9)	Messrs., Skelton, Bondurant and Tauscher each have the right to acquire 750, 1,250, and 1,250 shares, respectively, by virtue of options issued under Martin Resource Management’s non-qualified stock option plan.


(10)	Messrs. Skelton and Bondurant own securities in Martin Resource Management of 700 and 2,500 shares of common stock, respectively, obtained by the exercise of options issued under Martin Resource Management ’s nonqualified stock option plan.


(11)	Messrs. Skelton, Bondurant and Tauscher own securities in Martin Resource Management of 1,250, 1,250 and 875, restricted common shares, respectively, representing shares by virtue of restricted stock issued under Martin Resource Management’s 2007 Long-Term Incentive Plan. Fifty percent of these shares have vested and have been reissued without restriction.

The following table sets forth information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2012:

Equity Compensation Plan Information

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	Number of securities to be issued upon exercise of outstanding options, Warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan Category	(a)	(b)		(c)
Equity compensation plans approved by security holders	N/A	N/A		N/A
Equity compensation plans not approved by security holders(1)	—	$	—	688,400
Total	—	$	—	688,400


(1)	Our general partner has adopted and maintains the Martin Midstream Partners L.P. Long-Term Incentive Plan. For a description of the material features of this plan, please see “Item 11. Executive Compensation – Employee Benefit Plans – Martin Midstream Partners L.P. Long-Term Incentive Plan”.

In April 2012, we issued 6,250 restricted common units to non-employee directors under our long-term incentive plan from purchased by us in the open market for $222. These restricted common units vest in equal installments of 312.5 units on January 24, 2013, 2012, 2015 and 2016, respectively.

In May 2011, we issued 6,250 restricted common units to non-employee directors under our long-term incentive plan from 5,750 treasury units purchased by us in the open market for $235 and 500 treasury units from forfeitures. These restricted common units vest in equal installments of 312.5 units on January 24, 2012, 2013, 2014 and 2015, respectively.

In February 2011, we issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by us in the open market for $347. These units vest in 25% increments beginning in February 2013 and will be fully vested in February 2015.

On August 2, 2010, we issued 1,500 restricted common units to each of two new independent, non-employee directors under our long-term incentive plan. These restricted common units vest in equal installments of 375 units on January 24, 2011, 2012, 2013 and 2014, respectively.

On May 3, 2010, we issued 1,000 restricted common units to each of our three independent, non-employee directors under our long-term incentive plan. These restricted common units vest in equal installments of 250 units on January 24, 2011, 2012, 2013 and 2014, respectively.



Item 13.	Certain Relationships and Related Transactions, and Director Independence

Martin Resource Management owns 5,093,267 of our common limited partnership units representing approximately 19.1% of our outstanding common limited partnership units as of March 4, 2013. Our general partner is a wholly-owned subsidiary of Martin Resource Management. Our general partner owns a 2.0% general partner interest in us and our incentive distribution rights. Our general partner’s ability to manage and operate us and Martin Resource Management’s ownership of approximately 19.1% of our outstanding common limited partnership units effectively gives Martin Resource Management the ability to veto some of our actions and to control our management.

Distributions and Payments to the General Partner and its Affiliates

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The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.



Formation Stage
The consideration received by our general partner and Martin Resource Management for the transfer of assets to us	Ÿ 4,253,362 subordinated units (All of the original 4,253,362 subordinated units issued to Martin Resource Management have been converted into common units on a one-for-one basis since the formation of the Partnership. 850,672 subordinated units were converted on each of November 14, 2005, 2006, 2007 and 2008, respectively, and 850,674 subordinated units were converted on November 14, 2009)
	Ÿ 2% general partner interest; and Ÿ the incentive distribution rights.
Operational Stage
Distributions of available cash to our general partner	We will generally make cash distributions 98% to our unitholders, including Martin Resource Management as holder of all of the subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level as a result of its incentive distribution rights.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual aggregate distribution of approximately $1.8 million on its 2.0% general partner interest.
Payments to our general partner and its affiliates	Martin Resource Management is entitled to reimbursement for all direct expenses it or our general partner incurs on our behalf. The direct expenses include the salaries and benefit costs employees of Martin Resource Management who provide services to us. Our general partner has sole discretion in determining the amount of these expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses. Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. Please read “Agreements — Omnibus Agreement” below.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation	Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements

Omnibus Agreement

We and our general partner are parties to an omnibus agreement with Martin Resource Management (the "Onimbus Agreement") that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks.

Non-Competition Provisions . Martin Resource Management agrees for so long as Martin Resource Management controls the general partner not to engage in the business of


•	providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;

• providing marine transportation of petroleum products and by-products;

• distributing NGLs; and

• manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.

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This restriction does not apply to:


•	the ownership and/or operation on our behalf of any asset or group of assets owned by us or our affiliates;

• any business operated by Martin Resource Management, including the following:

◦ providing land transportation of various liquids,

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


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


◦	operating a crude oil gathering business in Stephens, Arkansas,

◦ operating an underground NGL storage facility in Arcadia, Louisiana,

◦ operating an environmental consulting company,

◦ operating an engineering services company, and

◦ building and marketing of sulfur processing equipment.


•	any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5.0 million,


•	any business that Martin Resource Management acquires or constructs that has a fair market value of $5.0 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of our Conflicts Committee, and

•

any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5.0 million or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, we are provided the opportunity to purchase the restricted business.

Services. Under the Omnibus Agreement, Martin Resource Management provides us with corporate staff and support services that are substantially identical in nature and quality to the services previously provided by Martin Resource Management in connection with its management and operation of our assets during the one-year period prior to the date of the agreement. The Omnibus Agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses.

Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. Effective October 1, 2012 through December 31, 2013, the Conflicts Committee of our general partner approved an annual reimbursement for indirect expenses of $10,622. For the years ended December 31, 2012, 2011 and 2010, the Conflicts Committee of our general partner approved and we reimbursed Martin Resource Management of $7.6, $4.8 and $3.8 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

These indirect expenses 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

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businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control our general partner.

Related Party Transactions . The Omnibus Agreement prohibits us from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee of our general partner’s board of directors. For purposes of the Omnibus Agreement, the term material agreements means any agreement between us and Martin Resource Management that requires aggregate annual payments in excess of then-applicable limitation on the reimbursable amount of indirect general and administrative expenses. Please read “— Services” above.

License Provisions . Under the Omnibus Agreement, Martin Resource Management has granted us a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates.

Amendment and Termination . The Omnibus Agreement may be amended by written agreement of the parties; provided, however that it may not be amended without the approval of the Conflicts Committee of our general partner if such amendment would adversely affect the unitholders. The Omnibus Agreement was amended on November 25, 2009, to permit us to provide refining services to Martin Resource Management. Such amendment was approved by the conflicts committee of our general partner. The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which we will reimburse Martin Resource Management for general and administrative services performed on our behalf, will terminate if we are no longer an affiliate of Martin Resource Management.

Motor Carrier Agreement

We are a party to a motor carrier agreement effective January 1, 2006, as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. Under the agreement, Martin Transport, Inc. agrees to ship our NGL shipments as well as other liquid products.

Term and Pricing. The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one-year 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 have the right to terminate this agreement at anytime by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports our NGL shipments as well as other liquid products. These rates are subject to any adjustment to which are mutually agreed or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the United States Department of Energy’s national diesel price list.

Indemnification. Martin Transport has indemnified us against all claims arising out of the negligence or willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.

Other Agreements

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement. We are a party to an agreement under which we provide terminal services to Martin Resource Management. This agreement was amended and restated as of October 27, 2004 and was set to expire in December 2006, but automatically renewed and will continue to automatically renew on a month-to-month basis until either party terminates the agreement by giving 60 days written notice. The per gallon throughput fee we charge under this agreement may be adjusted annually based on a price index.

Miscellaneous Terminal Services Agreements. We are currently party to several terminal services agreements and, from time to time, we may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.

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Marine Agreements

Marine Transportation Agreement. We are a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which we provide marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then- applicable term. The fees we charge Martin Resource Management are based on applicable market rates.

Marine Fuel. We are a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides us with marine fuel from its locations in the Gulf of Mexico at a fixed rate over the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil. Under this agreement, we agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.

Other Agreements

Cross Tolling Agreement. We are party to an agreement with Cross, dated November 25, 2009, under which we process crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement has a 12 year term which expires November 24, 2021. Under this tolling agreement, Martin Resource Management agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a fixed price per barrel. Any additional barrels are refined at a modified price per barrel. In addition, Martin Resource Management agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. We are a party to an agreement dated August 1, 2008 under which Martin Resource Management purchases and markets the sulfuric acid produced by our sulfuric acid production plant at Plainview, Texas, and which is not consumed by our internal operations. This agreement, as amended, will remain in place until we terminate it by providing 180 days’ written notice. Under this agreement, we sell all of our excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and we share in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

Other Miscellaneous Agreements. From time to time we enter into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.

Other Related Party Transactions

2012 Public Offerings .

Public Offerings . On January 25, 2012, we completed a public offering of 2,645,000 common units at a price of $36.15 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,645,000 common units, net of underwriters' discounts, commissions and offering expenses were $91.4 million. Our general partner contributed $2.0 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. On January 25, 2012, all of the net proceeds were used to reduce our outstanding indebtedness.

2011 Public Offering.

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On February 9, 2011, we completed a public offering of 1,874,500 common units at a price of $39.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70.7 million. Our general partner contributed $1.5 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us.

2010 Public Offerings.

In February 2010, we completed a public offering of 1,650,000 common units, resulting in net proceeds of $50.6 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $1.1 million in cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. The net proceeds were used to pay down revolving debt under our credit facility.

On August 17, 2010, we completed a public offering of 1,000,000 million common units resulting in net proceeds of approximately $28.1 million after payment of underwriters’ discounts. We used the net proceeds of $28.1 million to redeem from subsidiaries of Martin Resource Management an aggregate number of common units equal to the number of common units issued in the offering. Martin Resource Management reimbursed us for our payments of commissions and offering expenses. As a result of these transactions, our general partner was not required to contribute cash to us in conjunction with the issuance of these units in order to maintain its 2% general partner interest in us since there was no net increase in the outstanding limited partner units.

Talen's Marine & Fuel, LLC. On December 31, 2012, we acquired all of the outstanding membership interests in Talen's from Quintana Energy Partners, L.P. for $103.4 million, subject to certain post-closing adjustments. Simultaneous with the acquisition, we sold certain working capital-related assets and a customer relationship intangible asset to Martin Energy Services LLC for $56.0 million. The excess carrying value of the assets over the purchase price paid by Martin Resource Management at the sales date was $4.3 million and was recorded as an adjustment to partners' capital.

Lubricant Product Blending and Packaging Assets. On October 2, 2012, we acquired from Cross, certain specialty lubricant product blending and packaging assets, including working capital, for total consideration of $121.8 million in cash at closing, plus a final net working capital adjustment of $0.9 million paid in October of 2012. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these blending and packaging assets were recorded at the historical carrying value of the assets at the acquisition date, which totaled $62.4 million. The excess purchase price over the historical carrying value of the assets at the acquisition date was $60.3 million and was recorded as an adjustment to partners' capital.

Redbird Class A Interests. On October 2, 2012, we acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150.0 million in cash. The acquisition of these interests was recorded at the historical carrying value of the interests at the acquisition date. We recorded an investment in consolidated entities of $68.2 million and the excess of the purchase price over the carrying value of the Class A interests of $81.8 million was recorded as an adjustment to partners' capital.

Acquisition of Certain Terminalling Assets. On January 31, 2011, we acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for $36.5 million. The net book value of the acquired assets of $16.8 million was recorded in property, plant and equipment. The remaining $19.7 million was recorded as a reduction of partners' capital.

Acquisition of Offshore Tank Barge. On December 22, 2010, we acquired a 60,000 bbl offshore tank barge from Martin Resource Management for a total purchase price of $17.0 million. We paid cash in the amount of $9.6 million and assumed a note payable to a third party for $7.4 million. The net book value of the acquired assets was $16.8 million and was recorded in property, plant, and equipment. The remaining $0.2 million was recorded as a reduction of partners' capital.

Acquisition of Terminalling Assets. On August 26, 2010, we acquired certain shore-based marine terminalling assets from Martin Resource Management for $11.7 million. The net book value of the acquired assets was $7.3 million and was recorded in property, plant and equipment. The remaining $4.4 million was recorded as a reduction of partners' capital. These assets are located in Theodore, Alabama and Pascagoula, Mississippi.

Miscellaneous. Certain of directors, officers and employees of our general partner and Martin Resource Management maintain margin accounts with broker-dealers with respect to our common units held by such persons. Margin account

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transactions for such directors, officers and employees were conducted by such broker-dealers in the ordinary course of business.

Approval and Review of Related Party Transactions



Item 14.	Principal Accounting Fees and Services

KPMG, LLP served as our independent auditors for the fiscal years ended December 31, 2012 and 2011. The following fees were paid to KPMG, LLP for services rendered during our last two fiscal years:



	2012		2011
Audit fees	1,302,000	(1)	1,095,000	(1)
Audit related fees	20,000		16,809
Audit and audit related fees	1,322,000		1,111,809
Tax fees	171,976	(2)	142,930	(2)
All other fees	—		—
Total fees	1,493,976		1,254,739


(1)	2012 audit fees include fees for the annual integrated audit and fees related to services in connection with filing updated financial statements and in connection with transactions. 2011 Audit fees include fees for the annual integrated audit, the audit of Waskom Gas Processing Company and fees related to services in connection with transactions.


(2)	Tax fees are for services related to the review of our partnership K-1's returns, and research and consultations on other tax related matters.

Under policies and procedures established by the Board of Directors and the Audit Committee, the Audit Committee is required to pre-approve all audit and non-audit services performed by our independent auditor to ensure that the provisions of such services do not impair the auditor’s independence. All of the services described above that were provided by KPMG LLP in years ended December 31, 2012 and December 31, 2011 were approved in advance by the Audit Committee.

PART IV



Item 15.	Exhibits, Financial Statement Schedules

(a) Financial Statements, Schedules


(1)	The following financial statements of Martin Midstream Partners L.P. and are included in Part II, Item 8:

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2012 and 2011

Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Comprehensive Income for the years ended December 31, 2012 and 2011

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Consolidated Statements of Changes in Capital for the years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010

Notes to the Consolidated Financial Statements


(2)	Financial Statements of Waskom Gas Processing Company for the seven months ended July 31, 2012, an affiliate accounted for by the equity method, which constituted a significant subsidiary.

(b) Exhibits

Reference is made to the Index to Exhibits beginning on page 141 for a list of all exhibits filed as part of this report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have duly caused this Report to be signed on our behalf by the undersigned, thereunto duly authorized representative.

Martin Midstream Partners L.P.

(Registrant)

By: Martin Midstream GP LLC

It's General Partner

Date: March 4, 2013 By: /s/ Ruben S. Martin

Ruben S. Martin

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 4th day of March, 2013.

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Signature		Title

/s/ Ruben S. Martin		President, Chief Executive Officer and Director of Martin Midstream GP LLC (Principal Executive Officer)
Ruben S. Martin

/s/ Robert D. Bondurant		Executive Vice President and Chief Financial Officer of Martin Midstream GP LLC (Principal Financial Officer)
Robert D. Bondurant

/s/ Wesley M. Skelton		Executive Vice President, Chief Administrative Officer, Secretary and Controller of Martin Midstream GP LLC (Principal Accounting Officer)
Wesley M. Skelton

/s/ C. Scott Massey		Director of Martin Midstream GP LLC
C. Scott Massey

/s/ Byron Kelley		Director of Martin Midstream GP LLC
Howard Hackney

/s/ Joe N. Averett, Jr.		Director of Martin Midstream GP LLC
Joe N. Averett, Jr.

/s/ Charles H. Still		Director of Martin Midstream GP LLC
Charles H. Still

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INDEX TO EXHIBITS



Exhibit Number	Exhibit Name

3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.2	Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 25, 2009 (filed as Exhibit 10.1 to the Partnership’s Amendment to Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein by reference).
3.3	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed February 1, 2011, and incorporated herein by reference).
3.4	Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
3.5	Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.6	Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
3.7	Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.8	Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 33-91706), filed July 1, 2002, and incorporated herein by reference).
3.9	Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.10	Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
4.1	Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
4.2	Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
4.3	Indenture (including form of 8.875% Senior Note due 2018), dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed March 26, 2010, and incorporated herein by reference).
4.4*	First Supplemental Indenture, to the Indenture dated as of March 26, 2010, dated as of February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.5	Indenture (including form of 7.250% Senior Notes due 2021), dated as of February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).
4.6	Registration Rights Agreement, dated as of February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 4.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).
10.1	Second Amended and Restated Credit Agreement, dated November 10, 2005, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders set forth therein (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 14, 2005, and incorporated herein by reference).

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10.2	Second Amendment to Second Amended and Restated Credit Agreement, dated as of December 28, 2007, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed January 2, 2008, and incorporated herein by reference).
10.3	Third Amendment to Second Amended and Restated Credit Agreement, effective as of September 24, 2008, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed September 30, 2008, and incorporated herein by reference).
10.4	Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of December 21, 2009, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline LLC, the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 23, 2009, and incorporated herein by reference).
10.5	Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of January 14, 2010, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline LLC, the financial institutions parties thereto, as lenders, and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein by reference).
10.6	Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of March 26, 2010, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline LLC, the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed March 26, 2010, and incorporated herein by reference).
10.7	Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of April 15, 2011, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed April 21, 2011, and incorporated herein by reference).
10.8	Eighth Amendment to Second Amended and Restated Credit Agreement, dated as of May 31, 2011, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 13, 2012, and incorporated herein by reference).
10.9	Ninth Amendment to Second Amended and Restated Credit Agreement, dated as of September 7, 2011, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 7, 2011, and incorporated herein by reference).
10.10	Commitment Increase and Joinder Agreement, dated December 5, 2011 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 7, 2011, and incorporated herein by reference).
10.11	Commitment Increase and Joinder Agreement, dated May 10, 2012 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed May 10, 2012 and incorporated herein by reference).

143



10.12*	Tenth Amendment to the Second Amended and Restated Credit Agreement, dated as of May 22, 2012, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, Martin Midstream Finance Corp., the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent.
10.13*	Eleventh Amendment to the Second Amended and Restated Credit Agreement and Limited Waiver, dated as of February 4, 2013, among the Operating Partnership, the Partnership, the Operating General Partner, Martin Midstream Finance Corp., Redbird Gas Storage LLC, MOP Midstream Holdings LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent.
10.14	Omnibus Agreement, dated November 1, 2002, by and among Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.15	Amendment No. 1 to Omnibus Agreement, dated as of November 25, 2009, by and among Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.16	Amendment No. 2 to Omnibus Agreement, dated October 1, 2012, by Martin Resource Management Corporation, Martin Midstream GP, LLC, Martin Midstream Partners L.P., and Martin Operating Partnership L.P. (filed as Exhibit 10.4 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.17	Motor Carrier Agreement, dated January 1, 2006, by and between the Operating Partnership and Martin Transport, Inc. (filed as Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2011, and incorporated herein by reference). .
10.18	Marine Transportation Agreement, dated January 1, 2006, by and between the Operating Partnership and Midstream Fuel Service, L.L.C. (filed as Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2011, and incorporated herein by reference).
10.19	Product Storage Agreement, dated November 1, 2002, by and between Martin Underground Storage, Inc. and the Operating Partnership (filed as Exhibit 10.8 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.20	Marine Fuel Agreement, dated November 1, 2002, by and between Martin Fuel Service LLC and the Operating Partnership (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.21†	Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein by reference).
10.22†	Form of Restricted Common Unit Award Notice (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein by reference).
10.23	Assignment and Assumption of Lease and Sublease, dated November 1, 2002, by and between the Operating Partnership and Martin Gas Sales LLC (“MGSLLC”) (filed as Exhibit 10.12 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.24	Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement dated November 1, 2002, by and between MGSLLC and the Operating Partnership (filed as Exhibit 10.13 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.25	Asset Purchase Agreement by and among the Partnership, the Operating Partnership and Tesoro Marine Services, L.L.C., dated October 27, 2003 (filed as Exhibit 10.1 to the Partnership’s Amendment No. 1 to Current Report on Form 8-K (SEC No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
10.26	Purchase Agreement by and among the Operating Partnership, Prism Gas Systems I, L.P., Natural Gas Partners V, L.P., Robert E. Dunn, William J. Diehnelt, Gene A. Adams, Philip D. Gettig, Sharon C. Taylor and Scott A. Southard, dated September 6, 2005 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed September 6, 2005, and incorporated herein by reference).
10.27	Amended and Restated Terminal Services Agreement by and between the Operating Partnership and Martin Fuel Service LLC (“MFSLLC”), dated October 27, 2004 (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC No. 000-50056), filed October 28, 2004, and incorporated herein by reference).
10.28	Lubricants and Drilling Fluids Terminal Services Agreement by and between the Operating Partnership and MFSLLC, dated December 23, 2003 (filed as Exhibit 10.4 to the Partnership’s Amendment No. 1 to Current Report on Form 8-K (SEC No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
10.29*(1)	Amended and Restated Sales Agency Agreement, dated August 1, 2008, by and between Martin Operating Partnership L.P. and Martin Product Sales LLC.

144



10.30 †	Martin Resource Management Corporation Purchase Plan for Units of Martin Midstream Partners L.P. (filed as Exhibit 10.1 to the Partnership's registration statement on Form S-8 (SEC File No. 333-140152), filed January 23, 2007, and incorporated herein by reference).
10.31	Form of Indemnification Agreement (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 6, 2008, and incorporated herein by reference).
10.32	Amended and Restated Contribution Agreement, dated as of November 25, 2009, by and among the Operating Partnership, the Partnership, Cross Oil Refining & Marketing, Inc. and Martin Resource Management (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.33	Tolling Agreement, dated as of November 25, 2009, by and between the Operating Partnership and Cross Oil Refining & Marketing, Inc. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.34	Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between the Partnership and Martin Resource Management (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.35	Second Amended and Restated LLC Agreement of Redbird Gas Storage LLC, dated as of October 2, 2012. (filed as Exhibit 10.6 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
10.36	Asset Purchase Agreement, dated October 2, 2012, by and among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Cross Oil Refining & Marketing, Inc. and Martin Resource Management Corporation (filed as Exhibit 10.3 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.37	Supply Agreement dated, as of October 2, 2012, by and between the Partnership and Cross Oil & Refining Marketing Inc. (filed as Exhibit 10.7 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
10.38	Noncompetition Agreement dated, as of October 2, 2012, by and among the Partnership, Cross Oil Refining & Marketing Inc., and Martin Resource Management Corporation. (filed as Exhibit 10.8 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
10.39	Membership Interests Purchase Agreement, dated October 2, 2012, by and among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Martin Underground Storage, Inc. and Martin Resource Management Corporation (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.40	Purchase Price Reimbursement Agreement, dated October 2, 2012, by Martin Resource Management Corporation to and for the benefit of Martin Operating Partnership L.P. (filed as Exhibit 10.2 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
21.1*	List of Subsidiaries.
23.1*	Consent of KPMG LLP.
23.2*	Consent of KPMG LLP.
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 9.06 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 9.06 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; (5) the Consolidated Statements of Other Comprehensive Income; and (6) the Notes to Consolidated Financial Statements, tagged as blocks of text.
*	Filed or furnished herewith.
†	As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.

(1) Material has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended.

145

Financial Statement Schedule

Pursuant to Item 15(a)(2)

Waskom Gas Processing Company

Consolidated Financial Statements July 31, 2012 (unaudited) and December 31, 2011 and for the seven months ended July 31, 2012 (unaudited) and each of the years in the two-year period ended December 31, 2011 (with Independent Auditors' Report thereon).

146

INDEPENDENT AUDITORS' REPORT

To the Partners of

Waskom Gas Processing Company:

We have audited the accompanying consolidated balance sheet of Waskom Gas Processing Company and subsidiaries (the “Partnership”) as of December 31, 2011 and the related consolidated statements of income, partners' capital, and cash flows for the years ended December 31, 2011 and 2010. These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Waskom Gas Processing Company and subsidiaries as of December 31, 2011 and the results of their operations and their cash flows for the years ended December 31, 2011 and 2010, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Shreveport, Louisiana March 5, 2012

147

WASKOM GAS PROCESSING COMPANY



CONSOLIDATED BALANCE SHEETS
AS OF JULY 31, 2012 AND DECEMBER 31, 2011

	2012 (Unaudited)			2011
ASSETS

CURRENT ASSETS:
Cash	$	2,191,147		$	757,494
Accounts receivable	1,172,173			1,473,935
Accounts receivable - partners	5,869,715			18,241,163
Inventories	574,652			423,474
Prepaid expenses	—			26,224
Total current assets	9,807,687			20,922,290

PROPERTY AND EQUIPMENT:
Gas plant asset and gas gathering equipment	164,365,426			157,072,005
Other fixed assets	746,743			746,743
Accumulated depreciation and amortization	(36,997,090		)	(32,336,265		)
Net property and equipment	128,115,079			125,482,483

NON-CURRENT ASSETS:
Other non-current assets:	133,500			250,000
TOTAL	$	138,056,266		$	146,654,773

LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	5,882,893		$	14,934,725
Accounts payable - partners	2,131,007			4,057,864

Total current liabilities	8,013,900			18,992,589

LONG-TERM LIABILITIES - Asset retirement obligation	833,590			799,527

COMMITMENTS AND CONTINGENCIES

PARTNERS' CAPITAL	129,208,776			126,862,657

TOTAL	$	138,056,266		$	146,654,773

See accompanying notes to consolidated financial statements.

148

WASKOM GAS PROCESSING COMPANY



CONSOLIDATED STATEMENTS OF INCOME
FOR THE SEVEN MONTHS ENDED JULY 31, 2012 AND YEARS ENDED DECEMBER 31, 2011 AND 2010

	2012 (Unaudited)			2011		2010

OPERATING REVENUES:
Natural gas processing and other revenues	$	22,401,200		$	39,618,717	$	36,297,801
Natural gas liquid sales	44,261,039			88,654,517		86,911,925
Gain/loss on disposal of assets	(83,205		)	845,567		912,004

Total operating revenues	66,579,034			129,118,801		124,121,730

OPERATING COSTS AND EXPENSES:
Cost of sales - natural gas liquids	46,502,430			92,705,171		87,159,671
Operating costs	6,296,194			10,126,797		9,375,703
Depreciation and amortization	4,694,888			6,849,262		6,597,686

Total operating costs and expenses	57,493,512			109,681,230		103,133,060

OPERATING INCOME INCOME BEFORE TAXES	9,085,522			19,437,571		20,988,670

Income tax expense	100,000			53,008		226,589

NET INCOME	$	8,985,522		$	19,384,563	$	20,762,081

See accompanying notes to consolidated financial statements.

149

WASKOM GAS PROCESSING COMPANY



CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
FOR THE SEVEN MONTHS ENDED JULY 31, 2012 AND YEARS ENDED DECEMBER 31, 2011 AND 2010

	Total Partners' Capital

BALANCE - December 31, 2009	$	70,560,798

Cash contributions for capital expenditures	7,471,259

Cash contributions for investment in Waskom Midstream LLC	40,000,000

Cash distributions in excess of working capital	(4,702,415		)

Cash distributions	(4,200,000		)

Distributions in-kind	(22,383,279		)

Net Income	20,762,081

BALANCE - December 31, 2010	107,508,444

Cash contributions for capital expenditures	32,209,322

Cash distributions in excess of working capital	(4,432,461		)

Cash distributions	(2,400,000		)

Distributions in-kind	(25,407,211		)

Net Income	19,384,563

BALANCE - December 31, 2011	126,862,657

Cash contributions for capital expenditures (unaudited)	7,293,499

Cash distributions in excess of working capital (unaudited)	(1,209,056		)

Distributions in-kind (unaudited)	(12,723,846		)

Net Income (unaudited)	8,985,522

BALANCE - July 31, 2012 (Unaudited)	$	129,208,776

See accompanying notes to consolidated financial statements.

150

WASKOM GAS PROCESSING COMPANY



CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SEVEN MONTHS ENDED JULY 31, 2012 AND YEARS ENDED DECEMBER 31, 2011 AND 2010

	2012 (Unaudited)			2011			2010

OPERATING ACTIVITIES:
Net Income	$	8,985,522		$	19,384,563		$	20,762,081
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization	4,694,888			6,849,262			6,597,686
Distributions in-kind to partners	(12,723,846		)	(25,407,211		)	(22,383,279		)
Loss / (Gain) on sale of asset	83,205			(845,567		)	(912,004		)
Changes in operating assets and liabilities:
Accounts receivable	301,762			(527,729		)	(768,174		)
Accounts receivable - partners	12,371,448			(7,533,187		)	(1,334,484		)
Inventory	(151,178		)	79,975			(35,077		)
Prepaid expenses	26,224			(2,160		)	(24,064		)
Other non-current assets, net	116,500			—			—
Accounts payable and accrued liabilities	(9,086,227		)	6,330,191			2,132,514
Accounts payable - partners	(1,926,857		)	(920,761		)	3,134,610

Net cash provided by (used in) operating activities	2,691,441			(2,592,624		)	7,169,809

INVESTING ACTIVITIES:
Additions to property and equipment	(7,375,526		)	(25,489,809		)	(7,277,746		)
Acquisitions, net of cash required	—			—			(40,000,000		)
Proceeds from sale / disposal of assets	33,295			2,502,000			2,477,000
Net cash used in investing activities	(7,342,231		)	(22,987,809		)	(44,800,746		)

FINANCING ACTIVITIES:
Contributions from partners	7,293,499			32,209,322			47,471,259
Distributions to partners	(1,209,056		)	(6,832,462		)	(8,902,415		)
Net cash provided by financial activities	6,084,443			25,376,860			38,568,844

NET INCREASE (DECREASE) IN CASH	1,433,653			(203,573		)	937,907

CASH - Beginning of year	757,494			961,067			23,160

CASH - End of year	$	2,191,147		$	757,494		$	961,067

SUPPLEMENTAL CASH FLOWS DISCLOSURES:
Taxes paid	$	97,342		$	196,544		$	112,371

See accompanying notes to consolidated financial statements.

151

WASKOM GAS PROCESSING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	NATURE OF BUSINESS

Waskom Gas Processing Company (the “Partnership”), a Texas General Partnership, was formed on November 1, 1995 to construct and operate the Waskom Processing Plant (“the Plant”). As of December 31, 2011 the partners are CenterPoint Energy Gas Processing Company (50%) and Prism Gas Systems I, L.P. (50%). Prism Gas Systems I, L.P. serves as operator. The Partnership is engaged in the processing, gathering and marketing of natural gas and natural gas liquids (“NGL's”), predominantly in Texas and northwest Louisiana.

The Plant is a 320 MMcfd cryogenic turboexpander gas plant located in Harrison County, Texas. The Plant has full NGL fractionation, treating and stabilization capabilities. Fractionation is a process used to separate the mixture of NGL's into individual products for sale. Expansions to the processing plant were completed in March and June of 2007, July of 2008, June of 2009 and September of 2011 increasing the capacity from 150 MMcfd to 320 MMcfd. In July 2009 the Waskom fractionator was expanded to a capacity of 14,500 barrels per day from 12,500 barrels per day. A NGL railroad loading facility was constructed in 2011 and was placed in operation in the first quarter of 2012.

The natural gas supply for the Plant is derived primarily from natural gas wells located in the Cotton Valley formation of East Texas and Northwest Louisiana. The primary suppliers of natural gas to the Plant include BP American Production Company, Centerpoint Energy Gas Transmission Company, Samson Lone Star, LLC and Devon Energy Corporation, which collectively represent approximately 75% of the 252 MMcfd of natural gas supplied for the seven months ended July 31, 2012. The primary suppliers of natural gas to the Plant include BP American Production Company, Centerpoint Energy Gas Transmission Company, GMX/Endeavour Pipeline, Inc., Samson Lone Star, LLC and Devon Energy Corporation, which collectively represent approximately 77% of the 269 MMcfd of natural gas supplied for the year ended December 31, 2011.

The processing contracts for the Waskom Processing Plant are primarily percent-of-liquids (“POL”) contracts, in which we retain a portion of the NGL's recovered as a processing fee, percent-of-proceeds (“POP”) contracts in which we retain a portion of both the residue gas and the NGL's as payment for services and straight fee contracts in which we receive a fee for every Mcf of gas delivered to the plant. As of July 31, 2012, approximately 37.5% of the contracts are POL, 25% of the contracts are fee and 25% of the contracts are POP (unaudited). In addition, there is one minor contract for processing on a keep-whole basis and there is one purchase contract.

Sales of third party gas and fractionated NGL's are predominately to the partners and occur at the tailgate of the Plant.


2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation - During 2010 and 2008, Waskom Midstream LLC and Waskom Products Pipeline, LLC, respectively, were formed as wholly owned subsidiaries of Waskom Gas Processing Company, to hold certain plant and pipeline assets of the Partnership. Accordingly, the financial statements are consolidated to include these entities. All eliminations of intercompany balances have been made.

Accounts Receivable - Accounts receivable include trade receivables, recorded at invoiced amounts.

Property and Equipment - Property and equipment are stated at cost and depreciated using the straight-line method over the estimated useful lives of the classes of assets, as follows:

Depreciation expense was $4,660,825 (unaudited), $6,794,726, and $6,546,872 for the seven months ended 2012 and the years ended December 31, 2011 and 2010, respectively. Repairs and maintenance are charged to operations as incurred. Renewals and betterments are capitalized.

Inventories - Substantially all inventory at July 31, 2012 and December 31, 2011 represents pipe held for future projects. Such pipe was valued at acquisition cost.

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Asset Retirement Obligations - The Partnership records asset retirement obligations (“ARO”) for costs associated with legal obligations to retire tangible, long-lived assets. The Partnership records as an offset to the “ARO”, an asset at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. The Partnership's asset retirement obligations include purging, plugging and remediation costs associated with the pipeline. Accretion expense for the seven months ended July 31, 2012, and the years ended December 31, 2011 and 2010 was $34,063 (unaudited), $54,536 and $50,814, respectively.

Impairment of Long-Lived Assets - Long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

Revenue Recognition - Revenues are recognized when title passes or service is performed. The Partnership's business consists largely of the ownership and operation of physical assets. End sales from these businesses result in physical deliveries of commodities.

Federal Income Taxes - The Partnership is a Texas General Partnership and as such has no liability for Federal Income Taxes. Each partner is responsible for its share of federal income tax.

On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the then existing franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the new margin tax. These deferred taxes are immaterial. Texas margin tax expense for the seven months ended July 31, 2012 and the years ended December 31, 2012 and 2010 was $100,000 (unaudited), $53,008 and $226,589, respectively.

Environmental Liabilities - The Partnership's policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses for environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value.

Use of Estimates - The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts at the date of the financial statements and the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates.


3.	RELATED-PARTY TRANSACTIONS

During 2012, 2011, and 2010, the Partnership engaged in certain material transactions with the partners. The Partnership believes that the terms of these transactions were comparable to those that could have been negotiated with unrelated third parties. As of July 31, 2012 and December 31, 2011, the Partnership had receivables of approximately $5,869,715 (unaudited) and $18,241,163, respectively, and payables of approximately $2,131,007 (unaudited) and $4,057,864, respectively, due from and due to the partners.

Per the partnership agreement, cash contributions are made by the partners for capital expenditures and working capital. Contributions for capital expenditures totaled $7,293,499 (unaudited), $32,209,322 and $7,471,259 for the seven months ended 2012, and the years ended 2011 and 2010, respectively. The partnership agreement allows for cash distributions to be made to the partners of any cash available in excess of working capital requirements, generally equal to two months of historical operating expenses. Such cash distributions in excess of working capital totaled $1,209,056 (unaudited), $4,432,461 and $4,702,415 for the seven months ended 2012, and the years ended 2011 and 2010, respectively. Other cash distributions totaled $0 (unaudited), $2,400,000 and $4,200,000 for the seven months ended 2012, and the years ended 2011 and 2010, respectively.

The Partnership purchases gas from third party producers and processes this gas based on processing contracts, which are primarily POL contracts. The percentage of liquids retained by the Partnership is distributed to the partners as distributions

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of products-in-kind based on the partners' equity interest. Distributions of products in-kind of $12,723,846 (unaudited), $25,407,211 and $22,383,279 for the seven months ended 2012, and the years ended 2011 and 2010, respectively, were made to the partners. Distributions of products in-kind are valued at prevailing market prices at the time of distribution.

In some instances, the fractionated NGL's (less any retained portions) are returned to the third party producers, but in most cases, the third party producers enter into agreements with the partners to market their product. In such instances, the Partnership will sell the product to the partners. Such sales amounted to $48,098,581 (unaudited), $85,613,194 and $71,734,452 for the seven months ended 2012, and the years ended 2011 and 2010, respectively, and are included as natural gas liquid sales in the income statement.


4.	ACQUISITION

On January 15, 2010, the Partnership through its wholly owned subsidiary Waskom Midstream LLC, acquired from Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and equipment referred to as the Harrison Pipeline System for approximately $40,000,000.


5.	COMMITMENTS AND CONTINGENCIES

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Management believes that any future costs should not have a material adverse effect on the Partnership's liquidity or financial position.


6.	SUBSEQUENT EVENT

On July 31, 2012, Prism Gas Systems I, L.P. sold its 50% interest in the Partnership to CenterPoint Energy Gas Processing Company.

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TABLE OF CONTENTS

Part I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Legal Proceedings Item 4. Mine Safety Disclosures Part II Item 5. Market For Our Common Equity, Related Unitholder Matters and Issuer Purchases Of Equity Securities Item 6. Selected Financial Data Item 7. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Part III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services Part IV Item 15. Exhibits, Financial Statement Schedules

MMLP 10-K Fiscal year ended Dec. 31, 2012