Martin Midstream Partners
Annual Report 2008

Plain-text annual report

M I D S T R E A MP A R T N E R S M A R T I N M I D S T R E A M P A R T N E R S L . P . 2 0 0 8 A n n u a l R e p o r t M I D S T R E A MP A R T N E R S 4200 Stone Road Kilgore, Texas 75662 903-983-6200 www.martinmidstream.com 2008 Annual Report Our Most Important Asset… 177523_Martin_CVR 1-2 4/15/09 10:56:18 PM ...Isn’t Our... ...Isn’t Our... Company Information Company Information (cid:85) 17 marine terminal facilities and 6 inland terminal facilities located across the United States (cid:85) 17 marine terminal facilities and 6 inland terminal facilities located across the United States Gulf Coast with an aggregate storage capacity of 3.0 million barrels Gulf Coast with an aggregate storage capacity of 3.0 million barrels (cid:85) Ownership interests in over 669 miles of gathering and transmission pipelines located in the natural gas producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico (cid:85) Ownership interests in over 669 miles of gathering and transmission pipelines located in the natural gas producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico M I D S T R E A MP A R T N E R S M I D S T R E A MP A R T N E R S (cid:85) 50% ownership interest in a 265 million cubic feet per day natural gas processing plant located (cid:85) 50% ownership interest in a 265 million cubic feet per day natural gas processing plant located in East Texas in East Texas (cid:85) Over 2.1 million barrels of combined NGL storage capacity located in Louisiana, Mississippi (cid:85) Over 2.1 million barrels of combined NGL storage capacity located in Louisiana, Mississippi and Texas and Texas (cid:85) 42 inland marine tank barges, 18 inland push boats and 5 offshore tug barge units that (cid:85) 42 inland marine tank barges, 18 inland push boats and 5 offshore tug barge units that transport petroleum products and by-products primarily in the United States Gulf Coast region transport petroleum products and by-products primarily in the United States Gulf Coast region (cid:85) 2 sulfur prilling facilities with a combined 5,000 tons per day processing capacity located in (cid:85) 2 sulfur prilling facilities with a combined 5,000 tons per day processing capacity located in Stockton, California and Beaumont, Texas Stockton, California and Beaumont, Texas (cid:85) 6 sulfur-based fertilizer production plants, 1 sulfuric acid plant and 1 emulsified sulfur blend- ing plant located in Texas, Illinois and Utah with a combined production capacity of over 540 thousand tons per year (cid:85) 6 sulfur-based fertilizer production plants, 1 sulfuric acid plant and 1 emulsified sulfur blend- ing plant located in Texas, Illinois and Utah with a combined production capacity of over 540 thousand tons per year S S S S T T S S S S S S T S G G G G T G S G G G T G M S Terminalling and Storage Terminalling and Storage T Natural Gas Services Natural Gas Services G Marine Transportation Marine Transportation M Sulfur Services Sulfur Services S T T T S T M T T T T TT M G T T T G T T G S T M T T T T T T T T TT G G M G M T T T T T T M T S M T S T T M T T G T G T T T Company Information Company Information Principal Officers Principal Officers Martin Midstream GP LLC Martin Midstream GP LLC Board of Directors Board of Directors Martin Midstream GP LLC Martin Midstream GP LLC Corporate Offices Corporate Offices Martin Midstream GP LLC Martin Midstream GP LLC Ruben S. Martin Ruben S. Martin President President Chief Executive Officer Chief Executive Officer Robert D. Bondurant Executive Vice President Chief Financial Officer Robert D. Bondurant Executive Vice President Chief Financial Officer Donald R. Neumeyer Executive Vice President Chief Operating Officer Donald R. Neumeyer Executive Vice President Chief Operating Officer Wesley M. Skelton Executive Vice President Chief Administrative Officer Wesley M. Skelton Executive Vice President Chief Administrative Officer Ruben S. Martin Ruben S. Martin President President Chief Executive Officer Chief Executive Officer Martin Midstream GP LLC Martin Midstream GP LLC John R. Gaylord John R. Gaylord President President Jacintoport Terminal Company Jacintoport Terminal Company Howard R. Hackney Howard R. Hackney Director Director Texas Bank & Trust Texas Bank & Trust Federal Home Loan Bank of Dallas Federal Home Loan Bank of Dallas C. Scott Massey CPA C. Scott Massey, CPA LLC ManagerSandstone Ventures LLC C. Scott Massey CPA C. Scott Massey, CPA LLC ManagerSandstone Ventures LLC 4200 Stone Road Kilgore, Texas 75662 (903) 983-6200 4200 Stone Road Kilgore, Texas 75662 (903) 983-6200 Transfer Agent Transfer Agent BNY Mellon Shareowner Services 480 Washington Boulevard Jersey City, New Jersey 07310 (800) 301-0911 www.bnymellon.com/shareowner/isd BNY Mellon Shareowner Services 480 Washington Boulevard Jersey City, New Jersey 07310 (800) 301-0911 www.bnymellon.com/shareowner/isd Auditors Auditors KPMG LLP KPMG LLP 333 Texas Street 333 Texas Street Suite 1900 Suite 1900 Shreveport, Louisiana 71101 Shreveport, Louisiana 71101 Units Traded Units Traded NASDAQ Global Select Market Symbol: MMLP NASDAQ Global Select Market Symbol: MMLP Investor Information Investor Information Updated investor information on Updated investor information on the Company is available on our the Company is available on our website www.martinmidstream.com. website www.martinmidstream.com. Inquiries can also be sent to Inquiries can also be sent to info@martinmidstream.com. info@martinmidstream.com. m o c . s r o n n o c - n a r r u c . w w w / . c n I , s r o n n o C & n a r r u C y b d e n g i s e D m o c . s r o n n o c - n a r r u c . w w w / . c n I , s r o n n o C & n a r r u C y b d e n g i s e D 177523_Martin_CVR 3-4 177523_Martin_CVR 3-4 4/15/09 10:56:20 PM 4/15/09 10:56:20 PM C O A T E D …It’s Our People Martin Midstream Partners 2008 Annual Report 1 NARR 1 4/21/09 12:07:38 AM C O A T E D Hard Working Raymond Raggett (left) Process Safety Management Coordinator Beaumont, TX Years of Service: 6 Matt Yost (right) VP—Terminalling Kilgore, TX Years of Service: 26 2 Martin Midstream Partners 2008 Annual Report NARR 2 4/21/09 12:07:40 AM U N C O A T E D Terminalling & Storage Terminalling and storage services for petroleum products and by-products Marine Terminals We are one of the largest operators of marine service termi- nals in the Gulf Coast region. We own or operate 17 marine terminals along the Gulf Coast from Tampa, Florida to Corpus Christi, Texas with an aggregate storage capacity totaling over 2.2 million barrels. Our terminal assets are located at strategic distribution points for the products we handle and are in close proximity to our customer base. The location and composition of our terminals are structured to complement our other businesses reflecting our strategy of providing a broad range of integrated services in the handling and transportation of petroleum products and by-products. We generate revenues from our marine terminals primarily through fee-based contracts with additional fees earned based on the value of the products and services delivered from our terminals. We also generate additional revenues through the distribution and marketing of lubricants from these facilities. Our marine terminals are generally classi- fied into three types of terminals: full service terminals, fuel and lubricant terminals and specialty petroleum terminals. Full Service Terminals We own or operate eight full service terminals across the Texas and Louisiana Gulf Coast with aggregate storage capacity of approximately 217,500 barrels. These terminals provide product storage, handling and distribution services for our customers. In addition, our facilities also serve as shore bases that are used in logistical support for our customers engaged in the offshore exploration and production and oilfield service industries. Our shore base support services include the storing and handling of tubular goods, loading and unloading of bulk materials and providing facilities from which major and independent oil companies can control offshore operations. Fuel and Lubricant Terminals We own or operate four lubricant and fuel oil terminals located along the Louisiana Gulf Coast with an aggregate storage capacity of approximately 159,000 barrels. These fuel and lubricant terminals primarily provide storage and handling services for lubricants and fuel oils used in the offshore explo- ration and production and oilfield service industries. We also distribute and market lubricants at these terminals. Specialty Petroleum Terminals We own or operate five terminal facilities providing storage and handling services for various products including anhy- drous ammonia, asphalt, sulfur, sulfuric acid, fuel oil and crude oil and other petroleum products and by-products. These terminals have an aggregate storage capacity of over 2.2 million barrels with each terminal capable of handling products transported by vessel, barge and truck. Inland Terminals In addition to our marine terminals, we own or operate six inland terminals located in Texas and Nebraska with over 335,000 barrels of aggregate storage capacity. Three of these inland terminals provide fee-based asphalt terminalling services through minimum throughput contracts with the parent company of our general partner, Martin Resource Management. In addition, three inland terminal facilities located in southeast Texas provide various handling, unload- ing and storage services for specialty products such as natu- ral gasoline, NGLs and lubricants. Martin Midstream Partners 2008 Annual Report 3 NARR 3 4/21/09 12:07:41 AM Natural Gas Services Gathering, processing and distribution of natural gas and natural gas liquids (NGLs) NGLs We own or operate six different natural gas liquids (NGLs) facilities in Louisiana, Texas and Mississippi with an aggre- gate storage capacity of over 2.1 million barrels. We purchase NGLs primarily from natural gas processors and, to a lesser extent, major domestic oil refiners. We generate revenue through marketing and distribution of these NGLs to our wholesale and retail customer base. In addition, we generate fee-based revenues by leasing underground storage capacity to industrial customers. U N C O A T E D Prism Gas Our wholly-owned subsidiary, Prism Gas, has ownership interests in over 669 miles of gathering pipelines located in the natural gas producing regions of East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico. In addition, Prism Gas owns a 50% operating interest in a 265 million cubic feet per day (MMcfd) natural gas processing plant located in East Texas. Key Prism Gas assets are primarily located in East Texas and include the Waskom Processing Plant and the Woodlawn Plant and Gathering System. Waskom Processing Plant The Waskom Processing Plant is a 265 MMcfd natural gas processing plant located in East Texas with full fractionation capabilities. Our plant is well-positioned competitively as we are strategically located near much of the new natural gas production in East Texas. In addition, the Waskom Processing Plant is the only gas plant in East Texas that has full fraction- ation capability. We are currently expanding the processing plant to 285 MMcfd and the fractionation capacity to 14,500 barrels per day. This expansion is expected to be complete by the end of the second quarter 2009. Prism Gas owns an unconsolidated 50% operating interest in the Waskom Pro- cess ing Plant with CenterPoint Energy Gas Processing, Inc. owning the remaining 50% non-operating interest. Woodlawn Plant and Gathering System Woodlawn Pipeline Co., Inc. (“Woodlawn”), a wholly-owned subsidiary of Prism Gas, owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 MMcfd natural gas processing plant. In addition, Prism Gas owns a nine-mile pipeline that delivers residue gas from the Woodlawn plant to the Texas Eastern Transmission pipeline system. NGLs recovered from gas processed at Woodlawn are trucked to the Waskom Processing Plant for fractionation. 4 Martin Midstream Partners 2008 Annual Report NARR 4 4/21/09 12:07:41 AM C O A T E D Dedicated Tom Redd (left) VP—NGLs Kilgore, TX Years of Service: 26 Bob Dunn (right) Sr. VP—Prism Bedford, TX Years of Service: 9 Mike Kyle (center) Manager—Operations Waskom, TX Years of Service: 26 Martin Midstream Partners 2008 Annual Report 5 NARR 5 4/21/09 12:07:48 AM C O A T E D Responsible Ed Grimm III (left) VP—Marine Transportation La Porte, TX Years of Service: 3 Capt. Phillip Hall (right) Master, ATB Explorer/Margaret Sue La Porte, TX Years of Service: 16 6 Martin Midstream Partners 2008 Annual Report NARR 6 4/21/09 12:07:50 AM U N C O A T E D Marine Transportation Marine transportation services for petroleum products and by-products horsepower. We operate our offshore tows in the Gulf of Mexico, the upper United States East Coast and Peruvian coastal waters. The customer base for our offshore services is similar to our inland business with revenues typically generated through a mix of day-rate term contracts and spot market contracts. We own a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products pro- duced in oil refining and natural gas processing. Inland Fleet Our inland marine transportation system operates coastwise along the Gulf of Mexico and on the United States inland waterway system between domestic ports along the Gulf of Mexico Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system. We own and operate 17 inland push boats and 40 tank barges that are combined to form inland tows. Our inland tows generally consist of one push boat combined with one to three tank barges, depending on the push boat horsepower, waterway capacity and condition, and customer requirements. Our inland push boats range from 800 to 3,800 horsepower. Our inland tank barges carry a wide variety of petroleum-based products including asphalt, crude oil, fuel oil, diesel, gasoline and sulfur. The primary customers for our inland marine transportation services include major and independent oil and gas refining companies, petroleum distributors and Martin Resource Management. Revenues are primarily gen- erated through day-rate contracts that typically range from one to three years. In addition, we also generate revenues through spot market contracts which allow us to balance pricing flexibility with stable cash flows generated through our longer-term contracts. Offshore Fleet In addition to our inland marine fleet, we own and operate four offshore tugboats and four offshore tank barges that are combined to form offshore tows. Our offshore tows consist of one tugboat and one tank barge and are used to carry prod- ucts such as asphalt, fuel oils, crude oil, distillates, gasoline and NGLs. Our offshore tows’ capacities range from 40,000 to 95,000 barrels of product and range from 3,200 to 7,200 Martin Midstream Partners 2008 Annual Report 7 NARR 7 4/21/09 12:07:51 AM Sulfur Services Sulfur gathering, processing and distribution acid plant, located in Texas, Illinois and Utah with a com- bined production capacity of over 540,000 tons per year. We sell our fertilizer products primarily to wholesale distributors, as well as to a small number of independent dealers through- out the United States. Our industrial sulfur products are marketed primarily in the eastern United States, where many industrial and power plants are located. A portion of the sulfuric acid produced at our Plainview sulfuric acid plant is consumed by the fertilizer production facility located on-site in Plainview, with the remaining production sold to Martin Resource Management. In general, our fertilizer product revenues are margin-based in nature and based on price lists that vary from state to state. U N C O A T E D Sulfur We own and operate an integrated suite of specialized assets designed to gather, transport, store and process sulfur in the United States. In the United States, recovered sulfur is mainly kept in liquid (molten) form at a temperature of approximately 275 degrees Fahrenheit. Because of the temperature require- ment, the transportation and storage of molten sulfur requires specialized equipment. We have the necessary assets and expertise to handle the unique requirements for transporta- tion and storage of molten sulfur for domestic customers. We accomplish this using dedicated equipment that includes one offshore tow, one inland tow, 165 railcars and several trucks owned and operated by Martin Resource Management. Our customers include refiners and natural gas processing plants primarily located along the Gulf Coast and in the southwestern United States, respectively. In addition, we have the ability to process molten sulfur into pellet form using our sulfur prillers located in Beaumont, Texas and Stockton, California. Prilled sulfur is the preferred form of sulfur used in many agricultural and industrial applications outside of the United States. Our strategically located prilling facilities provide us with the ability to export prilled sulfur to world markets such as Asia and South America. Revenues for our sulfur business are generated through margin-based buy/ sell contracts that are typically one to five years in length. In addition, revenues are earned through fee-based contracts for the right to use our prilling facilities, as well as for the use of our barge transportation and sulfur storage assets. Sulfur-Based Fertilizer Fertilizer and related sulfur products are a natural extension of our sulfur business. Most of the fertilizer products we man- ufacture and market are sulfur-based, including products such as ammonium sulfate, ammonium thiosulfate, plant nutrient sulfur, nitrogen-phosphorous-potassium (NPK) prod- ucts, emulsified sulfur and other agricultural and industrial products. We have six sulfur-based fertilizer production plants, one emulsified sulfur blending plant and one sulfuric 8 Martin Midstream Partners 2008 Annual Report NARR 8 4/21/09 12:07:51 AM C O A T E D Exceptional Randy Tauscher (left) Executive VP—Sulfur Kilgore, TX Years of Service: 2 James Alford (right) Operations Supervisor Beaumont, TX Years of Service: 6 Martin Midstream Partners 2008 Annual Report 9 NARR 9 4/21/09 12:07:53 AM C O A T E D Leadership Howard Hackney (left) Director Longview, TX Years of Service: 4 Ruben Martin (right center) Chairman, President & CEO Kilgore, TX Years of Service: 33 John Gaylord (left center) Director Houston, TX Years of Service: 6 Scott Massey (right) Director Shreveport, LA Years of Service: 6 10 Martin Midstream Partners 2008 Annual Report NARR 10 4/21/09 12:07:56 AM U N C O A T E D Letter to Unitholders To Our Partners, What a difference a year makes. As I wrote to you in the spring of 2008, commodity prices were rapidly escalating to historic levels and the financial markets, while turbulent, were still functioning relatively well. Twelve months later, commod- ity prices have retreated dramatically and the financial capital markets have become inaccessible. Despite these challenges, we reported a 29% year-over-year increase in our distributable cash flow to $58.9 million and a 12% increase in our cash distributions for the year ended December 31, 2008 to $2.91 per limited partner unit. In addition, we strengthened our distribution coverage to 1.3 times, the highest in the part- nership’s history. How were we able to succeed in light of such difficult circum- stances? While our strategies of disciplined growth and a diversified asset base are both undoubtedly important, clearly our people are the ones that make the difference. They are the hard-working, dedicated men and women who have sacrificed countless hours committed to one common goal: the continued success of our partnership. They are excep- tional. Without them, I am confident that we would not have performed nearly as well as we did in 2008. Looking ahead to 2009, it is clear to me now, more than ever, that our people will continue to be the critical factor to the success of our partner- ship as we continue navigating uncertain waters. While we are optimistic that a broad-based economic recov- ery will eventually surface, we are positioning ourselves to weather the continuing storm. At a time when some com- panies are reverting to downsizing as a strategy to address an uncertain economic outlook, we are reaffirming our com- mitment to our people in consideration for their continued outstanding service. As I mentioned above, we have been lim- ited in our access to the capital markets which are necessary for the continued growth of our part- nership. As such, our business man agers have committed to a reduction in growth and maintenance capital in order to allow for more bal- ance sheet flexibility. In addition, we are currently pursuing non-strategic asset sales which represent minimal contri- bution to the historical cash flow of our partnership. These measures, coupled with a continued focus on existing opera- tions, should better position us to take advantage of future, long-term opportunities as the overall fundamentals improve. In short, we have temporarily reduced capital investments in hard assets while continuing to maintain the capital invested in our people. They are, after all, our most important asset. Ruben S. Martin President and Chief Executive Officer Yours truly, Yours truly, Ruben S. Martin Ruben S. Martin President and Chief Executive Officer Martin Midstream Partners 2008 Annual Report 11 NARR 11 4/21/09 12:07:57 AM U N C O A T E D Financial Highlights NASDAQ: MMLP Distributable Cash Flow (in millions) Distributions per L.P. Unit Revenue (in millions) $1,214 (in thousands, except per unit amounts) $766 $1,400 1,200 1,000 800 Total Assets 600 Revenue $576 Operating Income $438 $294 Net Income Distributable Cash Flow(1) Distributions per Unit(2) 400 200 0 1400000 1200000 1000000 800000 600000 400000 200000 (1) See Reconciliation on page following Form 10-K. 2007 (2) Actual distributions per unit. 2004 2005 2006 2008 0 $58.9 60000 50000 $45.6 $60.0 50.0 40.0 2004 $ 188,332 30.0 294,144 14,729 20.0 $18.0 12,326 10.0 18,026 2005 $32.1 2006 $ 389,044 $ 457,461 438,443 $21.1 18,960 13,880 21,133 576,384 26,609 22,243 32,140 40000 2007 2008 $ 623,577 30000 765,822 $ 668,916 1,213,958 28,876 20000 24,939 45,579 10000 49,591 42,810 58,900 $ 2.10 $ 2.19 $ 2.44 $ 2.60 $ 2.91 0 0 $2.91 $2.60 $2.44 $2.19 $2.10 $3.00 2.50 2.00 1.50 1.00 0.50 0 3.0 2.5 2.0 1.5 1.0 0.5 0.0 2004 2005 2006 2007 2008 2004 2005 2006 2007 2008 Revenue (in millions) Distributable Cash Flow (in millions) Distributions per L.P. Unit $1,400 1,200 1,000 800 600 400 200 0 $766 $576 $438 $294 $1,214 $60.0 50.0 40.0 30.0 20.0 10.0 0 $45.6 $32.1 $21.1 $18.0 $58.9 $3.00 2.50 2.00 1.50 1.00 0.50 0 $2.91 $2.60 $2.44 $2.19 $2.10 2004 2005 2006 2007 2008 2004 2005 2006 2007 2008 2004 2005 2006 2007 2008 12 Martin Midstream Partners 2008 Annual Report NARR 12 4/21/09 12:07:58 AM Form 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K Mark One [ X ] [ ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2008 OR 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 State or other jurisdiction of incorporation or organization 05-0527861 (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: Securities Registered Pursuant to Section 12(g) of the Act: NONE Title of each class Common Units representing limited partnership interests Name of each exchange on which registered NASDAQ Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:2)(cid:3) (cid:3) No (cid:4) 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 (cid:2)(cid:3) (cid:3) No (cid:4) 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 (cid:4) No (cid:2) 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. (cid:2) 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 (cid:2) Accelerated filer (cid:4) Non-accelerated filer (cid:2) Smaller reporting (cid:2) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:2)(cid:3) (cid:3) No (cid:4) As of June 30, 2008, 12,837,480 common units were outstanding. The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $306,811,495. There were 13,688,152 of the registrant’s common units and 850,674 of the registrant’s subordinated units outstanding as of March 4, 2009. DOCUMENTS INCORPORATED BY REFERENCE: None. TABLE OF CONTENTS Page PART I Item 1.(cid:2) Item 1A.(cid:2) Item 1B.(cid:2) Item 2. Item 3. Item 4. PART II Item 5. Item 6.(cid:2) Item 7.(cid:2) Item 7A.(cid:2) Item 8.(cid:2) Item 9.(cid:2) Item 9A.(cid:2) Item 9B.(cid:2) PART III Item 10.(cid:2) Item 11.(cid:2) Item 12.(cid:2) Item 13. Item 14. Business .................................................................................................................................................................. 1(cid:2) Risk Factors .......................................................................................................................................................... 25(cid:2) Unresolved Staff Comments ................................................................................................................................. 43(cid:2) Properties ...............................................................................................................................................................43(cid:2) Legal Proceedings..................................................................................................................................................44(cid:2) Submission of Matters to a Vote of Security Holders ............................................................................................44(cid:2) (cid:2) Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities ............44(cid:2) Selected Financial Data..........................................................................................................................................46(cid:2) Management’s Discussion and Analysis of Financial Condition and Results of Operations .................................47(cid:2) Quantitative and Qualitative Disclosures about Market Risk................................................................................ 66(cid:2) Financial Statements and Supplementary Data ......................................................................................................69(cid:2) Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ...............................105(cid:2) Controls and Procedures ..................................................................................................................................... 105(cid:2) Other Information ............................................................................................................................................... 105(cid:2) (cid:2) Directors and Executive Officers of the Registrant..............................................................................................107(cid:2) Executive Compensation......................................................................................................................................111(cid:2) Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .............117(cid:2) Certain Relationships and Related Transactions ..................................................................................................121(cid:2) Principal Accounting Fees and Services ..............................................................................................................128(cid:2) (cid:2) PART IV Item 15. (cid:2) Exhibits and Financial Statement Schedules........................................................................................................129(cid:2) i Item 1. Business Overview PART I We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Our four primary business lines include: (cid:2) Terminalling and storage services for petroleum products and by-products; (cid:2) Natural gas services; (cid:2) Marine transportation services for petroleum products and by-products; and (cid:2) Sulfur and sulfur-based products processing, manufacturing, marketing and distribution. The petroleum products and by-products we collect, transport, store and market are produced primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the Gulf Coast region of the United States. This region is a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry. We were formed in 2002 by Martin Resource Management Corporation (“Martin Resource Management”), a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of hydrocarbon products and by-products and other bulk liquids. Martin Resource Management owns an approximate 34.9% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest and incentive distribution rights in us. Martin Resource Management operated our business segments for several years. Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions. Primary Business Segments Our primary business segments can be generally described as follows: (cid:2) (cid:2) Terminalling and Storage. We own or operate 17 marine terminal facilities and six inland terminal facilities located in the United States Gulf Coast region that provide storage and handling services for producers and suppliers of petroleum products and by-products, lubricants and other liquids. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuel oil. We provide these terminalling and storage services on a fee basis primarily under long-term contracts. Natural Gas Services. Through our acquisitions of Prism Gas Systems I, L.P. (“Prism Gas”) and Woodlawn Pipeline Co., Inc. (“Woodlawn”), we have ownership interests in over 669 miles of gathering and transmission pipelines located in the natural gas producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico as well as a 265 MMcfd capacity natural gas processing plant located in East Texas. In addition to our natural gas gathering and processing business, we distribute natural gas liquids (“NGLs”). We purchase NGLs primarily from natural gas processors. We store NGLs in our supply and storage facilities for resale to propane retailers, refineries and industrial NGL users in Texas and the Southeastern United States. We own an NGL pipeline which spans approximately 200 miles running from Kilgore to Beaumont, Texas. We own three NGL supply and storage facilities with an aggregate above ground storage capacity of - 1 - approximately 3,000 barrels and we lease approximately 2.2 million barrels of underground storage capacity for NGLs. (cid:2) Marine Transportation. We own a fleet of 40 inland marine tank barges, 17 inland push boats and four offshore tug barge units that transport petroleum products and by-products primarily in the United States Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts. In addition, our marine segment manages our sulfur segment’s marine assets. (cid:2) Sulfur Services. We process and distribute sulfur predominately produced by oil refineries primarily located in the United States Gulf Coast region. We own one offshore tug barge unit and two inland barges and an inland tug that transports sulfur primarily in the United States Gulf Coast region. We process molten sulfur into prilled, or pelletized, sulfur under both fee-based volume contracts and buy/sell contracts at our facilities in Port of Stockton, California and Beaumont, Texas. We own and operate six sulfur-based fertilizer production plants and one emulsified sulfur blending plant that manufacture primarily sulfur-based fertilizer products for wholesale distributors and industrial users. These plants are located in Illinois, Texas and Utah. In October 2007, we completed the construction of a sulfuric acid production plant in Plainview, Texas which processes molten sulfur into sulfuric acid. 2008 Developments and Subsequent Events Recent Acquisitions Acquisition of Martin Resource Management Stanolind Assets. In January 2008, we acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at our Stanolind terminal in Beaumont, from Martin Resource Management. In connection with this acquisition, we entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks. Other Developments Quarterly Distribution. We declared a quarterly cash distribution for the fourth quarter of 2008 of $0.75 per common and subordinated unit on January 27, 2009, reflecting no change over the quarterly distribution paid in respect of the third quarter of 2008. Conversion of Subordinated Units. On November 14, 2008, 850,672 of our 1,701,346 outstanding subordinated units owned by Martin Resource Management through a subsidiary converted into common units on a one-for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding subordinated units may occur in the future provided that certain distribution thresholds contained in our partnership agreement are met by us. Business Strategy The key components of our business strategy are to: (cid:2) (cid:2) (cid:2) Pursue Organic Growth Projects. We continually evaluate economically attractive organic expansion opportunities in new or existing areas of operation that will allow us to leverage our existing market position, increase the distributable cash flow from our existing assets through improved utilization and efficiency, and leverage our existing customer base. Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to Existing Customers. We seek to identify and pursue opportunities to expand our customer base across all of our business segments. We generally begin a relationship with a customer by transporting or marketing a limited range of products and services. We believe expanding our customer base and our service and product offerings to existing customers is the most efficient and cost effective method of achieving organic growth in revenues and cash flow. We believe significant opportunities exist to expand our customer base and provide additional services and products to existing customers. Pursue Strategic Acquisitions. We monitor the marketplace to identify and pursue accretive acquisitions that expand the services and products we offer or that expand our geographic presence. After acquiring other businesses, we will attempt to utilize our industry knowledge, network of customers and suppliers and strategic asset base to operate the acquired businesses more efficiently and competitively, thereby - 2 - (cid:2) (cid:2) increasing revenues and cash flow. We believe that our diversified base of operations provides multiple platforms for strategic growth through acquisitions. While we continue to monitor the marketplace for potential acquisitions, we anticipate that our activities in this area will be limited in 2009 due to general economic conditions and capital constraints. Pursue Strategic Alliances. Many of our larger customers are establishing strategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operational synergies. These strategic alliances are typically structured differently than our regular commercial relationships, with the goal that such alliances would expand our business relationships with our customers and suppliers. We intend to pursue strategic alliances with customers in the future. Expand Geographically. We work to identify and assess other attractive geographic markets for our services and products based on the market dynamics and the cost associated with penetration of such markets. We typically enter a new market through an acquisition or by securing at least one major customer or supplier and then dedicating or purchasing assets for operation in the new market. Once in a new territory, we seek to expand our operations within this new territory both by targeting new customers and by selling additional services and products to our original customers in the territory. Competitive Strengths We believe we are well positioned to execute our business strategy because of the following competitive strengths: (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) Asset Base and Integrated Distribution Network. We operate a diversified asset base that, together with the services provided by Martin Resource Management, enables us to offer our customers an integrated distribution network consisting of transportation, terminalling and midstream logistical services while minimizing our dependence on the availability and pricing of services provided by third parties. Our integrated distribution network enables us to provide customers a complementary portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by- products. Strategically Located Assets. We believe we are one of the largest providers of shore bases and one of the largest lubricant distributors and marketers in the United States Gulf Coast region. In addition, we are one of the largest operators of marine service terminals in the United States Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas gathering and processing assets are focused in areas that have continued to experience high levels of drilling activity and natural gas production. Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to handle and transport certain petroleum products and by-products with unique requirements for transportation and storage, such as molten sulfur and asphalt. For example, we own facilities and resources to transport molten sulfur and asphalt, which must be maintained at temperatures between approximately 275 and 350 degrees Fahrenheit to remain in liquid form. We believe these capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements. Ability to Grow Our Natural Gas Gathering and Processing Services. We believe that, with our Prism Gas assets, we have opportunities for organic growth in our natural gas gathering and processing operations through increasing fractionation capacity, pipeline expansions, new pipeline construction and bolt-on acquisitions. We believe Prism’s assets are well situated in the Haynesville Shale which is one of the four largest U.S. shale deposits. Chesapeake Energy, the largest lease holder in the Haynesville Shale, estimates that the Haynesville Shale will ultimately produce over 500 TCF of natural gas and that this field will be among the top 10 natural gas fields in the world. As the development of the Haynesville Shale is in its early stages, it is too early to estimate the ultimate impact on Prism. Experienced Management Team and Operational Expertise. Members of our executive management team and the heads of our principal business lines have, on average, more than 29 years of experience in the industries in which we operate. Further, these individuals have been employed by Martin Resource Management, on average, for more than 17 years. Our management team has a successful track record of creating internal growth and completing acquisitions. We believe our management team’s experience and - 3 - familiarity with our industry and businesses are important assets that assist us in implementing our business strategies. (cid:2) Strong Industry Reputation and Established Relationships with Suppliers and Customers. We believe we have established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient operation of our facilities. Our management has also established long-term relationships with many of our suppliers and customers. We believe we benefit from our management’s reputation and track record, and from these long-term relationships. Terminalling and Storage Segment Industry Overview. The United States petroleum distribution system moves petroleum products and by-products from oil refinery and natural gas processing facilities to end users. This distribution system is comprised of a network of terminals, storage facilities, pipelines, tankers, barges, rail cars and trucks. Terminals play a key role in moving these products throughout the distribution system by providing storage, blending and other ancillary services. In the 1990s, the petroleum industry entered a period of consolidation. Refiners and marketers developed large- scale, cost-efficient operations resulting in several refinery acquisitions, combinations, alliances and joint ventures. This consolidation resulted in major oil companies integrating the various components of their businesses, including terminalling and storage. However, major integrated oil companies later concentrated their focus and resources on their core competencies of exploration, production, refining and retail marketing and examined ways to lower their distribution costs. Additionally, the Federal Trade Commission required some divestitures of terminal assets in markets in which merged companies, alliances and joint ventures were regarded as having excessive market power. As a result of these factors, oil and gas companies began to increasingly rely on third parties such as us to perform many terminalling and storage services. Although many large energy and chemical companies own terminalling and storage facilities, these companies also use third party terminalling and storage services. Major energy and chemical companies typically have a strong demand for terminals owned by independent operators when such terminals are strategically located at or near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of lack of capacity, the nature of the stored material or specialized handling requirements. The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of United States refining capacity expansion in the 1990s occurred in this region. Growth in the refining and natural gas processing industries has increased the volume of petroleum products and by-products that are transported within the Gulf Coast region, which consequently has increased the need for terminalling and storage services. The marine and offshore oil and gas exploration and production industries use terminal facilities in the Gulf Coast region as shore bases that provide them logistical support services as well as provide a broad range of products, including fuel oil, lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly influenced by current and projected prices of oil and natural gas. Marine Terminals. We own or operate 17 marine terminals along the Gulf Coast from Tampa, Florida to Corpus Christi, Texas. Our terminal assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. Further, the location and composition of our terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated services in the handling and transportation of petroleum products and by-products. We developed our terminalling and storage assets by acquiring existing terminalling and storage facilities and then customizing and upgrading these facilities as needed to integrate the facilities into our petroleum product and by-product transportation network and to more effectively service customers. We expect to continue to acquire facilities, streamline their operations and customize and upgrade them as part of our growth strategy. We also continually evaluate opportunities to add services and increase access to our terminals to attract more customers and create additional revenues. We are one of the largest operators of marine service terminals in the Gulf Coast region. These terminals are used to distribute and market lubricants and the full service terminals also provide shore bases for companies that are operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production companies and oilfield service companies such as drilling fluid companies, marine transportation companies, and offshore - 4 - construction companies. Shore bases typically provide logistical support including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. We also generate revenues through the distribution and marketing of lubricants. Lubricants are used in the operation of offshore drilling rigs, offshore production and transmission platforms, and various ships and equipment engaged in marine transportation. In addition, Martin Resource Management, through contractual arrangements, pays us for terminalling and storage of fuel oil at these terminal facilities. Our 17 marine terminals are divided generally into three classes of terminals: (i) full service terminals, (ii) fuel and lubricant terminals and (iii) specialty petroleum terminals. Full Service Terminals. We own or operate eight full service terminals. These terminal facilities provide logistical support services, distribute and market lubricants and provide storage and handling services for fuel oil. The significant difference between our full service terminals and our fuel and lubricant terminals is that our full service terminals generate additional revenues by providing shore bases to support our customer’s operating activities related to the offshore exploration and production industry. One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drilling industry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore operations. Customers are primarily oil and gas exploration and production companies, and oilfield service companies such as drilling fluids companies, marine transportation companies, and offshore construction companies. The following is a summary description of our eight full service terminals: Terminal Location Acres Tanks Aggregate Capacity Pelican Island ............ Galveston, Texas Harbor Island(1)........ Harbor Island, Texas Freeport ..................... Freeport, Texas Port O’Connor(2) ...... Port O’Connor, Texas Sabine Pass(3)........... Sabine Pass, Texas Cameron “East”(4).... Cameron, Louisiana Cameron “West”(5)... Cameron, Louisiana Venice (6) …………. Venice, Louisiana 51.3 25.5 17.8 22.8 23.1 34.3 16.9 2.8 16 12 1 8 11 12 5 2 87,200 Bbls. 32,500 Bbls. 8,300 Bbls. 7,000 Bbls. 17,000 Bbls. 34,000 Bbls. 16,500 Bbls. 15,000 Bbls. _________ (1) A portion of this terminal is located on land owned by a third party and leased under a lease that expires in January 2010 and can be extended by us through January 2015. (2) This terminal is located on land owned by a third party and leased under a lease that expires in March 2014. (3) A portion of this terminal is located on land owned by a third party and leased under a lease that expires in September 2036. (4) This terminal is located on land owned by third parties and leased under a lease that expires in March 2012 and can be extended by us through March 2022. (5) This terminal is located on land owned by a third party and leased under a lease that expires in February 2013. (6) This terminal is located on land owned by a third party and leased under a sublease agreement that expires in August 2009 and can be extended by us through August 2024. Fuel and Lubricant Terminals. We own or operate four lubricant and fuel oil terminals located in the Gulf Coast region that provide storage and handling service for lubricants and fuel oil. We also distribute and market lubricants at these terminals. - 5 - The following is a summary description of our fuel and lubricant terminals: Terminal Location Tanks Aggregate Capacity Amelia ........................ Amelia, Louisiana Berwick(1).................. Berwick, Louisiana Intracoastal City(2)(3) Fourchon(4) ................ Fourchon, Louisiana Intracoastal City, Louisiana 17 2 16 11 14,900 Bbls. 25,000 Bbls. 39,000 Bbls. 80,000 Bbls. __________ (1) This terminal is located on land owned by third parties and leased under a lease that expires in September 2012 and can be extended by us through September 2017. (2) A portion of this terminal is located on land owned by a third party at which we throughput fuel oil pursuant to an agreement that expires in January 2010. (3) A portion of this terminal is located on land owned by third parties and leased under a lease that expires in April 2014. (4) This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an agreement that expires in January 2017. Specialty Petroleum Terminals. We own or operate five terminal facilities providing storage and handling services for some or all of the following: anhydrous ammonia, asphalt, sulfur, sulfuric acid, fuel oil, crude oil and other petroleum products and by-products. Our specialty terminals have an aggregate storage capacity of approximately 1.90 million barrels. Each of these terminals has storage capacity for petroleum products and by-products and has assets to handle products transported by vessel, barge and truck. Our Tampa terminal is located on approximately 10 acres of land owned by the Tampa Port Authority that was leased to us under a 10-year lease that commenced on December 16, 2006 with two five year options. Our Stanolind terminal is located on approximately 11 acres of land owned by us located on the Neches River in Beaumont. Our Neches terminal is a deep water marine terminal located near Beaumont, Texas on approximately 50 acres of land owned by us. Our Ouachita County terminal is located on approximately six acres of land owned by us on the Ouachita River in southern Arkansas. Our Corpus Christi terminal is located on approximately 25 acres of land owned by us and has access to the waterfront via marine docks owned by the Port of Corpus Christi. At our Tampa, Neches, Stanolind and Corpus Christi terminals, our customers are primarily large oil refining and natural gas processing companies. We charge either a fixed monthly fee or a throughput fee for the use of our facilities, based on the capacity of the applicable tank. We conduct a substantial portion of our terminalling and storage operations under long-term contracts, which enhances the stability and predictability of our operations and cash flow. We attempt to balance our short term and long term terminalling contracts in order to allow us to maintain a consistent level of cash flow while maintaining flexibility to earn higher storage revenues when demand for storage space increases. At our Ouachita County terminal, Cross Oil Refining & Marketing, Inc., a related party owned by Martin Resource Management, operates the terminal under a long-term terminalling agreement whereby we receive a throughput fee. We also continually evaluate opportunities to add services and increase access to our terminals to attract more customers and create additional revenues. The following is a summary description of our specialty marine terminals: - 6 - Terminal Location Tampa(1)................. Tampa, Florida Tanks 8 Aggregate Capacity 779,000 Bbls. Description Asphalt, sulfur and fuel oil Marine terminal, Products Stanolind ................. Beaumont, Texas 8 555,000 Bbls. Asphalt, crude oil, sulfur, sulfuric acid and fuel oil Neches..................... Beaumont, Texas 7 500,400 Bbls. Ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer Ouachita County...... Ouachita County, 2 77,500 Bbls. Crude oil Arkansas Corpus Christi ......... Corpus Christi, 4 330,000 Bbls. Fuel oil and diesel Texas loading/unloading for vessels, barges and trucks Marine terminal, marine dock for loading/unloading of vessels, barges, railcars and trucks Marine terminal, loading/unloading for vessels, barges, railcars and trucks Marine terminal, loading/unloading for barges and trucks Marine Terminal, loading/unloading barges and vessels and unloading trucks __________ (1) This terminal is located on land owned by the Tampa Port Authority that was leased to us under a 10-year lease that expires in December 2016 with two five year extension options. Inland Terminals. We own or operate six inland terminals. At Mont Belvieu, Texas, we own a rail unloading terminal where we unload and measure NGLs and transport these products via a half-mile pipeline to Enterprise Products Texas Operating L.P.’s NGL fractionator facility. Our fees for the use of this facility are based on the number of gallons unloaded at the terminal. In Beaumont, Texas we own Spindletop Terminal where we receive natural gasoline via pipeline and then ship the product to our customers via other pipelines to which the facility is connected. Our fees for the use of this facility are based on the number of barrels shipped from the terminal. In Channelview, Texas, we operate an inland terminal used for lubricant storage, packaging and distribution. This terminal is used as our central hub for lubricant distribution where we receive, package, and ship our lubricants to our terminals or directly to customers. In Houston, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates. In Port Neches, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based upon throughput rates. In Omaha, Nebraska, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates. The following is a summary description our inland terminals: Terminal Location Channelview ...... Houston, Texas Aggregate Capacity 34,000 sq. ft. Warehouse/29,000 Bbls Products Lubricants Mont Belvieu ..... Mont Belvieu, Texas 20 rail car spaces Propane- propylene mix South Houston Description Lubricants blending and truck loading/unloading Rail car unloading - 7 - Asphalt............... Houston, Texas 71,000 Bbls Asphalt Port Neches Asphalt............... Port Neches, Texas 31,250 Bbls Asphalt Omaha Asphalt .. Omaha, Nebraska 114,225 Bbls Asphalt Asphalt Processing and storage Asphalt Processing and storage Asphalt Processing and storage Spindletop .......... Beaumont, Texas 90,000 Bbls Natural Gasoline Pipeline receipts and shipments Competition. We compete with independent terminal operators and major energy and chemical companies that own their own terminalling and storage facilities. We believe many customers prefer to contract with independent terminal operators rather than terminal operators owned by integrated energy and chemical companies that may have refining or marketing interests that compete with the customers. Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably-located terminal has access to various cost effective transportation modes, both to and from the terminal, such as waterways, railroads, roadways and pipelines. Terminal versatility depends upon the operator’s ability to handle diverse products, some of which have complex or specialized handling and storage requirements. The service function of a terminal includes, among other things, the safe storage of product at specified temperature, moisture and other conditions, and receiving and delivering product to and from the terminal. All of these services must be in compliance with applicable environmental and other regulations. We believe we successfully compete for terminal customers because of the strategic location of our terminals along the Gulf Coast, our integrated transportation services, our reputation, the prices we charge for our services and the quality and versatility of our services. Additionally, while some companies have significantly more terminalling and storage capacity than us, not all terminalling and storage facilities located in the markets we serve are equipped to properly handle specialty products such as asphalt, sulfur and sulfuric acid. As a result, our facilities typically command higher terminal fees when compared to fees charged for terminalling and storage of other petroleum products. The principal competitive factors affecting our terminals which provide lubricant distribution and marketing as well as shore bases at certain terminals, are the locations of the facilities, availability of competing logistical support services, and the experience of personnel and dependability of service. The distribution and marketing of our lubricant products is brand sensitive, and we encounter brand loyalty competition. Shore base rental contracts are generally long- term contracts and provide more protection from competition. Our primary competitors for both lubricants and shore bases include several independent operations as well as major companies that maintain their own similarly equipped marine terminals, shore bases and lubricant supply sources. Natural Gas Services Segment NGL Industry Overview. NGLs are produced through natural gas processing. They are also a by-product of crude oil refining. NGL consists of hydrocarbons that are vapors at atmospheric temperatures and pressures but change to liquid phase under pressure. NGLs include ethane, propane, normal butane, iso butane and natural gasoline. Ethane is almost entirely used as a petrochemical feedstock in the production of ethylene and propylene. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a fuel for heating, for industrial applications, as motor fuel and as a refrigerant. Normal butane is used as a petrochemical feedstock, as a blend stock for motor gasoline and as a component in aerosol propellants. Normal butane can also be made into iso butane through isomerization. Iso butane is used in the production of motor gasoline, petrochemical feedstock and as a component in aerosol propellants. Natural gasoline is used as a component of motor gasoline and as a petrochemical feedstock. NGL Facilities. We purchase NGLs primarily from natural gas processors and, to a lesser extent, major domestic oil refiners. We transport NGLs using Martin Resource Management’s land transportation fleet or by contracting with common carriers, owner-operators and railroad tank cars. We typically enter into annual contracts with independent retail propane distributors to deliver their estimated annual volume requirements based on prevailing market prices. We believe dependable delivery is very important to these customers and in some cases may be more important than price. We ensure adequate supply of NGLs through: - 8 - (cid:2) (cid:2) (cid:2) 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) Retail terminals __________ Hattiesburg, Mississippi(2) Mt. Belvieu, Texas(3)(2) Kilgore, Texas Longview, Texas Henderson, Texas 2,000,000 barrels 100,000 barrels 40,000 barrels 90,000 gallons 30,000 gallons 12,000 gallons Underground storage Underground storage Underground storage Retail propane distribution Retail propane distribution Retail propane distribution (1) We lease our underground storage at Arcadia, Louisiana from Martin Resource Management under a three-year product storage agreement, which is renewable on a yearly basis thereafter subject to a re-determination of the lease rate for each subsequent year. (2) We lease our underground storage at Hattiesburg, Mississippi and Mont Belvieu, Texas from third parties under one-year lease agreements, which have been renewed annually for more than 20 years. (3) In addition, under a throughput agreement, we are entitled to the sole access to and use of a truck loading and unloading and pipeline distribution terminal owned by Martin Resource Management and located at Mont Belvieu, Texas. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. This terminal facility has a storage capacity of 8,000 barrels. Our NGL customers that utilize these assets consist of retail propane distributors, industrial processors and refiners. For the year ended December 31, 2008, we sold approximately 34% of our NGL volume to independent retail propane distributors located in Texas and the southeastern United States and approximately 66% of our NGL volume to refiners and industrial processors. NGL Competition. We compete with large integrated NGL producers and marketers, as well as small local independent marketers. NGLs compete primarily with natural gas, electricity and fuel oil as an energy source, principally on the basis of price, availability and portability. NGL Seasonality. The level of NGL supply and demand is subject to changes in domestic production, weather, inventory levels and other factors. While production is not seasonal, residential and wholesale demand is highly seasonal. This imbalance causes increases in inventories during summer months when consumption is low and decreases in inventories during winter months when consumption is high. If inventories are low at the start of the winter, higher prices are more likely to occur during the winter. Additionally, abnormally cold weather can put extra upward pressure on prices during the winter because there are less readily available sources of additional supply except for imports which are less accessible and may take several weeks to arrive. General economic conditions and inventory levels have a greater impact on industrial and refinery use of NGLs than the weather. We generally maintain consistent margins in our natural gas services business because we attempt to pass increases and decreases in the cost of NGLs directly to our customers. We generally try to coordinate our sales and purchases of NGLs based on the same daily price index of NGLs in order to decrease the impact of NGL price volatility on our profitability. Prism Gas. Prism Gas is operated and reported as part of our natural gas services business segment, which has been expanded to include natural gas gathering and processing as well as the NGL services business described herein. Prism Gas has ownership interests in over 669 miles of gathering pipelines located in the natural gas producing regions of North Central Texas and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico as well as a 265 MMcfd natural gas processing plant located in East Texas. The underlying assets are in two operating areas: - 9 - North Central Texas and East Texas The North Central Texas and East Texas area assets consist of the Waskom Processing Plant, Woodlawn Pipeline Co., the McLeod Gathering System, the Hallsville Gathering System, the Marshall Line, Bosque County Pipeline (“BCP”), the East Texas Gathering System and the Prism Liquids Pipeline. • • • (cid:2)(cid:3) (cid:2)(cid:3) (cid:2)(cid:3) (cid:2) Waskom Processing Plant — The Waskom Processing Plant, located in Harrison County in East Texas, currently has 265 MMcfd of processing capacity with full fractionation facilities. Expansions to the processing plant were completed in March and June of 2007, and July of 2008 increasing the capacity from 150 MMcfd to 265 MMcfd. In January 2007, the Waskom fractionator was expanded to a capacity of 12,500 barrels per day (“bpd”). In addition, an increase in the processing capacity of the plant to 285 MMcfd and fractionation capacity to 14,500 bpd is expected to be completed by the end of the second quarter of 2009. For the years ended December 31, 2008 and 2007, inlet throughput and NGL fractionation averaged approximately 257 and 229 MMcfd and 10,542 and 8,725 bpd, respectively. Prism Gas owns an unconsolidated 50% operating interest in the Waskom Processing Plant with CenterPoint Energy Gas Processing, Inc. owning the remaining 50% non-operating interest. We reflect the results of operations from this facility using the equity method of accounting. Woodlawn Plant and Gathering System — On May 2, 2007, we, through our subsidiary Prism Gas acquired 100% of the outstanding stock of Woodlawn. The results of Woodlawn’s operations have been included in our consolidated financial statements beginning May 2, 2007. Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 MMcfd processing plant. Prism Gas acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from the Woodlawn plant to the Texas Eastern Transmission pipeline system. McLeod Gathering System — The McLeod Gathering System, located in East Texas and Northwest Louisiana, is a low pressure gathering system connected to the Waskom Processing Plant, providing processing and blending services for natural gas with high nitrogen and high liquids content gathered by the system. For both years ended December 31, 2008 and 2007, the McLeod Gathering System gathered approximately 5 MMcfd of natural gas. Prism Gas owns a consolidated 100% interest in this system. Hallsville Gathering System — The Hallsville Gathering System, which Prism Gas constructed in 2006 in Harrison County, Texas, provides gathering and centralized compression for producers in the Oak Hill Field of East Texas. The system operates at low pressure and redelivers gas to two interstate and three intrastate markets via the Oakhill Gathering System. For the years ended December 31, 2008 and 2007, the Hallsville Gathering System gathered approximately 21 and 17 MMcfd of natural gas, respectively. Prism Gas owns a consolidated 100% interest in this system. The Marshall Line — The Marshall Line is a 10” gathering line that Prism Gas began leasing from Kinder Morgan Texas in 2006. It is located in Harrison County, Texas. The Marshall Line gathers gas at intermediate pressure and feeds the Waskom Processing Plant. Prism Gas owns a consolidated 100% interest in the lease. Bosque County Pipeline — The Bosque County Pipeline, gathers gas in four North Central Texas counties centered around Bosque County. Prism Gas owns an unconsolidated 20% non-operating interest in a partnership that owns the lease rights to the assets of the Bosque County Pipeline, with Panther Pipeline Ltd. owning a 42.5% operating interest and two unrelated parties owning the remaining 37.5% interest. The lease contract provides for termination in June 2009 and an extension of the lease is not currently contemplated. East Texas Gathering System — The East Texas Gathering System, located in Panola County, Texas, is comprised of gathering systems built to gather gas produced in this area to market outlets. Prism Gas owns a consolidated 100% interest in these systems. - 10 - The natural gas supply for the Waskom Processing Plant, the Woodlawn Plant and Gathering System, the McLeod Gathering System, the Hallsville Gathering System, the Marshall Line and the East Texas Gathering System is derived primarily from natural gas wells located in the Cotton Valley formation of East Texas and Northwest Louisiana. The Cotton Valley formation is one of the largest tight gas plays in the U.S. and extends over fourteen counties in East Texas and into Northwest Louisiana. Prism Gas’ East Texas Operating Area includes assets that provide gathering and processing services to producers in Cass, Gregg, Harrison, Panola, and Rusk Counties, Texas and Caddo Parish, Louisiana. The total number of wells permitted in Prism Gas’ East Texas Operating Area was 2,323 and 2,290 in calendar years 2008 and 2007, respectively. These annual permit numbers include 261 permits for horizontal wells in 2008 and 83 permits for horizontal wells in 2007. Improved technology and drilling applications have enhanced the economics of drilling in the Cotton Valley formation. This increase in drilling activity has provided us with access to newly developed natural gas supplies. However, we anticipate that drilling activity in 2009 will be negatively impacted by low commodity prices and capital constraints. In addition, emphasis in the area will shift from predominantly Cotton Valley drilling to a blend of Cotton Valley and Haynesville formation drilling. Our primary suppliers of natural gas to the Waskom Processing Plant include BP America Production Company, Centerpoint Energy Gas Transmission Company and Devon Energy Corporation, which collectively represented approximately 72% of the 229 MMcfd of natural gas supplied in 2007 and approximately 70% of the 257 MMcfd of natural gas supplied for the year ended December 31, 2008. A substantial portion (approximately 27%) of the Waskom Processing Plant’s inlet volumes are derived from production at BP’s Blocker, East Mountain, Carthage and Woodlawn fields in East Texas. Production from these fields is dedicated to the Waskom Processing Plant under a contract with BP for the life of the Waskom partnership. We receive natural gas at the Waskom Processing Plant from our McLeod Gathering System. We also receive a significant amount of trucked-in NGLs that are fractionated, treated and stabilized at the Waskom Processing Plant. The tightening of pipeline dew point specifications and access to local markets with high NGL demand has resulted in increased trucked-in NGL volumes at the Waskom Processing Plant. In October 2006, we began construction to expand the fractionator to 12,500 bpd to provide additional capacity for both the increase in NGL volumes from the plant expansions that were underway and this increase in trucked-in NGL volumes. This expansion was completed in late January 2007. The processing plant was expanded to 265 MMcfd in three phases with the first expansion of 30 MMcfd being completed in March 2007, the second expansion of 70 MMcfd being completed in June 2007 and the third phase of 15 Mmcfd being completed in July 2008. There are currently six processing plants that compete with Waskom for natural gas supplies. Drilling activity in the Cotton Valley trend is moving north from the Panola-Harrison County line further into Harrison County. Our plant is the preferred gas plant for much of this new production due to its proximity to the increased drilling activity. In addition, the Waskom Processing Plant is the only plant in this area that has full fractionation capability with access to strong local markets for NGLs. Purchasers of NGLs fractionated at Waskom include various chemical companies and other industrial distributors. The processing contracts for the Waskom Processing Plant are primarily percent-of-liquids (“POL”) contracts, in which we retain a portion of the NGLs recovered as a processing fee, percent-of-proceeds (“POP”) contracts in which we retain a portion of both the residue gas and the NGLs as payment for services and straight fee contracts in which we receive a fee for every Mcf of gas delivered to the plant. Currently, approximately 50% of the contracts are POL, 30% of the contracts are fee and 20% of the contracts are POP. In addition, there is one minor contract for processing on a keep-whole basis. Woodlawn provides gathering and processing services. The Woodlawn gathering system provides both low and intermediate pressure gathering services. The gas is gathered to a 30 MMcfd refrigerated gas processing plant. The NGL’s that are recovered at Woodlawn are trucked to the Waskom Processing Plant for fractionation. In 2007, after acquiring Woodlawn, the system gathered and processed 21 MMcfd and recovered 223 bpd of NGL’s. For the year ended December 31, 2008, the system gathered and processed 24 MMcfd and recovered 247 bpd of NGL’s. The contracts on the Woodlawn system are primarily wellhead purchase with some POP contracts. The McLeod Gathering System is a low-pressure gathering system that provides an outlet for high nitrogen and high liquids content gas. In June 2003, Prism Gas constructed a pipeline to tie the McLeod Gathering System to the Waskom Processing Plant to provide an outlet for high nitrogen gas. As a result, the majority of gas gathered on the McLeod Gathering System is transported to the Waskom Processing Plant for processing and blending. Revenue from the McLeod Gathering System is earned through gathering and compression fees and processing revenue. The processing revenue results from the difference in the processing agreements with the producers and the agreement that we have with the Waskom partnership. The processing contracts in the McLeod Gathering System are predominately - 11 - POP contracts. Natural gas gathered in the region surrounding the McLeod Gathering System has two primary outlets, including the Waskom Processing Plant. Cotton Valley wells are now being drilled in the southern area served by the McLeod Gathering System. The new Cotton Valley wells that have recently been tied into the system are POL contracts with a small gathering fee. These contracts are typically lower margin, higher volume contracts. In this area, competition is geographic based with the McLeod Gathering System capturing wells that are located near the system and the competitor capturing wells that are near its system. The Hallsville Gathering System was constructed in 2005 and 2006 to gather low pressure gas. The wells tied into the system are fee based gathering contracts. The Marshall Line was leased from Kinder Morgan to provide additional sources of gas for the Waskom Processing Plant. The gas on the system is from Cotton Valley production and is tied into the system under percent of index based contracts. The BCP is an approximate 67 mile pipeline located in the Barnett Shale extension. The East Texas Gathering System was constructed in 2004 to tie producers into DCP Midstream’s gathering system in Panola County, Texas. These lines are sized to handle volumes that are expected to increase as producers continue to develop Cotton Valley sands in areas that were traditionally marginal. The existing East Texas Gathering System contracts are all fee-for-service contracts dependent on volumes gathered. The Prism Liquids Pipeline condensate system was formed from the condensate pipeline system obtained in the Woodlawn acquisition. The system was subsequently extended approximately 10 miles using lateral lines to gather condensate from additional locations. The pipeline is a common carrier under the Rules and Regulations of the Railroad Commission of Texas, Oil and Gas Division and, as such, operates under a tariff filed with the Railroad Commission of Texas. The system gathers and transports condensate for producers along the main line which extends south from the Woodlawn Plant to the Carthage Plant operated by DCP Midstream. Gulf Coast The Gulf Coast area assets consist of the Fishhook Gathering System and the Matagorda Offshore Gathering System (“Matagorda”) located offshore and onshore of the Texas Gulf Coast. (cid:2) (cid:2) Fishhook Gathering System — The Fishhook Gathering System, located in Jefferson County, Texas and offshore federal waters, gathers and transports gas in both offshore and onshore areas. For the year ended December 31, 2007, the Fishhook Gathering System gathered and transported approximately 32 MMcfd of natural gas. In September 2008, Hurricane Ike caused extensive damage to an offshore platform on the system. Repairs were completed in February 2009. Prior to the hurricane damage approximately 15 MMcfd of natural gas was gathered and transported for the year ended December 31, 2008. Prism Gas owns an unconsolidated 50% non-operating interest in Panther Interstate Pipeline Energy, LLC (“PIPE”), the owner of the Fishhook Gathering System, with Panther Pipeline Ltd owning the remaining 50% operating interest. We reflect the results of operations from this system using the equity method of accounting. Matagorda Offshore Gathering System — The Matagorda Offshore Gathering System, located in Matagorda County, Texas and offshore Texas State waters, gathers gas in both the offshore and onshore areas. For the years ended December 31, 2008 and 2007, the Matagorda Offshore Gathering System gathered approximately 15 and 7 MMcfd of natural gas, respectively. Prism Gas owns an unconsolidated 50% non-operating interest in the Matagorda Offshore Gathering System, with Panther Pipeline Ltd. owning the remaining 50% operating interest. We reflect the results of operations from this system using the equity method of accounting. The Fishhook Gathering System and the Matagorda Offshore Gathering System gather and transport natural gas from Texas and federal waters of the Gulf of Mexico to onshore pipelines. The Fishhook Pipeline gathers and transports natural gas principally from the eastern portion of the High Island Area which is further offshore. The - 12 - offshore natural gas supply for the Matagorda Offshore Gathering System is produced primarily from the Brazos Area blocks, which are near shore in the Texas State waters. Additionally, the Matagorda Offshore Gathering System includes onshore gathering in Matagorda, Wharton and Brazoria Counties. The Fishhook Gathering System is located in federal waters offshore from Beaumont, Texas and gathers gas from producers. This area is characterized by strong drilling activity with traditionally high volume, high decline wells. Typically, two to four of these traditional wells are drilled near the Fishhook Gathering System each year. Contracts on this system are 100% fee-for-service contracts with both the gathering fee and the maximum transmission fee stated in PIPE’s FERC Gas Tariff, on file with the Federal Energy Regulatory Commission. There are currently two competing pipelines in the area which limit our ability to increase margins on this system. However, we believe that our existing relationships with active producers will enable us to capture additional volumes from new production in this area. The Matagorda Offshore Gathering System gathers gas from producers. Contracts for the offshore portion of the Matagorda Offshore Gathering System are a combination of fixed transportation fees plus a fixed margin. The contracts for the onshore portion of the Matagorda Offshore Gathering System are under either a fixed margin or a fixed transportation fee. There is limited competition for the offshore portion of the pipeline. There are currently two pipelines situated in the offshore area but they primarily gather natural gas from wells further offshore than the Matagorda Offshore Gathering System. There are several pipelines that compete with the onshore portion of the system. These competing pipelines result in lower margins for the onshore portion of this system. Marine Transportation Segment Industry Overview. The United States inland waterway system is a vast and heavily used transportation system. This inland waterway system is composed of a network of interconnected rivers and canals that serve as water highways and is used to transport vast quantities of products annually. This waterway system extends approximately 26,000 miles, of which 12,000 miles are generally considered significant for domestic commerce. The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of United States refining capacity expansion in the 1990s occurred in this region. The hydrocarbon refining process generates products and by- products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this waterway system by the petroleum and petrochemical industry is a major reason for the current location of United States refineries and petrochemical facilities. Recent growth in refining and natural gas processing capacity has increased the volume of petroleum products and by-products transported within the Gulf Coast region, which consequently has increased the need for transportation, storage and distribution facilities. The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight capacity. The combination of the power source and tank barge freight capacity is called a tow. Marine Fleet. We own a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products produced in oil refining and natural gas processing. Our marine transportation system operates coastwise along the Gulf of Mexico and on the United States inland waterway system, primarily between domestic ports along the Gulf of Mexico Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system. Our inland tows generally consist of one push boat and one to three tank barges, depending upon the horsepower of the push boat, the river or canal capacity and conditions, and customer requirements. Each of our offshore tows consist of one tugboat, with much greater horsepower than an inland push boat, and one large tank barge. We transport asphalt, fuel oil, gasoline, sulfur and other bulk liquids. The following is a summary description of the marine vessels we use in our marine transportation business: Class of Equipment Number in Class Capacity/Horsepower Description of Products Carried Inland tank barges ....... Inland tank barges ....... Inland push boats......... Offshore tank barges ... 14 26 17 4 20,000 bbl and under 20,000 - 30,000 bbl 800 - 3,800 horsepower 40,000 bbl and 95,000 bbl Asphalt, crude oil, fuel oil, gasoline and sulfur(1) Asphalt, crude oil, fuel oil and gasoline(1) N/A Asphalt, fuel oil and NGLs - 13 - Offshore tugboats ........ 4 3,200 - 7,200 horsepower N/A __________ (1) One of our 14 inland tank barges with capacity of up to 20,000 bbl, and 13 of our 26 inland tank barges with capacity of 20,000 to 30,000 bbl, are specialized and equipped to transport asphalt. Our largest marine transportation customers include major and independent oil and gas refining companies, petroleum marketing companies and Martin Resource Management. We conduct our marine transportation services under spot contracts and under term contracts that typically range from one to 12 months in length. In order to maintain a balance of pricing flexibility and stable cash flow, we strive to maintain an appropriate mix of spot versus term contracts, based on current market conditions. We are a party to a marine transportation agreement effective January 1, 2006 under which we provide marine transportation services to Martin Resource Management on a spot contract basis at applicable market rates. This agreement replaced a prior agreement between us and Martin Resource Management covering marine transportation services which expired in November 2005. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term. The fees we charge Martin Resource Management are based on applicable market rates. Competition. We compete primarily with other marine transportation companies. The marine barging industry has experienced significant consolidation in the past few years. The total number of tank barges and push boats that operate in the inland waters of the United States declined from approximately 4,200 in 1982 to approximately 2,900 in 1993 and has reduced to approximately 2,800 since 1993. We believe the earlier decrease primarily resulted from: (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) 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 (cid:2) 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: (cid:2) (cid:2) (cid:2) (cid:2) significant start-up capital requirements; the costs and operational difficulties of complying with stringent safety and environmental regulations; the cost and difficulty in obtaining insurance; and the number and expertise of personnel required to support marine fleet operations. We believe the reduction of the number of tank barges, the consolidation among barging companies and the significant barriers to entry in the industry have resulted in a more stabilized and favorable pricing environment for our marine transportation services. We believe we compete favorably with many of our competitors. Historically, competition within the marine transportation business was based primarily on price. However, we believe customers are placing an increased emphasis on safety, environmental compliance, quality of service and the availability of a single source of supply of a diversified package of services. In particular, we believe customers are increasingly seeking transportation vendors that can offer marine, land, rail and terminal distribution services, as well as provide operational flexibility, safety, environmental and financial responsibility, adequate insurance and quality of service consistent with the customer’s own operations and - 14 - policies. We operate a diversified asset base that, together with the services provided by Martin Resource Management, enables us to offer our customers an integrated distribution network consisting of transportation, terminalling, distribution and midstream logistical services for petroleum products and by-products. In addition to competitors that provide marine transportation services, we also compete with providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. We believe we offer a competitive advantage over rail tank cars and tractor-trailer tank trucks because marine transportation is a more efficient, and generally less expensive, mode of transporting petroleum products and by-products. For example, a typical two inland barge unit carries a volume of product equal to approximately 80 rail cars or 250 tanker trucks. Pipelines generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to transport most of the products we transport and are generally a less flexible form of transportation because they are limited to the fixed point-to-point distribution of commodities in high volumes over extended periods of time. Seasonality. The demand for our marine transportation business is subject to some seasonality factors. Our asphalt shipments are generally higher during April through November when weather allows for efficient road construction. However, demand for marine transportation of sulfur, fuel oil and gasoline is directly related to production of these products in the oil refining and natural gas processing business, which is fairly stable. Sulfur Services Segment Industry Overview. Sulfur is a natural element and is required to produce a variety of industrial products. In the United States, approximately 11 million tons of sulfur is consumed annually, with the Tampa, Florida area being the largest single market. Currently, all sulfur produced in the United States is “recovered sulfur,” or sulfur that is a by-product from oil refineries and natural gas processing plants. Sulfur production in the United States is principally located along the Gulf Coast, along major inland waterways and in some areas of the western United States. Sulfur is an important plant nutrient and is used in the manufacture of phosphate fertilizers. Approximately 53% of worldwide sulfur consumption is currently used for phosphate fertilizers, with the balance used for industrial purposes. The primary application of sulfur in fertilizers occurs in the form of sulfuric acid. Burning sulfur creates sulfur dioxide, which is subsequently oxidized and dissolved in water to create sulfuric acid. The sulfuric acid is then combined with phosphate rock to make phosphoric acid, the base material for most high-grade phosphate fertilizers. Sulfur-based fertilizers are manufactured chemicals containing nutrients known to improve the fertility of soils. Nitrogen, phosphorus, potassium and sulfur are the four most important nutrients for crop growth. These nutrients are found naturally in soils. However, soils used for agriculture become depleted of these nutrients and frequently require fertilizers rich in these essential nutrients to restore fertility. The Fertilizer Institute has estimated that the earth’s soil contains less than 20% of organic plant nutrients needed to meet worldwide food production needs. As a result, we believe mineral fertilizer production will continue to be an important industrial market. Industrial sulfur products (including sulfuric acid) are used in a wide variety of industries. For example, these products are used in power plants, paper mills, auto and tire manufacturing plants, food processing plants, road construction, cosmetics and pharmaceuticals. The largest consumers of industrial sulfur products are power plants, paper mills and rubber products manufacturers. Our Operations and Products. We gather molten sulfur from refiners, primarily located on the Gulf Coast, and from natural gas processing plants, primarily located in the southwestern United States. We transport sulfur by inland and offshore barges, rail cars and trucks. In 2008, we handled approximately 1.7 million long tons of molten sulfur. In the U.S. recovered sulfur is mainly kept in liquid form from production to usage at a temperature of approximately 275 degrees Fahrenheit. Because of the temperature requirement, the sulfur industry uses specialized equipment to store and transport molten sulfur. We have the necessary transportation and storage assets and expertise to handle the unique requirements for transportation and storage of molten sulfur for domestic customers. The terms of our commercial sulfur contracts typically range from one to five years in length. The prices in such contracts are usually tied to a published market indicator and fluctuate according to the price movement of the indicator. We also provide barge transportation and tank storage to large integrated oil companies that produce sulfur and fertilizer manufacturers that consume sulfur under transportation and storage contracts with remaining lives from one to two years in duration. The sulfur prilling assets we acquired from the acquisition of Bay Sulfur in April 2005 are located at the Port of Stockton in California and are used to process molten sulfur into pellets. These dry, bulk pellets are stored and loaded at - 15 - our facility at the Port of Stockton. The sulfur pellets are sold into certain U.S. and international agricultural markets. Our facility at the Port of Stockton can process approximately 1,000 metric tons of molten sulfur per day. In January 2007, we completed the construction of a sulfur priller at our Neches facility in Beaumont, Texas. In January 2009, we completed the construction of a second sulfur priller at our Neches facility in Beaumont, Texas. The two Beaumont prillers have the capacity to process approximately 4,000 metric tons of molten sulfur per day. Our sulfur prilling facilities provide refiners with an alternative market for the sale of their residual sulfur. In late September 2007, we completed construction of a sulfuric acid production facility at our Plainview, Texas location. This facility processes molten sulfur to produce approximately 500 short tons of sulfuric acid per day. Our sulfuric acid facility provides our Plainview fertilizer plant with an economical supply of sulfuric acid and it uses approximately one third of the sulfuric acid produced by the Plainview facility. The remaining sulfuric acid production is sold to Martin Resource Management which markets the product to third parties. We entered the sulfur based fertilizer manufacturing business in 1990 through an acquisition. We acquired two additional fertilizer manufacturing companies in 1998. Over the next two years we expended significant resources to replace and update facilities and other assets and to integrate each of the businesses into our business. These acquisitions have subsequently increased the profitability of our fertilizer business. In December 2005, sulfur fertilizer production capacity was added with the purchase of the net operating assets of A & A Fertilizer, Ltd. (“A & A Fertilizer”). This production capacity is located at our Neches deep-water marine terminal near Beaumont, Texas. Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to sulfur and our distribution capabilities. These products allow us to leverage the sulfur services segment of our business. Our annual fertilizer and industrial sulfur products sales have grown from approximately 62,000 tons in 1997 to approximately 255,000 tons in 2008 as a result of acquisitions and internal growth. In the United States, fertilizer is generally sold to farmers through local dealers. These dealers are typically owned and supplied by much larger wholesale distributors. We sell primarily to these wholesale distributors, as well as to a small number of independent dealers throughout the United States. Our industrial sulfur products are marketed primarily in the eastern United States, where many paper manufacturers and power plants are located. Our products are sold in accordance with price lists that vary from state to state. These price lists are updated periodically to reflect changes in seasonal or competitive prices. We transport our fertilizer and industrial sulfur products to our customers using third party common carriers. We utilize rail shipments for large volume and long distance shipments where available. We manufacture and market the following sulfur-based fertilizer and related sulfur products: (cid:2) (cid:2) (cid:2) Plant nutrient sulfur products. We produce plant nutrient and agricultural ground sulfur products at our two facilities in Odessa, Texas. We also produce plant nutrient sulfur at our facility in Seneca, Illinois. Our plant nutrient sulfur product is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold throughout the United States to direct application agricultural markets. Our agricultural ground sulfur products are used primarily in the western United States on grapes and vegetable crops. Ammonium sulfate products, NPK products and related blended products. We produce various grades of ammonium sulfate including coarse and standard grades, a 40% ammonium sulfate solution and a Kosher-approved food grade material. We also produce nitrogen-phosphorus- potassium products (commonly referred to as NPK products). Our NPK products are an ammoniated phosphate fertilizer containing nitrogen, phosphorus and potash that we manufacture so all particles have a uniform composition. These products primarily serve direct application agricultural markets within a 400-mile radius of our manufacturing plant in Plainview, Texas. We blend our ammonium sulfate to make custom grades of lawn and garden fertilizer at our facility in Salt Lake City, Utah. We package these custom grade products under both proprietary and private labels and sell them to major retail distributors, and other retail customers, of these products. Industrial sulfur products. We produce industrial sulfur products such as emulsified sulfur, elemental pastille sulfur, and industrial ground sulfur products. We produce emulsified sulfur at our Texarkana, Texas facility. Emulsified sulfur is primarily used to control the sulfur content in the pulp and paper manufacturing processes. We produce elemental pastille sulfur at our two Odessa, Texas facilities and at our Seneca, Illinois facility. Elemental pastille sulfur is used to increase the efficiency of the coal-fired precipitators in the power industry. These industrial ground sulfur products are also used in a variety of dusting and wettable sulfur applications such as rubber manufacturing, fungicides, sugar and animal feeds. - 16 - (cid:2) Liquid sulfur products. We produce ammonium thiosulfate at our Neches terminal location in Beaumont, Texas. This agricultural sulfur product is a clear liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid plant nutrient used directly through spray rigs or irrigation systems. It is also blended with other NPK liquids or suspensions as well. Our market is predominantly the Mid South and Coastal Bend area of Texas. Our Sulfur Services Facilities. We own 60 railcars and lease approximately 105 railcars equipped to transport molten sulfur. We own the following major marine assets and use them to ship molten sulfur from our Beaumont, Texas terminal to our Tampa, Florida terminal: Asset Class of Equipment Capacity/Horsepower Products Transported Margaret Sue ................ Offshore tank barge M/V Martin Explorer.... Offshore tugboat Inland push boat M/V Martin Express..... Inland tank barge MGM 101..................... Inland tank barge MGM 102..................... 10,450 long tons 7,200 horsepower 1,200 horsepower 2,450 long tons 2,450 long tons Molten sulfur N/A N/A Molten sulfur Molten sulfur We own the following sulfur prilling facilities as part of our sulfur services business: Terminal Location Daily Production Capacity Products Stored Stockton ... Stockton, California 1,000 metric tons per day Molten and prilled sulfur 4,000 metric tons per day Molten and prilled sulfur Neches ..... Beaumont, Texas We lease approximately 40 railcars to transport ammonium thiosulfate. We own the following manufacturing plants as part of our sulfur services business: Facility Location Capacity Description Fertilizer plants (two) ............... Odessa, Texas Fertilizer plant .......................... Seneca, Illinois Fertilizer plant .......................... Plainview Texas Fertilizer plant .......................... Salt Lake City, Utah Fertilizer plant .......................... Beaumont, Texas Industrial sulfur plant ............... Texarkana, Texas Sulfuric acid plant .................... Plainview Texas 70,000 tons/year 36,000 tons/year 180,000 tons/year 25,000 tons/year 70,000 tons/year 18,000 tons/year 150,000 tons/year Dry sulfur fertilizer production Dry sulfur fertilizer production Fertilizer production Blending and packaging Liquid sulfur fertilizer production Emulsified sulfur production Sulfuric acid production Competition. Seven phosphate fertilizer manufacturers together consume a vast majority of the total United States production of sulfur. These companies buy from resellers as well as directly from producers. We own one of the four vessels currently used to transport molten sulfur between United States ports on the Gulf of Mexico and Tampa, Florida. Our primary competition consists of producers that sell their production directly to a fertilizer manufacturer that has its own transportation assets or foreign suppliers from Mexico or Venezuela that may sell into the Florida market. Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from Louisiana to California. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur products manufacturers. However, the close proximity of our manufacturing plants to our customer base is a competitive advantage for us in the markets we serve and allows us to minimize freight costs and respond quickly to customer requests. Seasonality. Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand during the growing season. Our Relationship with Martin Resource Management Martin Resource Management is engaged in the following principal business activities: (cid:2) (cid:2) 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; - 17 - (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas; operating a small crude oil gathering business in Stephens, Arkansas; operating a lube oil processing facility in Smackover, Arkansas; operating an underground NGL storage facility in Arcadia, Louisiana building and marketing sulfur prillers; developing an underground natural gas storage facility in Arcadia, Louisiana; supplying employees and services for the operation of our business; operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal; operating, solely for our account, an NGL truck loading and unloading and pipeline distribution terminal in Mont Belvieu, Texas; and operating, solely for our account, the asphalt facilities in Omaha, Nebraska. We are and will continue to be closely affiliated with Martin Resource Management as a result of the following relationships. Ownership Martin Resource Management owns an approximate 34.9% limited partnership interest and a 2% general partnership interest in us and all of our incentive distribution rights. Management Martin Resource Management directs our business operations through its ownership and control of our general partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of management expertise and established relationships throughout the energy industry. We do not have employees. Martin Resource Management employees are responsible for conducting our business and operating our assets on our behalf. Related Party Agreements We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $67.5 million of direct costs and expenses for the twelve months ended December 31, 2008, compared to $53.9 million for the twelve months ended December 31, 2007. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008, 2007, and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The omnibus agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the omnibus agreement. - 18 - In addition to the omnibus agreement, we and Martin Resource Management have entered into various other agreements that are not the result of arm’s-length negotiations and consequently may not be as favorable to us as they might have been if we had negotiated them with unaffiliated third parties. The agreements include, but are not limited to, a motor carrier agreement, a terminal services agreement, a marine transportation agreement, a product storage agreement, a product supply agreement, a throughput agreement, and a Purchaser Use Easement, Ingress-Egress Easement and Utility Facilities Easement. Pursuant to the terms of the omnibus agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee of our general partner’s board of directors. For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions – Agreements.” Commercial We have been and anticipate that we will continue to be both a significant customer and supplier of products and services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is currently a key component of our integrated distribution network. We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.0 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases. In the aggregate, our purchases of land transportation services, NGL storage services, and lube oil product purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 10%, 12% and 14% of our total cost of products sold during the years ended December 31, 2008, 2007, and 2006, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense. Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for approximately 6%, 6% and 4% of our total revenues for the years ended December 31, 2008, 2007, and 2006, respectively. In connection with the closing of the Tesoro Marine asset acquisition in 2003, we entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel provides terminal services to us to handle lubricants, greases and drilling fluids. For a more comprehensive discussion concerning these commercial agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions – Agreements.” Approval and Review of Related Party Transactions If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee of our general partner's board of directors, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders. - 19 - Insurance Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance policies. Vessel operating liabilities such as collision, cargo, environmental and personal injury are insured primarily through our participation in mutual insurance associations and other reinsurance arrangements, pursuant to which we are potentially exposed to assessments in the event claims by us or other members exceed available funds and reinsurance. Protection and indemnity, (“P&I”), insurance coverage is provided by P&I associations and other insurance underwriters. Our vessels are entered in P&I associations that are parties to a pooling agreement, known as the International Group Pooling Agreement, (“Pooling Agreement”), through which approximately 95% of the world’s commercial shipping tonnage is reinsured through a group reinsurance policy. With regard to collision coverage, the first $1.0 million of coverage is insured by our hull policy and any excess is insured by a P&I association. We insure our owned cargo through a domestic insurance company. We insure cargo owned by third parties through our P&I coverage. As a member of P&I associations that are parties to the Pooling Agreement, we are subject to supplemental calls payable to the associations of which we are a member, based on our claims record and the other members of the other P&I associations that are parties to the Pooling Agreement. Except for our marine operations, we self-insure against liability exposure up to a pre-determined amount, beyond which we are covered by catastrophe insurance coverage. For marine pollution claims, our insurance covers up to $1.0 billion of liability per accident or occurrence and for non-pollution incidents, our insurance covers up to $2.0 billion of liability per accident or occurrence. We believe our current insurance coverage is adequate to protect us against most accident related risks involved in the conduct of our business and that we maintain appropriate levels of environmental damage and pollution insurance coverage. However, there can be no assurance that all risks are adequately insured against, that any particular claim will be paid by the insurer, or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future. Environmental and Regulatory Matters Our activities are subject to various federal, state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters. Environmental We are subject to complex federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment. These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Many environmental laws and regulations can impose joint and several, strict liability, and any failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, there is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, chemical substances, and wastes as well as the accidental release or spill of such materials into the environment. Consequently, we cannot assure you that we will not incur significant costs and liabilities as result of such handling practices, releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, we cannot provide any assurance that our environmental compliance expenditures will not have a material adverse impact on us in the future. Superfund The Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and similar state laws, impose liability without regard to fault or the - 20 - legality of the original conduct, on certain classes of “responsible persons,” including the owner or operator of a site where regulated hazardous substances have been released into the environment and companies that disposed or arranged for the disposal of the hazardous substances found at such site. Under CERCLA, these responsible persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although certain hydrocarbons are not subject to CERCLA’s reach because “petroleum” is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA. Solid Waste We generate both hazardous and nonhazardous solid wastes which are subject to requirements of the federal Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state statutes. From time to time, the U.S. Environmental Protection Agency (“EPA”) has considered making changes in nonhazardous waste standards that would result in stricter disposal requirements for these wastes. Furthermore, it is possible some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or operating expenses. We currently own or lease, and have in the past owned or leased, properties that have been used for the manufacturing, processing, transportation and storage of petroleum products and by-products. Solid waste disposal practices within oil and gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties have been operated by third parties over whom we had no control as to such entities’ handling of hydrocarbons, hydrocarbon by-products or other wastes and the manner in which such substances may have been disposed of or released. State and federal laws and regulations applicable to oil and natural gas wastes and properties have gradually become more strict and, under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, even under circumstances where such contamination resulted from past operations of third parties. Clean Air Act Our operations are subject to the federal Clean Air Act, as amended, and comparable state statutes. Amendments to the Clean Air Act adopted in 1990 contain provisions that may result in the imposition of increasingly stringent pollution control requirements with respect to air emissions from the operations of our terminal facilities, processing and storage facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control requirements may include specific equipment or technologies to control emissions, permits with emissions and operational limitations, pre-approval of new or modified projects or facilities producing air emissions, and similar measures. For example, the Mont Belvieu terminal we use is located in an EPA-designated ozone non-attainment area, referred to as the Houston- Galveston non-attainment area, which is now subject to a new, EPA-adopted 8-hour standard for complying with the national standard for ozone. Categorized as being in “moderate” non-attainment for ozone, the Houston-Galveston non- attainment area has until 2010 to achieve compliance with this new standard, which almost certainly will require the adoption of more restrictive regulations in this non- attainment area for the issuance of air permits for new or modified facilities. In addition, existing sources of air emissions in the Houston-Galveston area are already subject to stringent emission reduction requirements. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air emission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are in substantial compliance with applicable requirements of the Clean Air Act and analogous state laws. Global Warming and Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering climate change-related legislation to restrict greenhouse gas emissions. At least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA must consider whether it is - 21 - required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect our operations and demand for our services. Clean Water Act The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Regulations promulgated under these laws require entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System (“NPDES”) and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess penalties for releases of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff and that applicable facilities develop and implement plans for the management of storm water runoff (referred to as storm water pollution prevention plans (“SWPPPs”)) as well as for the prevention and control of oil spills (referred to as spill prevention, control and countermeasure (“SPCC”) plans). As part of the regular overall evaluation of our on-going operations, we are reviewing and, as necessary, updating SWPPPs for certain of our facilities, including facilities recently acquired. In addition, we have reviewed our SPCC plans and, where necessary, amended such plans to comply with applicable regulations adopted by EPA in 2002. We believe that compliance with the conditions of such permits and plans will not have a material effect on our operations. Oil Pollution Act The Oil Pollution Act of 1990, as amended (“OPA”) imposes a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages including natural resource damages. Under OPA, vessels and shore facilities handling, storing, or transporting oil are required to develop and implement oil spill response plans, and vessels greater than 300 tons in weight must provide to the United States Coast Guard evidence of financial responsibility to cover the costs of cleaning up oil spills from such vessels. The OPA also requires that all newly constructed tank barges engaged in oil transportation in the United States be double hulled and all existing single hull tank barges be retrofitted with double hulls or phased out by 2015. We believe we are in substantial compliance with all of these oil spill-related and financial responsibility requirements. Safety Regulation The Company’s marine transportation operations are subject to regulation by the United States Coast Guard, federal laws, state laws and certain international treaties. Tank ships, push boats, tugboats and barges are required to meet construction and repair standards established by the American Bureau of Shipping, a private organization, and the United States Coast Guard and to meet operational and safety standards presently established by the United States Coast Guard. We believe our marine operations and our terminals are in substantial compliance with current applicable safety requirements. Occupational Health Regulations The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. In May 2001, Martin Resource Management paid a small fine in relation to the settlement of alleged OSHA violations at our facility in Plainview, Texas. Although we believe the amount of this fine and the nature of these violations were not, as an individual event, material to our business or operations, this violation may result in increased fines and other sanctions if we are cited for similar violations in the future. Our marine vessel operations are also subject to safety and operational standards established and monitored by the United States Coast Guard. - 22 - In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. These expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business. Jones Act The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. Since we engage in maritime transportation between locations in the United States, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of convenience. Following Hurricane Katrina, and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act or other similar actions could adversely affect our cash flow and ability to make distributions to our unitholders. Merchant Marine Act of 1936 The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the President of the United States of a national emergency or a threat to the national security, the United States Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States’ citizens (including us, provided that we are considered a United States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the United States government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats, tugboats or tank barges. Regulations Affecting Natural Gas Transmission, Processing and Gathering We own a 50% non-operating interest in PIPE. PIPE’s Fishhook Gathering System transports natural gas in interstate commerce and is thus subject to FERC regulations and FERC-approved tariffs as a natural gas company under the National Gas Act of 1938 (“NGA”). Under the NGA, FERC has issued orders requiring pipelines to provide open- access transportation on a basis that is equal for all shippers. In addition, FERC has the authority to regulate natural gas companies with respect to: rates, terms and conditions of service; the types of services PIPE may provide to its customers; the construction of new facilities; the acquisition, extension, expansion or abandonment of services or facilities; the maintenance and retention of accounts and records; and relationships of affiliated companies involved in all aspects of the natural gas and energy business. On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“EP Act”). The EP Act is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, the EP Act amends the NGA and the Natural Gas Policy Act of 1978 by increasing the criminal penalties available for violations of each act. The EP Act also adds a new section to the NGA which provides FERC with the power to assess civil penalties of up to $1,000,000 per day per violation of the NGA. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. However, we do not believe that we will be disproportionately affected as compared to other natural gas producers and marketers by any action taken. We believe that our natural gas gathering operations meet the tests FERC uses to establish a pipeline’s status as a gatherer exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, - 23 - ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure our unitholders that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC- regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts. Other state and local regulations also affect our natural gas processing and gathering business. Our gathering lines are subject to ratable take and common purchaser statutes in Louisiana and Texas. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge proprietary status of a line, or the rates, terms and conditions of a gathering line providing transportation service. Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to: perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) Employees We do not have any employees. Under our omnibus agreement with Martin Resource Management, Martin Resource Management provides us with corporate staff and support services. These services include centralized corporate functions, such as accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other corporate services. Martin Resource Management employs approximately 601 individuals who provide direct support to our operations as of March 2, 2009. None of these employees are represented by labor unions. Financial Information about Segments Information regarding our operating revenues and identifiable assets attributable to each of our segments is presented in Note 20 to our consolidated financial statements included in this annual report on Form 10-K. Access to Public Filings We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed with the Securities and Exchange Commission (“SEC”) under the Securities and Exchange Act of 1934. These documents may be accessed free of charge on our website at the following address: www.martinmidstream.com. These documents are provided as soon as is reasonably practicable after their filing with the SEC. This website address is intended to be an inactive, textual reference only, and none of the material on this website is part of this report. These documents may also be found at the SEC’s website at www.sec.gov. - 24 - Item 1A. Risk Factors Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a business similar to ours. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In this case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and unitholders could lose all or part of their investment. These risk factors should be read in conjunction with the other detailed information concerning us set forth herein. Risks Relating to Our Business Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the risks set forth below. The risks described below should not be considered to be comprehensive and all- inclusive. Additional risks that we do not yet know of or that we currently think are immaterial may also impair our business operations, financial condition and results of operations. If any events occur that give rise to the following risks, our business, financial condition, or results of operations could be materially and adversely affected, and as a result, the trading price of our common units could be materially and adversely impacted. Many of such factors are beyond our ability to control or predict. Unitholders are cautioned not to put undue reliance on forward-looking statements. We may not have sufficient cash after the establishment of cash reserves and payment of our general partner’s expenses to enable us to pay the minimum quarterly distribution each quarter. We may not have sufficient available cash each quarter in the future to pay the minimum quarterly distribution on all our units. Under the terms of our partnership agreement, we must pay our general partner’s expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of net cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things: (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) the costs of acquisitions, if any; the prices of petroleum products and by-products; fluctuations in our working capital; the level of capital expenditures we make; restrictions contained in our debt instruments and our debt service requirements; our ability to make working capital borrowings under our credit facility; and the amount, if any, of cash reserves established by our general partner in its discretion. Unitholders should also be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash flow from working capital borrowings, and not solely on profitability, which will be affected by non-cash items. In addition, our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and the establishment of reserves, each of which can affect the amount of cash available for distribution to our unitholders. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income. Restrictions in our credit facility may prevent us from making distributions to our unitholders. The payment of principal and interest on our indebtedness reduces the cash available for distribution to our unitholders. In addition, we are prohibited by our credit facility from making cash distributions during an event of default or if the payment of a distribution would cause an event of default thereunder. Our leverage and various limitations in our credit facility may reduce our ability to incur additional debt, engage in certain transactions and capitalize on acquisition or other business opportunities that could increase cash flows and distributions to our unitholders. - 25 - If we do not have sufficient capital resources for acquisitions or opportunities for expansion, our growth will be limited. We intend to explore acquisition opportunities in order to expand our operations and increase our profitability. We may finance acquisitions through public and private financing, or we may use our limited partner interests for all or a portion of the consideration to be paid in acquisitions. Distributions of cash with respect to these equity securities or limited partner interests may reduce the amount of cash available for distribution to the common units. In addition, in the event our limited partner interests do not maintain a sufficient valuation, or potential acquisition candidates are unwilling to accept our limited partner interests as all or part of the consideration, we may be required to use our cash resources, if available, or rely on other financing arrangements to pursue acquisitions. If we use funds from operations, other cash resources or increased borrowings for an acquisition, the acquisition could adversely impact our ability to make our minimum quarterly distributions to our unitholders. Additionally, if we do not have sufficient capital resources or are not able to obtain financing on terms acceptable to us for acquisitions, our ability to implement our growth strategies may be adversely impacted. We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs. Global financial markets and economic conditions have been, and continue to be, volatile due to a variety of factors, including significant write-offs in the financial services sector and the current weak economic conditions. As a result of the disruption in the financial markets, the availability of funds from those markets has diminished significantly and the cost of raising money in the debt and equity capital markets has increased substantially. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to the disruption in the financial markets and the current weak economic conditions, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due, complete future acquisitions or expansion and maintenance capital projects. We are exposed to counterparty risk in our credit facility and related interest rate protection agreements. We have entered into interest rate protection agreements to manage our interest rate risk exposure by fixing a portion of the interest expense we pay on our long-term debt under our credit facility. There is considerable turmoil in the world economy and banking markets which could affect whether the counterparties to such interest rate protection agreements are able to honor their agreements. If the counterparties fail to honor their commitments, we could experience higher interest rates, which could have a material adverse effect on our business, financial condition and results of operations. In addition, if the counterparties fail to honor their commitments, we also may be required to replace such interest rate protection agreements with new interest rate protection agreements, and such replacement interest rate protection agreements may be at higher rates than our current interest rate protection agreements, which could have a material adverse effect on our business, financial condition and results of operations. The current economic crisis may significantly affect our customers and their ability to make payments to us. The current economic crisis is having profound effects on all areas of the world economy. Our customers’ abilities to make payments to us when due may be adversely affected in this environment. As such, we could see an increase in delayed or uncollected receivables that may have an adverse effect on our results of operations, cash flow and ability to make distributions to our unitholders. Our recent and future acquisitions may not be successful, may substantially increase our indebtedness and contingent liabilities, and may create integration difficulties. As part of our business strategy, we intend to acquire businesses or assets we believe complement our existing operations. We may not be able to successfully integrate recent or any future acquisitions into our existing operations or achieve the desired profitability from such acquisitions. These acquisitions may require substantial capital expenditures and the incurrence of additional indebtedness. If we make acquisitions, our capitalization and results of operations may change significantly. Further, any acquisition could result in: - 26 - (cid:2) (cid:2) (cid:2) (cid:2) post-closing discovery of material undisclosed liabilities of the acquired business or assets; the unexpected loss of key employees or customers from the acquired businesses; difficulties resulting from our integration of the operations, systems and management of the acquired business; and an unexpected diversion of our management’s attention from other operations. If recent or any future acquisitions are unsuccessful or result in unanticipated events or if we are unable to successfully integrate acquisitions into our existing operations, such acquisitions could adversely affect our results of operations, cash flow and ability to make distributions to our unitholders. Adverse weather conditions, including droughts, hurricanes, tropical storms and other severe weather, could reduce our results of operations and ability to make distributions to our unitholders. Our distribution network and operations are primarily concentrated in the Gulf Coast region and along the Mississippi River inland waterway. Weather in these regions is sometimes severe (including tropical storms and hurricanes) and can be a major factor in our day-to-day operations. Our marine transportation operations can be significantly delayed, impaired or postponed by adverse weather conditions, such as fog in the winter and spring months, and certain river conditions. Additionally, our marine transportation operations and our assets in the Gulf of Mexico, including our barges, push boats, tugboats and terminals, can be adversely impacted or damaged by hurricanes, tropical storms, tidal waves or other related events. Demand for our lubricants and the diesel fuel we throughput in our terminalling and storage segment can be affected if offshore drilling operations are disrupted by weather in the Gulf of Mexico. National weather conditions have a substantial impact on the demand for our products. Unusually warm weather during the winter months can cause a significant decrease in the demand for NGL products, fuel oil and gasoline. Likewise, extreme weather conditions (either wet or dry) can decrease the demand for fertilizer. For example, an unusually wet spring can delay planting of seeds, which can leave insufficient time to apply fertilizer at the planting stage. Conversely, drought conditions can kill or severely stunt the growth of crops, thus eliminating the need to nurture plants with fertilizer. Any of these or similar conditions could result in a decline in our net income and cash flow, which would reduce our ability to make distributions to our unitholders. If we incur material liabilities that are not fully covered by insurance, such as liabilities resulting from accidents on rivers or at sea, spills, fires or explosions, our results of operations and ability to make distributions to our unitholders could be adversely affected. Our operations are subject to the operating hazards and risks incidental to terminalling and storage, marine transportation and the distribution of petroleum products and by-products and other industrial products. These hazards and risks, many of which are beyond our control, include: (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) 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. - 27 - Changes in the insurance markets attributable to the September 11, 2001, terrorist attacks, and their aftermath, may make some types of insurance more difficult or expensive for us to obtain. In addition, changes in the insurance markets attributable to the effects of Hurricanes Katrina and Rita, and their aftermath, may make some types of insurance more difficult or expensive for us to obtain. As a result, we may be unable to secure the levels and types of insurance we would otherwise have secured prior to such events. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. The price volatility of petroleum products and by-products can reduce our liquidity and results of operations and ability to make distributions to our unitholders. We purchase hydrocarbon products and by-products such as molten sulfur, sulfur derivatives, fuel oils, LPGs, lubricants, asphalt and other bulk liquids, and sell these products to wholesale and bulk customers and to other end users. We also generate revenues through the terminalling and storage of certain products for third parties. The price and market value of hydrocarbon products and by-products can be, and has recently been, volatile. Our liquidity and revenues have been adversely affected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. In addition, our liquidity and costs have been adversely affected during periods of increasing prices because of the increased costs associated with our purchase of hydrocarbon products and by-products. Future price volatility could have an adverse impact on our liquidity and results of operations, cash flow and ability to make distributions to our unitholders. Increasing energy prices could adversely affect our results of operations. Increasing energy prices, such as those experienced in the past couple of years, could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect our results of operations including net income and cash flows. We cannot assure unitholders that we will be able to pass along increased operating expenses to our customers. 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: (cid:2) (cid:2) 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; (cid:2) worldwide demand for oil and natural gas; (cid:2) (cid:2) (cid:2) (cid:2) 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; (cid:2) weather conditions; (cid:2) (cid:2) 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. - 28 - Our NGL and sulfur-based fertilizer products are subject to seasonal demand and could cause our revenues to vary. The demand for NGL and natural gas is highest in the winter. Therefore, revenue from our natural gas services business is higher in the winter than in other seasons. Our sulfur-based fertilizer products experience an increase in demand during the spring, which increases the revenue generated by this business line in this period compared to other periods. The seasonality of the revenue from these products may cause our results of operations to vary on a quarter to quarter basis and thus could cause our cash available for quarterly distributions to fluctuate from period to period. The highly competitive nature of our industry could adversely affect our results of operations and ability to make distributions to our unitholders. We operate in a highly competitive marketplace in each of our primary business segments. Most of our competitors in each segment are larger companies with greater financial and other resources than we possess. We may lose customers and future business opportunities to our competitors and any such losses could adversely affect our results of operations and ability to make distributions to our unitholders. Our business is subject to compliance with environmental laws and regulations that may expose us to significant costs and liabilities and adversely affect our results of operations and ability to make distributions to our unitholders. Our business is subject to federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment. These laws and regulations may impose numerous obligations that are applicable to our operations, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Many environmental laws and regulations can impose joint and several strict liability, and any failure to comply with environmental laws, regulations and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to make distributions to our unitholders. Additionally, if neither Ruben Martin nor Scott Martin is the chief executive officer of our general partner, amounts we owe under our credit facility may become immediately due and payable. Our success is largely dependent upon the continued services of members of the senior management team of Martin Resource Management. Those senior executive officers have significant experience in our businesses and have developed strong relationships with a broad range of industry participants. The loss of any of these executives could have a material adverse effect on our relationships with these industry participants, our results of operations and our ability to make distributions to our unitholders. Additionally, if neither Ruben Martin nor Scott Martin is the chief executive officer of our general partner, the lender under our credit facility could declare amounts outstanding thereunder immediately due and payable. If such event occurs, our results of operations and our ability to make distribution to our unitholders could be negatively impacted. We do not have employees. We rely solely on officers and employees of Martin Resource Management to operate and manage our business. Martin Resource Management operates businesses and conducts activities of its own in which we have no economic interest. There could be competition for the time and effort of the officers and employees who provide services to our general partner. If these officers and employees do not or cannot devote sufficient attention to the management and operation of our business, our results of operation and ability to make distributions to our unitholders may be reduced. - 29 - Our loss of significant commercial relationships with Martin Resource Management could adversely impact our results of operations and ability to make distributions to our unitholders. Martin Resource Management provides us with various services and products pursuant to various commercial contracts. The loss of any of these services and products provided by Martin Resource Management could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders. Additionally, we provide terminalling and storage and marine transportation services to Martin Resource Management to support its businesses under various commercial contracts. The loss of Martin Resource Management as a customer could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders. Our business would be adversely affected if operations at our transportation, terminalling and storage and distribution facilities experienced significant interruptions. Our business would also be adversely affected if the operations of our customers and suppliers experienced significant interruptions. Our operations are dependent upon our terminalling and storage facilities and various means of transportation. We are also dependent upon the uninterrupted operations of certain facilities owned or operated by our suppliers and customers. Any significant interruption at these facilities or inability to transport products to or from these facilities or to or from our customers for any reason would adversely affect our results of operations, cash flow and ability to make distributions to our unitholders. Operations at our facilities and at the facilities owned or operated by our suppliers and customers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as: (cid:2) (cid:2) (cid:2) (cid:2) catastrophic events, including hurricanes; environmental remediation; labor difficulties; and disruptions in the supply of our products to our facilities or means of transportation. Additionally, terrorist attacks and acts of sabotage could target oil and gas production facilities, refineries, processing plants, terminals and other infrastructure facilities. Any significant interruptions at our facilities, facilities owned or operated by our suppliers or customers, or in the oil and gas industry as a whole caused by such attacks or acts could have a material adverse affect on our results of operations, cash flow and ability to make distributions to our unitholders. Political, regulatory and economic factors may significantly affect our operations, the manner in which we conduct our business and slow our rate of growth. Due to changes in the political climate as a result of the outcome of recent state elections and the Presidential election in the United States, we cannot predict with any certainty the nature and extent of the changes in federal, state and local laws, regulations and policy we will face, or the effect of such elections on any pending legislation. Any increased regulation, new policy initiatives, increased taxes or any other changes in federal law may have an adverse effect on our business, financial condition and results of operations. Our marine transportation business would be adversely affected if we do not satisfy the requirements of the Jones Act, or if the Jones Act were modified or eliminated. The Jones Act is a federal law that restricts domestic marine transportation in the United States to vessels built and registered in the United States. Furthermore, the Jones Act requires that the vessels be manned and owned by United States citizens. If we fail to comply with these requirements, our vessels lose their eligibility to engage in coastwise trade within United States domestic waters. The requirements that our vessels be United States built and manned by United States citizens, the crewing requirements and material requirements of the Coast Guard and the application of United States labor and tax laws significantly increase the costs of United States flagged vessels when compared with foreign flagged vessels. During the past several years, certain interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoes reserved for United States flagged vessels under the Jones Act and cargo preference laws. If the Jones Act were to be modified to permit foreign competition that would not be subject to the same United States government imposed costs, we may need to lower the prices we charge for our services in order to compete with foreign competitors, which would adversely affect our cash flow and ability to make distributions to our unitholders. - 30 - Following Hurricane Katrina and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act or other similar actions could result in similar consequences. Our marine transportation business would be adversely affected if the United States Government purchases or requisitions any of our vessels under the Merchant Marine Act. We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of the United States of a national emergency or a threat to the national security, the United States Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (including us, provided that we are considered a United States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the United States government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats, tugboats or tank barges. If any of our vessels are purchased or requisitioned for an extended period of time by the United States government, such transactions could have a material adverse affect on our results of operations, cash flow and ability to make distributions to our unitholders. Regulations affecting the domestic tank vessel industry may limit our ability to do business, increase our costs and adversely impact our results of operations and ability to make distributions to our unitholders. The OPA 90, provides for the phase out of single-hull vessels and the phase-in of the exclusive operation of double-hull tank vessels in U.S. waters for barges that carry petroleum products that are regulated under OPA. Under OPA, substantially all tank vessels that do not have double hulls will be phased out by 2015 and will not be permitted to enter U.S. ports or trade in U.S. waters. The phase out dates vary based on the age of the vessel and other factors. All but one of our offshore tank barges are double-hull vessels which have no phase out date. We have 13 single-hull barges that will be phased out of the petroleum product trade by the year 2015. The phase out of these single-hull vessels in accordance with OPA may require us to make substantial capital expenditures, which could adversely affect our operations and market position and reduce our cash available for distribution. A decline in the volume of natural gas and NGLs delivered to our facilities could adversely affect our results of operations, cash flows and financial condition. Our profitability could be materially impacted by a decline in the volume of natural gas and NGLs transported, gathered or processed at our facilities. A material decrease in natural gas production, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas and NGLs handled by our facilities. The natural gas and NGLs available to our facilities will be derived from reserves produced from existing wells. These reserves naturally decline over time. To offset this natural decline, our facilities will need access to additional reserves. Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile. We are subject to significant risks due to fluctuations in commodity prices. These risks relate primarily to: (1) the purchase of certain volumes of natural gas at a price that is a percentage of a relevant index; and (2) certain processing contracts for Prism Gas whereby we are exposed to natural gas and NGL commodity price risks. The margins we realize from purchasing and selling a portion of the natural gas that we transport through our pipeline systems decrease in periods of low natural gas prices because our gross margins are based on a percentage of the index price. For the years ended December 31, 2008, and 2007, Prism Gas purchased approximately 22% and 14%, respectively, of our gas at a percentage of relevant index. Accordingly, a decline in the price of natural gas could have an adverse impact on our results of operations. In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to continue. For example, in 2007, the spot price of Henry Hub natural gas ranged from a high of $9.10 per MMBtu to a low - 31 - of $5.29 per MMBtu. From January 1, 2008, through December 31, 2008, the same price ranged from $13.31 per MMBtu to $5.38 per MMBtu. On December 31, 2008, the spot price was $5.63 per MMBtu. We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income. The markets and prices for residue gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including: (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) the impact of weather on the demand for oil and natural gas; the level of domestic oil and natural gas production; the level of domestic industrial and manufacturing activity; the availability of imported oil and natural gas; actions taken by foreign oil and gas producing nations; the availability of local, intrastate and interstate transportation systems; the availability and marketing of competitive fuels; the impact of energy conservation efforts; and the extent of governmental regulation and taxation. Our hedging activities may have a material adverse effect on our earnings, profitability, liquidity, cash flows and financial condition. As of December 31, 2008, Prism Gas has hedged approximately 47% and 21% of its commodity risk by volume for 2009 and 2010, respectively. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. We anticipate entering into additional hedges in 2009 and beyond to further reduce our exposure to commodity price movements. The intent of these arrangements is to reduce the volatility in our cash flows resulting from fluctuations in commodity prices. We entered into these derivative transactions with an investment grade subsidiary of a major oil company and investment grade banks. While we anticipate that future derivative transactions will be entered into with investment grade counterparties, and that we will actively monitor the credit rating of such counterparties, it is nevertheless possible that losses will result from counterparty credit risk in the future. Such risks may be more likely due to the worldwide financial and credit crisis. Management will continue to evaluate whether to enter into any new hedging arrangements, but there can be no assurance that we will enter into any new hedging arrangements or that our future hedging arrangements will be on terms similar to our existing hedging arrangements. Also, we may seek in the future to further limit our exposure to changes in natural gas, NGL and condensate commodity prices and we may seek to limit our exposure to changes in interest rates by using financial derivative instruments and other hedging mechanisms from time to time. To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. Despite our hedging program, we remain exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual natural gas, NGL and condensate prices that we realize in our operations. Furthermore, we have entered into derivative transactions related to only a portion of the volume of our expected natural gas supply and production of NGLs and condensate from our processing plants; as a result, we will continue to have direct commodity price risk to the unhedged - 32 - portion. Our actual future production may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or do not perform as planned. We cannot assure our unitholders that the steps we take to monitor our hedging activities will detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. For additional information regarding our hedging activities, please see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering and pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate. We make internal evaluations of natural gas reserves based on publicly available information. However, we typically do not obtain independent evaluations of natural gas reserves connected to our systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations to verify publicly available information. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas on our systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders. We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and NGLs. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution. We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. While some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations and financial condition, unless we were able to acquire comparable volumes from other sources. We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks. We purchase from producers and other customers a significant amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. While we attempt to balance our purchases and sales, if our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows. If third party pipelines and other facilities interconnected to our natural gas and NGL pipelines and facilities become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected. We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third party pipelines and other facilities become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected. - 33 - The industry in which we operate is highly competitive, and increased competitive pressure could adversely affect our business and operating results. We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own systems to transport NGLs in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. We believe that our natural gas gathering operations meet the tests the FERC, uses to establish a pipeline’s status as a gatherer exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure our unitholders that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts. Other state and local regulations also affect our business. Our gathering lines are subject to ratable take and common purchaser statutes in Louisiana and Texas. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of a gathering line providing transportation service. Panther Interstate Pipeline Energy, LLC is also subject to regulation by FERC with respect to issues other than ratemaking. Under the NGA, FERC has the authority to regulate natural gas companies, such as Panther Interstate Pipeline Energy, LLC with respect to: rates, terms and conditions of service; the types of services Panther Interstate Pipeline Energy, LLC may provide to its customers; the construction of new facilities; the acquisition, extension, expansion or abandonment of services or facilities; the maintenance and retention of accounts and records; and relationships of affiliated companies involved in all aspects of the natural gas and energy business. FERC’s actions in any of these areas or modifications to its current regulations could impair Panther Interstate Pipeline Energy, LLC’s ability to compete for business, the costs it incurs to operate, or the acquisition or construction of new facilities. - 34 - We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs. Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to: (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. We currently estimate that we will incur costs of less than $1.0 million between 2008 and 2010 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations. We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to our unitholders. Risks Relating to an Investment in the Common Units Units available for future sales by us or our affiliates could have an adverse impact on the price of our common units or on any trading market that may develop. Martin Resource Management through a subsidiary currently hold 850,674 subordinated units and 4,334,143 common units. The remaining subordinated units may convert into common units in accordance with the terms of our Partnership Agreement at the end of the subordination period on November 14, 2009 if certain distribution thresholds are met by us. Common units will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Our partnership agreement provides that, after the subordination period, we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as: (cid:2) (cid:2) (cid:2) 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 - 35 - (cid:2) the conversion of our general partner’s general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner. Our partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow the general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as a general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. Except as described below, the general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws. Our general partner and its affiliates, with our concurrence, have granted comparable registration rights to their bank group to which their partnership units have been pledged. The sale of any common or subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop. Unitholders have less power to elect or remove management of our general partner than holders of common stock in a corporation. Common unitholders will not have sufficient voting power to elect or remove our general partner without the consent of Martin Resource Management. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis. Martin Resource Management elects the directors of our general partner. Although our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders, the directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to Martin Resource Management and its shareholders. If unitholders are dissatisfied with the performance of our general partner, they will have a limited ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. Because our general partner and its affiliates, including Martin Resource Management, control 35.7% of our outstanding limited partnership units, our general partner initially cannot be removed without the consent of it and its affiliates. If our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common units by prematurely eliminating their contractual right to distributions and liquidation preference over the subordinated units, which preferences would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of our business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period. Unitholders’ voting rights are further restricted by our partnership agreement provision prohibiting any units held by a person owning 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of our general partner’s directors, from voting on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or - 36 - 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: (cid:2) we had been conducting business in any state without compliance with the applicable limited partnership statute; or (cid:2) 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: (cid:2) (cid:2) (cid:2) (cid:2) 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. - 37 - Unitholders are treated as having consented to the various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law. We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests. During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as: (cid:2) (cid:2) (cid:2) (cid:2) the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis; the conversion of subordinated units into common units; the conversion of units of equal rank with the common units into common units under some circumstances; or the conversion of our general partner’s general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner. After the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time. On November 14, 2008, 850,672 of 1,701,346 outstanding subordinated units owned by Martin Resource Management though a subsidiary converted into common units on a one for one basis following our distribution of available cash on such date. Additional conversion of our outstanding subordinated units will occur following our quarterly distributions of available cash provided that certain distribution thresholds are met by us. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) our unitholders’ proportionate ownership interest in us will decrease; the amount of cash available for distribution on a per unit basis may decrease; because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; the relative voting strength of each previously outstanding unit will diminish; the market price of the common units may decline; and the ratio of taxable income to distributions may increase. The control of our general partner may be transferred to a third party, and that party could replace our current management team, without unitholder consent. Additionally, if Martin Resource Management no longer controls our general partner, amounts we owe under our credit facility may become immediately due and payable. Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner to transfer its ownership interest in our general partner to a third party. A new owner of our general partner could replace the directors and officers of our general partner with its own designees and control the decisions taken by our general partner. Martin Resource Management and its affiliates have pledged their interests in our general partner and us to their bank group. If, at any time, Martin Resource Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder - 38 - immediately due and payable. If such event occurs, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distribution to our unitholders. Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price. If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. No provision in our partnership agreement, or in any other agreement we have with our general partner or Martin Resource Management, prohibits our general partner or its affiliates from acquiring more than 80% of our common units. For additional information about this call right and unitholders’ potential tax liability, please see “Risk Factors — Tax Risks — Tax gain or loss on the disposition of our common units could be different than expected”. Our common units have a limited trading volume compared to other publicly traded securities. Our common units are quoted on the NASDAQ National Market (“NASDAQ”) under the symbol “MMLP.” However, daily trading volumes for our common units are, and may continue to be, relatively small compared to many other securities quoted on the NASDAQ. The price of our common units may, therefore, be volatile. Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our unit price. In order to comply with Section 404 of the Sarbanes-Oxley Act, we periodically document and test our internal control procedures. Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent auditors addressing these assessments. During the course of our testing we may identify deficiencies which we may not be able to address in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse effect on the price of our common units. Risks Relating to Our Relationship with Martin Resource Management Cash reimbursements due to Martin Resource Management may be substantial and will reduce our cash available for distribution to our unitholders. Under our omnibus agreement with Martin Resource Management, Martin Resource Management provides us with corporate staff and support services on behalf of our general partner that are substantially identical in nature and quality to the services it conducted for our business prior to our formation. The omnibus agreement requires us to reimburse Martin Resource Management for the costs and expenses it incurs in rendering these services, including an overhead allocation to us of Martin Resource Management’s indirect general and administrative expenses from its corporate allocation pool. These payments may be substantial. Payments to Martin Resource Management will reduce the amount of available cash for distribution to our unitholders. Martin Resource Management has conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders. Martin Resource Management owns an approximate 34.9% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest and incentive distribution rights in us. Conflicts of interest may arise between Martin Resource Management and our general partner, on the one hand, and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of Martin Resource Management over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management and our general partner could occur in many of our day-to-day operations including, among others, the following situations: - 39 - (cid:2) 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. (cid:2) 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. (cid:2) Martin Resource Management may engage in limited competition with us. (cid:2) 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. (cid:2) 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. (cid:2) Our general partner determines which costs incurred by Martin Resource Management are reimbursable by us. (cid:2) 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. (cid:2) Our general partner controls the enforcement of obligations owed to us by Martin Resource Management. (cid:2) Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. (cid:2) (cid:2) The audit committee of our general partner retains our independent auditors. In some instances, our general partner may cause us to borrow funds to permit us to pay cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period. (cid:2) Our general partner has broad discretion to establish financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters. Martin Resource Management and its affiliates may engage in limited competition with us. Martin Resource Management and its affiliates may engage in limited competition with us. For a discussion of the non-competition provisions of the omnibus agreement, please see “Item 13. Certain Relationships and Related Transactions — Agreements — Omnibus Agreement.” If Martin Resource Management does engage in competition with us, we may lose customers or business opportunities, which could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders. If Martin Resource Management were ever to file for bankruptcy or otherwise default on its obligations under its credit facility, amounts we owe under our credit facility may become immediately due and payable and our results of operations could be adversely affected. If Martin Resource Management were ever to commence or consent to the commencement of a bankruptcy proceeding or otherwise defaults on its obligations under its credit facility, its lenders could foreclose on its pledge of the - 40 - interests in our general partner and take control of our general partner. If Martin Resources Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, a bankruptcy filing by or against Martin Resource Management could independently result in an event of default under our credit facility if it could reasonably be expected to have a material adverse effect on us. If our lenders do declare us in default and accelerate repayment, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our unitholders. A bankruptcy filing by or against Martin Resource Management could also result in the termination or material breach of some or all of the various commercial contracts between us and Martin Resource Management, which could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders. Tax Risks The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to unitholders. The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. If we were treated as a corporation for federal income tax purposes, we would pay tax on our income at corporate rates, which is currently a maximum of 35%, and would likely pay state income tax at various rates. Distributions to unitholders would generally be taxed again to them as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to unitholders would be substantially reduced. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore would likely result in a substantial reduction in the value of the common units. Current law may change so as to cause us to be taxable as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us. A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units and the costs of any contest will be borne by our unitholders and our general partner. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by all of our unitholders and our general partner. Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us. Unitholders may be required to pay federal income taxes and, in some cases, state, local and foreign income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even the tax liability that results from the taxation of their share of our taxable income. Tax gain or loss on the disposition of our common units could be different than expected. If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income unitholders were allocated for a common unit, which decreased unitholder tax basis in that common unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or - 41 - not representing gain, may be ordinary income to our unitholders. Should the IRS successfully contest some positions we take, our unitholders could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them. Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest effective tax rate applicable to individuals, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. We treat a purchaser of our common units as having the same tax benefits without regard to the seller’s identity. The IRS may challenge this treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation positions that may not conform to all aspects of the Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unit holders’ tax returns. Unitholders may be subject to state, local and foreign taxes and return filing requirements as a result of investing in our common units. In addition to federal income taxes, unitholders may be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders may be required to file state, local and foreign income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We own property and conduct business in Alabama, Arkansas, California, Georgia, Florida, Illinois, Louisiana, Mississippi, Nebraska, Texas and Utah. We may do business or own property in other states or foreign countries in the future. It is the unitholder’s responsibility to file all federal, state, local and foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in our common units. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis. The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the United States federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for United States federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code Section 7704(d) and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing United States tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes. We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other - 42 - things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year. For purposes of determining whether the 50% threshold is met, multiple sales of the same units are counted only once. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. We prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. Item 1B. Unresolved Staff Comments None. Item 2. Properties A description of our properties is contained in Item 1. Business. We believe we have satisfactory title to our assets. Some of the easements, rights-of-way, permits, licenses or similar documents relating to the use of the properties that have been transferred to us in connection with our initial public offering and the assets we acquired in our acquisitions, required the consent of third parties, which in some cases is a governmental entity. We believe we have obtained sufficient third party consents, permits and authorizations for the transfer of assets necessary for us to operate our business in all material respects. With respect to any third party consents, permits or authorizations that have not been obtained, we believe the failure to obtain these consents, permits or authorizations will not have a material adverse effect on the operation of our business. Title to our property may be subject to encumbrances, including liens in favor of our secured lender. We believe none of these encumbrances materially detract from the value of our properties or our interest in these properties, or materially interfere with their use in the operation of our business. - 43 - Item 3. Legal Proceedings From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of our tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, we have been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two of our employees were served with grand jury subpoenas during the fourth quarter of 2007. We are cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against us. Item 4. Submission of Matters to a Vote of Security Holders None. PART II Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Our common units are traded on the NASDAQ under the symbol “MMLP.” As of March 2, 2009 there were approximately 24 holders of record and approximately 10,371 beneficial owners of our common units. In addition, as of that date there were 850,674 subordinated units representing limited partner interests outstanding. All of the subordinated units are held by Martin Resource Management through a subsidiary. There is no established public trading market for our subordinated units. The following table sets forth the high and low closing sale prices of our common units for the periods indicated, based on the daily composite listing of stock transactions for the NASDAQ and cash distributions declared per common and subordinated units during those periods: Fiscal 2008: Quarters Ended March 31, 2008 June 30, 2008 September 30, 2008 December 31, 2008 Fiscal 2007: Quarters Ended March 31, 2007 June 30, 2007 September 30, 2007 December 31, 2007 Common Units Distributions Declared per Unit High $37.20 $36.24 $32.76 $26.99 Low $30.50 $31.50 $19.23 $13.60 Common $0.720 $0.740 $0.750 $0.750 Subordinated $0.720 $0.740 $0.750 $0.750 Common Units Distributions Declared per Unit High $39.17 $42.66 $42.65 $38.61 Low $32.96 $39.48 $34.62 $35.33 Common $0.640 $0.660 $0.680 $0.700 Subordinated $0.640 $0.660 $0.680 $0.700 On March 2, 2009, the last reported sales price of our common units as reported on the NASDAQ was $16.22 per unit. In connection with our formation in June 2002, we issued to our general partner a 2% general partner interest in us in exchange for a capital contribution in the amount of $20 and issued to Martin Resources LLC a 98% limited partner interest in the partnership in exchange for a capital contribution in the amount of $980 in an offering exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. On November 1, 2002, in offerings exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, we (i) issued 1,543,797 subordinated units representing limited partner interests in us (“Subordinated Units”) to Martin Product Sales LLC, in connection with the contribution to us of Martin Gas Sales LLC’s limited partner interests in Martin Operating Partnership L.P. (“Operating Partnership”) which holds our operating assets; (ii) issued 620,644 Subordinated Units to Midstream Fuel Service LLC, in connection with the contribution to us of Midstream Fuel Service LLC’s limited partner interests in the Operating Partnership; (iii) issued 2,088,921 Subordinated Units to Martin Gas Marine LLC in connection with the contribution of Martin Gas Marine LLC’s limited partner interests in the Operating Partnership; and (iv) converted a portion of the - 44 - existing interest in us owned by Martin Midstream GP LLC into a portion of its 2% general partner interest and the incentive distribution rights in us. In connection with our public offering of 1,322,500 common units in February 2004, our general partner contributed $0.8 million in cash to us in order to maintain its 2% general partner interest in us. In connection with our acquisition of Prism Gas in November 2005, 756,480 common units were issued to certain members of the Prism Gas management team and Martin Resource Management. In addition our general partner contributed $0.5 million in cash to us in order to maintain its 2% general partner interest in us. In connection with our public offering of 3,450,000 common units in January 2006, our general partner contributed $2.1 million in cash to us in order to maintain its 2% general partner interest in us. In connection with our public offering of 1,380,000 common units in May 2007, our general partner contributed $1.2 million in cash to us in order to maintain its 2% general partner interest in us. In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a capital contribution of approximately $0.3 million made by our general partner in order to maintain its 2% general partner interest in us. This transaction was exempt from registration pursuant to either Regulation D or Section 4(2) of the Securities Act of 1933, as amended. A total of 3,402,688 of our original 4,253,362 outstanding subordinated units owned by Martin Resource Management and its subsidiaries were converted into common units on a one-for-one basis following our quarterly cash distribution, 850,672 each on November 14, 2008, 2007, 2006 and 2005. The common units into which the subordinated units were converted were issued in reliance on Section 3(a)(9) of the Securities Act of 1933, as amended. The remaining 850,674 outstanding subordinated units will convert into common units at the end of the subordination period on November 14, 2009. Within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. During the subordination period (as described below), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our general partner determines are necessary to: (cid:2) (cid:2) (cid:2) provide for the proper conduct of our business; comply with applicable law, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand for the quarter resulting from working capital borrowings made after the end of the quarter on the date of determination of available cash. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively made 98% to unitholders and 2% to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Distributions to our general partner increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement. Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause an event of default, or an event of default is existing, under our credit facility. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility.” - 45 - The subordination period will extend until the first day of any quarter beginning after September 30, 2009, in which each of the following tests are met: (cid:2) (cid:2) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” as defined in the partnership agreement generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and (cid:2) there are no arrearages in payment of the minimum quarterly distribution on the common units. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will participate pro rata with the other common units in distributions of available cash. Item 6. Selected Financial Data The following table sets forth selected financial data and other operating data of Martin Midstream Partners L.P. for the years ended December 31, 2008, 2007, 2006, 2005 and 2004 are derived from the audited consolidated financial statements of Martin Midstream Partners L.P. The following selected financial data are qualified by reference to and should be read in conjunction with our Consolidated and Combined Financial Statements and Notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this document. 2008 2007 2006 2005 2004 Income Statement Data: Revenues.......................................................... Cost of product sold......................................... Operating expenses.......................................... Selling, general, and administrative ................ Depreciation and amortization ........................ Total costs and expenses.................................. Other operating income ................................... Operating Income ............................................ Equity in earnings of unconsolidated entities . Interest expense ............................................... Debt prepayment premium .............................. Other, net ......................................................... Income before income taxes ............................ Income taxes .................................................... Net Income....................................................... $ 1,213,958 $ 765,822 $ 576,384 $ 438,443 $ 294,144 1,013,525 102,894 16,939 31,218 1,164,576 209 49,591 13,224 (19,777) — 483 43,521 711 $ 42,810 618,689 83,533 11,985 23,442 737,649 703 28,876 10,941 (14,533) — 299 25,583 644 $ 24,939 459,170 65,387 10,977 17,597 553,131 3,356 26,609 8,547 (12,466) (1,160) 713 22,243 — $ 22,243 351,820 46,888 8,133 12,642 419,483 — 18,960 1,591 (6,909) — 238 13,880 — $ 13,880 229,976 34,475 6,198 8,766 279,415 — 14,729 912 (3,326) — 11 12,326 — $ 12,326 Net income per limited partner unit................. Weighted average limited partner units........... $2.72 14,529,826 $1.67 14,018,799 $1.69 12,602,000 $1.58 8,583,634 $1.45 8,349,551 Balance Sheet Data (at Period End): Total assets....................................................... Due to affiliates................................................ Long-term debt ................................................ Partner’s capital (owner’s equity) ................... $ 668,916 13,420 295,000 234,714 $ 623,577 7,543 225,000 235,848 $ 457,461 10,474 174,021 198,525 $ 389,044 3,492 192,200 95,565 $ 188,332 429 73,000 75,534 Cash Flow Data: Net cash flow provided by (used in): Operating activities ..................................... Investing activities ...................................... Financing activities ..................................... 79,903 (100,184) 24,151 58,017 (127,103) 69,896 39,317 (95,098) 52,991 32,334 (138,742) 109,689 12,812 (34,322) 22,424 - 46 - Other Financial Data: 2008 2007 2006 2005 2004 Maintenance capital expenditures ................... Expansion capital expenditures ....................... Total capital expenditures................................ 16,528 84,424 $ 100,952 10,342 107,892 $ 118,234 12,391 78,267 $ 90,658 5,100 74,110 $ 79,210 5,182 30,234 $ 35,416 Cash dividends per common unit (in dollars) . $ 2.91 $ 2.60 $ 2.44 $ 2.19 $ 2.10 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations References in this annual report to “we,” “ours,” “us” or like terms when used in a historical context refer to the assets and operations of Martin Resource Management’s business contributed to us in connection with our initial public offering on November 6, 2002. References in this annual report to “Martin Resource Management” refers to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires. You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and the notes thereto included elsewhere in this annual report. For more detailed information regarding the basis for presentation for the following information, you should read the notes to the consolidated financial statements included elsewhere in this annual report. Forward-Looking Statements This annual report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this annual report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward- looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. 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 (cid:2) Risks Related to our Business”. Overview We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Our four primary business lines include: (cid:2) Terminalling and storage services for petroleum products and by-products; (cid:2) Natural gas services; (cid:2) Marine transportation services for petroleum products and by-products; and (cid:2) Sulfur and sulfur-based products processing, manufacturing, marketing and distribution. The petroleum products and by-products we collect, transport, store and distribute are produced primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the Gulf Coast region of the United States. This region is a major hub for petroleum refining, natural gas gathering and processing and support services to the exploration and production industry. - 47 - 2008 Developments and Subsequent Events Recent Acquisitions Acquisition of Martin Resource Management Stanolind Assets. In January 2008, we acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at our Stanolind terminal in Beaumont, from Martin Resource Management. In connection with this acquisition, we entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks. Other Developments Quarterly Distribution. We declared a quarterly cash distribution for the fourth quarter of 2008 of $0.75 per common and subordinated unit on January 27, 2009, reflecting no change over the quarterly distribution paid in respect of the third quarter of 2008. Conversion of Subordinated Units. On November 14, 2008, 850,672 of our 1,701,346 outstanding subordinated units owned by Martin Resource Management through a subsidiary converted into common units on a one-for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding subordinated units may occur in the future provided that certain distribution thresholds contained in our partnership agreement are met by us. Critical Accounting Policies Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated financial statements included elsewhere herein. We prepared these financial statements in conformity with generally accepted accounting principles. The preparation of these financial statements required us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Our results may differ from these estimates. Currently, we believe that our accounting policies do not require us to make estimates using assumptions about matters that are highly uncertain. However, we have described below the critical accounting policies that we believe could impact our consolidated financial statements most significantly. You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements contained in this annual report on Form 10-K. Some of the more significant estimates in these financial statements include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS 142”), Goodwill and Other Intangible Assets. Derivatives In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. In early 2006, we adopted a hedging policy that allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, we had designated a portion of our derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity. Product Exchanges We enter into product exchange agreements with third parties whereby we agree to exchange NGLs and sulfur with third parties. We record the balance of NGLs and sulfur due to other companies under these agreements at quoted market product prices and the balance of NGLs and sulfur due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out method. Revenue Recognition Revenue for our four operating segments is recognized as follows: - 48 - Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through our terminals at the contracted rate. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, we recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline. Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip. For time charters, revenue is recognized based on a per day rate. Sulfur Services – Revenue is recognized when the customer takes title to the product, either at our plant or the customer facility. Equity Method Investments We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under the provisions of SFAS 142, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. No portion of the net income from these entities is included in our operating income. Following our acquisition of Prism Gas in November 2005, we own an unconsolidated 50% interest in Waskom, Matagorda, and PIPE. As a result, these assets are accounted for by the equity method and we do not include any portion of their net income in operating income. On June 30, 2006, we, through Prism Gas, acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the BCP. This interest is accounted for by the equity method of accounting. The lease contract expires in June 2009 and an extension is not currently contemplated. Goodwill Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. We are required to identify our reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. Goodwill is assigned to reporting units at the date the goodwill is initially recorded. Once goodwill has been assigned to reporting units, it no longer retains its association with a particular acquisition, and all of the activities within a reporting unit, whether acquired or organically grown, are available to support value of the goodwill. We performed the annual impairment tests as of September 30, 2008, September 30, 2007 and September 30, 2006, respectively. In performing such tests, we determined we had four “reporting units” which contained goodwill. These reporting units were in each of our four reporting segments: terminalling, natural gas services, marine transportation, and sulfur services. The estimated fair value of our reporting units with goodwill were developed using the guideline public company method, the guideline transaction method, and the discounted cash flow (“DCF”) method using observable market data where available. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, we would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired. At September 30, 2008, 2007 and 2006 the estimated fair value of each of our four reporting units was in excess of its carrying value resulting in no impairment. As a result of the deterioration in the overall stock market subsequent to September 30, 2008 and the decline in our unit price, we reviewed specific factors, as outlined in Statement of Financial Accounting Standards No. 142, to - 49 - determine if we had a trigging event that required us to test our goodwill for impairment as of December 31, 2008. These factors included whether there have been any significant fundamental changes since our annual impairment test to (i) our business as a whole or to the reporting units, including regulatory changes, (ii) our level of operating cash flows, (iii) our expectation of future levels of operating cash flows, (iv) our executive management team, and (v) the carrying value of our other long-lived assets. While these factors did not indicate a triggering event occurred, our unit price fell to a point by December 31, 2008, that resulted in our total market capitalization being less than our partner’s equity. We determined this to be a triggering event requiring us to perform an impairment test as of December 31, 2008. As a result of our goodwill impairment test for each of the four reporting units as of December 31, 2008, no impairment was determined to exist. Environmental Liabilities We have historically not experienced circumstances requiring us to account for environmental remediation obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other related environmental studies that we may elect to perform. We would record changes to our estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related eventual liability. Allowance for Doubtful Accounts In evaluating the collectability of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and historical collection experience. Based on these assessments, we record both specific and general reserves for bad debts to reduce the related receivable to the amount we ultimately expect to collect from customers. Asset Retirement Obligation In accordance with Statement of Financial Accounting Standards No. 143 (“SFAS 143”), Accounting for Asset Retirement Obligations and FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143, we recognize and measure our asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset. Subsequent measurement and accounting provisions are in accordance with SFAS 143. We have recognized asset retirement obligations, where appropriate. Reclassifications As previously reported in our Quarterly Report on Form 10-Q for the three months ended September 30, 2005, which was filed with the SEC on November 9, 2005, we converted to a new accounting system in August 2005. In connection with the system conversion, we closely examined expense classifications under the new system. Upon review, it was determined that certain payroll, property insurance and property tax expenses that were previously categorized as selling, general and administrative expenses would be more appropriately classified as operating expenses or costs of products sold. As a result, those expenses were set up in the new system with the new classification. Accordingly, it is necessary for us to reclassify the related expense items for fiscal year 2004. Since the reclassifications, as indicated in the tables set forth below, had no impact on the prior periods’ revenues, operating income, cash flows from operations or net income, we have determined that the reclassifications are not material to our audited financial statements for the prior periods. Nonetheless, we are effecting the reclassifications for prior periods in order to provide comparative clarity and consistency for the 2004 annual period when compared to our financial reporting for our current 2008 fiscal year. The following table sets forth the effects of the reclassifications on certain line items within our previously reported consolidated statements of income for the year ended December 31, 2004 (dollars in thousands), which statements of income and certain relevant footnotes thereto as well as the relevant portions of Management’s Discussion and Analysis of Financial Condition and Results of Operations for those periods have been updated. Year Ended December 31, 2004 (In Thousands) Cost of products sold (as previously reported) Cost of products sold (as reclassified) Operating expenses (as previously reported) Terminalling and Storage NGL Marine Sulfur Total $ 6,775 $ 197,859 $ — $ 25,207 $ 229,841 6,775 6,699 197,859 — 25,342 229,976 928 24,796 — 32,423 - 50 - Operating expenses (as reclassified) Selling, general and administrative (as previously reported) Selling, general and administrative (as reclassified) 8,494 2,194 399 1,185 1,457 1,200 24,796 — 34,475 175 175 4,599 4,424 8,425 6,198 Our Relationship with Martin Resource Management Martin Resource Management directs our business operations through its ownership and control of our general partner and under an omnibus agreement. In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007, when the cap expired. For the years ended December 31, 2008, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. We are required to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. Martin Resource Management also licenses certain of its trademarks and trade names to us under this omnibus agreement. We are both an important supplier to and customer of Martin Resource Management. Among other things, we sell sulfuric acid and provide marine transportation and terminalling and storage services to Martin Resource Management. We purchase land transportation services, underground storage services, sulfuric acid and marine fuel from Martin Resource Management. Additionally, we have exclusive access to and use of a truck loading and unloading terminal and pipeline distribution system owned by Martin Resource Management at Mont Belvieu, Texas. All of these services and goods are purchased and sold pursuant to the terms of a number of agreements between us and Martin Resource Management. For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions – Agreements.” Results of Operations The results of operations for the twelve months ended December 31, 2008, 2007 and 2006 have been derived from our consolidated financial statements. We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating revenues and operating income by segment for the twelve months ended December 31, 2008, 2007 and 2006. Year ended December 31, 2008: Terminalling and storage................. Natural gas services......................... Marine transportation ...................... Sulfur services ................................. Indirect selling, general and administrative Operating Revenues Revenues Intersegment Eliminations Operating Revenues after Eliminations Operating Income (loss) (In thousands) Operating Income Intersegment Eliminations Operating Income (loss) after Eliminations $ 90,474 679,375 80,059 372,987 — $ (4,189) — (3,710) (1,038) — $ 86,285 679,375 76,349 371,949 — $ 12,261 2,780 8,104 31,956 (5,510) $ (3,635) 945 (2,534) 5,224 — $ 8,626 3,725 5,570 37,180 (5,510) Total ............................................ $1,222,895 $ (8,937) $1,213,958 $ 49,591 $ — $ 49,591 Year ended December 31, 2007: Terminalling and storage................. Natural gas services......................... Marine transportation ...................... Sulfur services ................................. Indirect selling, general and administrative $ 59,790 515,992 63,533 131,602 — $ (865) — (3,954) (276) — $ 58,925 515,992 59,579 131,326 — $ 10,745 4,159 7,949 9,222 (3,199) $ (472) 333 (3,679) 3,818 — $ 10,273 4,492 4,270 13,040 (3,199) - 51 -  Total ............................................ Year ended December 31, 2006: Terminalling and storage................. Natural gas services......................... Marine transportation ...................... Sulfur services ................................. Indirect selling, general and administrative Operating Revenues $ 770,917 Revenues Intersegment Eliminations $ (5,095) Operating Revenues after Eliminations $ 765,822 Operating Income (loss) $ 28,876 Operating Income Intersegment Eliminations $ — Operating Income (loss) after Eliminations $ 28,876 $ 36,606 389,735 50,174 102,646 — $ (389) — (2,339) (49) — $ 36,217 389,735 47,835 102,597 — $ 12,646 4,239 8,258 4,719 (3,253) $ (142) — (1,847) 1,989 — $ 12,504 4,239 6,411 6,708 (3,253) Total ............................................ $ 579,161 $ (2,777) $ 576,384 $ 26,609 $ — $ 26,609 Our results of operations are discussed on a comparative basis below. There are certain items of income and expense which we do not allocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment. Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007 Our total revenues before eliminations were $1,222.9 million for the year ended December 31, 2008 compared to $770.9 million for the year ended December 31, 2007, an increase of $452.0 million, or 59%. Our operating income before eliminations was $49.6 million for the year ended December 31, 2008 compared to $28.9 million for the year ended December 31, 2007, an increase of $20.7 million, or 72%. 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. Revenues: Services............................................................................................... Products .............................................................................................. Total Revenues ................................................................................ Cost of products sold .............................................................................. Operating expenses ................................................................................. Selling, general and administrative expenses.......................................... Depreciation and amortization ................................................................ Other operating income (loss)................................................................. Operating income ................................................................................ Years Ended December 31, 2008 2007 (In thousands) $ 40,118 50,356 90,474 42,721 26,086 120 9,272 12,275 (14) $ 12,261 $ 29,400 30,390 59,790 26,298 16,238 139 6,358 10,757 (12) $ 10,745 Revenues. Our terminalling and storage revenues increased $30.7 million, or 51%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Service revenue accounted for $10.7 million of this increase. The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service during the end of 2007 and throughout 2008 and increased service revenue. Product revenue, which is lubricant sales, increased $20.0 million primarily due to our acquisition of the operations assets of Mega Lubricants Inc. (“Mega Lube”) in June 2007. Cost of products sold. Our cost of products sold increased $16.4 million, or 62% for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of the Mega Lube acquisition. Operating expenses. Operating expenses increased $9.8 million, or 61%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. The increase was result of our recent acquisitions and capital projects placed into service during the end of 2007 and throughout 2008. The increase was also a result of increased - 52 - operating activities and an increase in costs of those activities at our terminals, including increased salaries and related burden and utility costs. Hurricane expenses also accounted for $1.1 million of this increase. Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for the years ended December 31, 2008 and 2007. Depreciation and amortization. Depreciation and amortization increased $2.9 million, or 46%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of our recent acquisitions and capital expenditures. Other operating income (loss). Other operating income was approximately the same for the year ended December 31, 2008 compared to the year ended December 31, 2007. This consisted solely of a loss related to the sale of equipment for both periods. In summary, terminalling and storage operating income increased $1.5 million, or 14%, for the years ended December 31, 2008 and 2007. Natural Gas Services Segment The following table summarizes our results of operations in our natural gas services segment. Years Ended December 31, 2008 2007 (In thousands) Revenues: NGLs.................................................................................................. Natural gas ......................................................................................... Non-cash mark to market and impairment adjustments of commodity derivatives....................................................................... Loss on cash settlements of commodity derivatives .......................... Other operating fees .......................................................................... Total revenues.............................................................................. $615,966 59,346 4,930 (3,932) 3,065 679,375 Cost of products sold: NGLs ................................................................................................. Natural gas ........................................................................................ Total cost of products sold ........................................................... Operating expenses ................................................................................. Selling, general and administrative expenses.......................................... Depreciation and amortization ................................................................ Other operating income .......................................................................... Operating income ................................................................................ NGLs Volumes (Bbls) Natural Gas Volumes (Mmbtu) *Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments 599,835 58,771 658,606 8,633 5,292 4,067 2,777 3 $ 2,780 8,794 7,267 $481,018 35,983 (3,104) (611) 2,706 515,992 461,489 34,485 495,974 7,082 5,524 3,252 4,160 (1) $ 4,159 8,266 5,550 Equity in Earnings of Unconsolidated Entities ....................................... $ 13,224 $ 10,941 Waskom: Plant Inlet Volumes (Mmcf/d) Frac Volumes (Bbls/d) 257 10,542 229 8,725 Revenues. Our natural gas services revenues increased $163.4 million, or 32% for the year ended December 31, 2008 compared to the year ended December 31, 2007 due to higher commodity prices, in addition to increased - 53 - natural gas and NGL volumes. For the year ended December 31, 2008, NGL revenues increased $134.9 million, or 28% and natural gas revenues increased $23.4 million, or 65%. During 2008, our NGL average sales price per barrel increased $11.85 or 20% and our natural gas average sales price per Mmbtu increased $1.68, or 26% compared to the same period in 2007. NGL sales volumes for the year increased 6% and natural gas volumes increased 31% compared to the same period of 2007. The increase in NGL volumes is primarily due to increased industrial demand experienced during 2008 and the increase in natural gas volumes is primarily due to receiving a full year’s benefit of the Woodlawn acquisition. Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the year ended December 31, 2008, 58% of our total natural gas volumes and 33% of our total NGL volumes were hedged as compared to 46% and 53%, respectively in 2007. The impact of price risk management and marketing activities increased total natural gas and NGL revenues $1.0 million for 2008 compared to a decrease of $3.7 million in the same period of 2007. Costs of product sold. Our cost of products increased $162.6 million, or 33%, for the year ended December 31, 2008 compared to the same period in 2007. Of the increase, $138.3 million relates to NGLs and $24.3 million relates to natural gas. The percentage increase in NGL cost of products sold is greater than our percentage increase in NGL revenues as our NGL per barrel margins decreased $0.53, or 22%, primarily due to a sharp decline in commodity prices experienced in the fourth quarter of 2008. The percentage increase relating to natural gas cost of products sold is greater than the percentage increase in natural gas revenues which caused our Mmbtu margins to decrease by 70%, primarily as a result of the terms of Woodlawn’s producer contracts compared to our historical producer contracts. Operating expenses. Operating expenses increased $1.6 million, or 22%, for the year ended December 31, 2008 compared to the same period of 2007. This increase is primarily due to a full year of operations of the Woodlawn acquisition. Selling, general and administrative expenses. Selling, general and administrative expenses remained consistent for the years ended December 31, 2008 and 2007. Depreciation and amortization. Depreciation and amortization increased $0.8 million, or 25%, for the year ended December 31, 2008 compared to the same period of 2007. This increase was primarily a result of the Woodlawn acquisition. In summary, our natural gas services operating income decreased $1.4 million, or 33%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $13.2 million and $10.9 million for the year ended December 31, 2008 and 2007, respectively, an increase of 21%. This increase is primarily a result of receiving full benefit of the expansion to the Waskom plant and the Waskom fractionator in 2008 as the plant was shut down for a portion of 2007. As a result, our inlet volumes increased 12% and our fractionation volumes increased 21% for the year ended December 31, 2008 compared to the same period of 2007. Marine Transportation Segment The following table summarizes our results of operations in our marine transportation segment. Years Ended December 31, 2008 2007 (In thousands) Revenues............................................................................................ $ 80,059 57,346 Operating expenses ............................................................................ 2,635 Selling, general and administrative expenses..................................... 12,128 Depreciation and amortization ........................................................... 7,950 154 Other operating income...................................................................... Operating income ........................................................................... $ 8,104 $ 63,533 46,946 535 8,819 7,233 716 $ 7,949 - 54 - Revenues. Our marine transportation revenues increased $16.5 million, or 26%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Our inland marine assets generated an additional $16.8 million in revenue from expansion of our inland fleet and increased contract rates. This increase was offset by a slight decrease in our offshore revenues of $0.3 million resulting primarily from downtime associated with capital expenditures of offshore vessels. Operating expenses. Operating expenses increased $10.4 million, or 22%, for the year ended December 31, 2008 compared to the year ended December 31, 2007 due to increases in fuel, salaries and wages, property and liability premiums and repair and maintenance expenses. Selling, general and administrative expenses. Selling, general & administrative expenses increased $2.1 million, or 393% for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was a result of the bankruptcy of a contractor to which we had made advance payments for the construction of vessels and other expenses associated with the expansion of our fleet. Depreciation and amortization. Depreciation and amortization increased $3.3 million, or 38%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was the result of capital expenditures made in the last 12 months. Other operating income. Other operating income decreased $0.5 million, or 78%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. In 2008, there were less gains recorded on the sale of property and equipment than in 2007. In summary, our marine transportation operating income increased $0.2 million, or 2%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Sulfur Services Segment The following table summarizes our results of operations in our sulfur services segment. Revenues ................................................................................................ Cost of products sold.............................................................................. Operating expenses ................................................................................ Selling, general and administrative expenses......................................... Depreciation and amortization ............................................................... Other operating income........................................................................... Operating income............................................................................ Years Ended December 31, 2008 2007 (In thousands) $372,987 314,001 17,963 3,382 5,751 31,890 66 $ 31,956 $131,602 97,747 17,033 2,587 5,013 9,222 — $ 9,222 Sulfur (long tons) .................................................................................. Fertilizer (long tons) .............................................................................. Sulfur Services Volumes (long tons) ............................................. 1,094.3 227.6 1,321.9 1,169.8 251.1 1,420.9 Revenues. Our sulfur services revenues increased $241.4 million, or 183%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of the significant escalation in market prices during 2008, primarily driven by higher costs of sulfur and raw materials, which generated higher revenues on decreased volumes. Margins were positively impacted due to a contract pricing provision with a significant customer which allowed us to invoice them at prices greater than the prevailing market prices in the fourth quarter of 2008. Cost of products sold. Our cost of products sold increased $216.3 million, or 221%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of significant escalation in market prices during 2008 which generated higher cost of products sold on decreased volumes, particularly with respect to prilled sulfur. - 55 - Operating expenses. Our operating expenses increased $0.9 million, or 5%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was a result of increased costs relating to fuel prices for marine transportation and increased gas utilities pricing. Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased $0.8 million, or 31%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase is a result of increased compensation expense. Depreciation and amortization. Depreciation and amortization increased $0.7 million, or 15%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This is attributable to full year of operations at our sulfuric acid facility. In summary, our sulfur services operating income increased $22.7 million, or 247%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Statement of Operations Items as a Percentage of Revenues In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended December 31, 2008 and December 31, 2007. The following table summarizes, on a comparative basis, these items of our statement of operations as a percentage of our revenues. Years Ended December 31, 2008 2007 (In thousands) Revenues................................................................................................. Cost of products sold .............................................................................. Operating expenses ................................................................................. Selling, general and administrative expenses.......................................... Depreciation and amortization ................................................................ 100% 83% 8% 1% 3% 100% 81% 11% 2% 3% Equity in Earnings of Unconsolidated Entities For the years ended December 31, 2008 and 2007, equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom Gas Processing Company (“Waskom”), Matagorda, PIPE and BCP. Equity in earnings of unconsolidated entities was $13.2 million for the year ended December 31, 2008, compared to $10.9 million for the year ended December 31, 2007, an increase of $2.3 million. This increase related to earnings received from Waskom, Matagorda, PIPE and BCP. Interest Expense Our interest expense for all operations was $19.8 million for 2008 compared to $14.5 million for 2007, an increase of $5.3 million, or 37%. This increase was primarily due to an increase in average debt outstanding offset by a decrease in interest rates throughout 2008 compared to 2007. Also, we had interest swap cash settlements of $2.7 million and non-cash mark-to-market charges of $0.7 million which increased interest expense in 2008. Indirect Selling, General and Administrative Expenses Indirect selling, general and administrative expenses were $5.5 million for 2008 compared to $3.2 million for 2007, an increase of $2.3 million or 72%. Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in - 56 - the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income. In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007, when the cap expired. For the years ended December 31, 2008 and 2007, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006 Our total revenues before eliminations were $770.9 million for the year ended December 31, 2007, compared to $579.2 million for the year ended December 31, 2006, an increase of $191.7 million, or 33%. Our operating income before eliminations was $28.9 million for the year ended December 31, 2007, compared to $26.6 million for the year ended December 31, 2006, an increase of $2.3 million, or 9%. 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. Revenues: Services............................................................................................... Products .............................................................................................. Total Revenues ................................................................................ Cost of products sold .............................................................................. Operating expenses ................................................................................. Selling, general and administrative expenses.......................................... Depreciation and amortization ................................................................ Other operating income (loss)................................................................. Operating income ................................................................................ Years Ended December 31, 2007 2006 (In thousands) $ 29,400 30,390 59,790 26,298 16,238 139 6,358 10,757 (12) $ 10,745 $ 24,182 12,424 36,606 9,999 12,276 112 4,700 9,519 3,127 $ 12,646 Revenues. Our terminalling and storage revenues increased $23.2 million, or 63%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Service revenue accounted for $5.2 million of this increase. The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service during the end of 2006 and throughout 2007. Product revenue increased $18.0 million primarily due to the Mega Lube acquisition, and, exclusive of Mega Lube, a 29% increase in product cost that was passed through to our customers. There was also a 22% increase in sales volumes. Cost of products sold. Our cost of products sold increased $16.3 million, or 163% for the year ended December 31, 2007, compared to the year ended December 31, 2006. This increase was primarily a result of the Mega Lube acquisition, an increase in product cost and an increase in sales volumes. Operating expenses. Operating expenses increased $4.0 million, or 32%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. The increase was result of our recent acquisitions and capital projects placed into service during the end of 2006 and throughout 2007. The increase was also a result of increased operating activities and an increase in costs of those activities at our terminals. Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for the year ended December 31, 2007, compared to the year ended December 31, 2006. - 57 - Depreciation and amortization. Depreciation and amortization increased $1.7 million, or 35%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. This increase was primarily a result of our recent acquisitions and capital expenditures. Other operating income (loss). Other operating income for the year ended December 31, 2007, consisted solely of a loss related to the sale of equipment. Other operating income for the year ended December 31, 2006 consisted primarily of a gain of $3.1 million related to an involuntary conversion of assets. This gain resulted from insurance proceeds which were greater than the impairment of assets destroyed by hurricanes Katrina and Rita. In summary, terminalling and storage operating income decreased $1.9 million, or 15%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. Natural Gas Services Segment The following table summarizes our results of operations in our natural gas services segment. Revenues: NGLs.................................................................................................. Natural gas ......................................................................................... Non-cash mark to market adjustment of commodity derivatives....... Gain (loss) on cash settlements of commodity derivatives ................ Other operating fees .......................................................................... Total revenues.............................................................................. Cost of products sold: NGLs ................................................................................................. Natural gas ........................................................................................ Total cost of products sold ........................................................... Operating expenses ................................................................................. Selling, general and administrative expenses.......................................... Depreciation and amortization ................................................................ Other operating income........................................................................... Operating income ................................................................................ NGLs Volumes (Bbls) Natural Gas Volumes (Mmbtu) Years Ended December 31, 2007 2006 (In thousands) $481,018 35,983 (3,104) (611) 2,706 515,992 461,489 34,485 495,974 7,082 5,524 3,252 4,160 (1) $ 4,159 8,266 5,550 $372,997 13,773 221 894 1,850 389,735 361,941 12,277 374,218 5,240 4,373 1,667 4,237 2 $ 4,239 7,688 2,107 *Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments which are reflected in Equity in Earnings of Unconsolidated Entities detailed below. Equity in Earnings of Unconsolidated Entities ....................................... $ 10,941 $ 8,547 Waskom: Plant Inlet Volumes (Mmcf/d) Frac Volumes (Bbls/d) 229 8,725 183 7,677 Revenues. Our natural gas services revenues increased $126.3 million, or 32% for the year ended December 31, 2007 compared to the year ended December 31, 2006 due to increased natural gas and NGL volumes, in addition to higher commodity prices. For the year ended December 31, 2007, NGL revenues increased $108.0 million, or 29% and natural gas revenues increased $22.2 million, or 161% compared to the year ended December 31, 2006. NGL sales volumes for the year increased 8% and natural gas volumes increased 163% compared to the same period of 2006. During 2007, our NGL average sales price per barrel increased $9.68 or 20% and our natural gas average sales price per Mmbtu - 58 - decreased $0.05, or 1% compared to the same period of 2006. The increase in NGL volumes is primarily due to increased industrial demand experienced during 2007 and the increase in natural gas volumes is primarily due to the Woodlawn acquisition, completed in the second quarter of 2007. Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the year ended December 31, 2007, 46% of our total natural gas volumes and 53% of our total NGL volumes were hedged as compared to 53% and 64%, respectively for the year ended December 31, 2006. The impact of price risk management and marketing activities decreased total natural gas and NGL revenues $3.7 million for 2007 compared to an increase of $1.1 million in the same period of 2006. Costs of product sold. Our cost of products increased $121.8 million, or 33%, for the year ended December 31, 2007 compared to the same period of 2006. Of the increase, $99.6 million relates to NGLs and $22.2 million relates to natural gas. The percentage increase in NGL cost of products sold is less than our percentage increase in NGL revenues as our NGL per barrel margins increased $0.92, or 64%, primarily due to continued rising NGL prices in 2007. The percentage increase relating to natural gas cost of products sold is greater than the percentage increase in natural gas revenues, which caused our Mmbtu margins to decrease by 62%, as a result of the terms of Woodlawn’s producer contracts compared to our historical producer contracts. Operating expenses. Operating expenses increased $1.8 million, or 35%, for the year ended December 31, 2007 compared to the same period of 2006. This increase is primarily due to the Woodlawn acquisition. Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.2 million, or 26%, for the year ended December 31, 2007 compared to the same period of 2006. This increase primarily is primarily due to the Woodlawn acquisition. Depreciation and amortization. Depreciation and amortization increased $1.6 million, or 95%, for the year ended December 31, 2007 compared to the same period of 2006. This increase was primarily a result of the Woodlawn acquisition In summary, our natural gas services operating income decreased $0.1 million, or 2%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $10.9 million and $8.5 million for the year ended December 31, 2007 and 2006, respectively, an increase of 28%. This increase is primarily a result of completing the expansions to the Waskom plant and the Waskom fractionator in the first half of 2007, resulting in our inlet volumes and fractionation volumes increasing 25% and 14%, respectively. Marine Transportation Segment The following table summarizes our results of operations in our marine transportation segment. Years Ended December 31, 2007 2006 (In thousands) Revenues............................................................................................ $ 63,533 46,946 Operating expenses ............................................................................ Selling, general and administrative expenses..................................... 535 8,819 Depreciation and amortization ........................................................... 7,233 716 Other operating income...................................................................... Operating income ........................................................................... $ 7,949 $ 50,174 34,946 587 6,609 8,032 226 $ 8,258 Revenues. Our marine transportation revenues increased $13.4 million, or 27%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Our inland marine assets generated an additional $12.4 million in revenue from increased utilization of our fleet as a result of a geographical redistribution of our assets on the Gulf Coast. We also had increased contract rates and operated an additional number of leased vessels. Our offshore revenues increased $1.0 million primarily from the acquisition of an integrated tug barge unit in the fourth quarter of 2006. - 59 - Operating expenses. Operating expenses increased $12.0 million, or 34%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. We experienced increases in salaries and wages, repair and maintenance expenses, increased shipyard costs and outside towing expenses. Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for the year ended December 31, 2007 compared to the year ended December 31, 2006. Depreciation and amortization. Depreciation and amortization increased $2.2 million, or 33%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was the result of capital expenditures made in the last 12 months. Other operating income. Other operating income increased $0.5 million, or 217%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase consisted of gains on the sale of property and equipment. In summary, our marine transportation operating income decreased $0.3 million, or 4%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Sulfur Services Segment The following table summarizes our results of operations in our sulfur services segment. Years Ended December 31, 2007 2006 (In thousands) Revenues ................................................................................................ Cost of products sold.............................................................................. Operating expenses ................................................................................ Selling, general and administrative expenses......................................... Depreciation and amortization ............................................................... Operating income............................................................................ $131,602 97,747 17,033 2,587 5,013 $ 9,222 Sulfur (long tons) .................................................................................. Fertilizer (long tons) .............................................................................. Sulfur Services Volumes (long tons) ............................................. 1,169.8 251.1 1,420.9 $102,646 76,372 14,283 2,651 4,621 $ 4,719 836.3 188.9 1,025.2 Revenues. Our sulfur services revenues increased $29.0 million, or 28%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was primarily a result of a 39% increase in sales volume. The sales volume increase was due to a new molten sulfur sales contract negotiated in 2007 and increased demand for our sulfur-based products, driven by higher agricultural commodity prices. Cost of products sold. Our cost of products sold increased $21.4 million, or 28%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This percentage increase was the same as our percentage increase in sales, as our margin per ton was approximately the same for both years. Operating expenses. Our operating expenses increased $2.8 million, or 19%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was a result of increased marine transportation costs relating to increased crew wages, outside towing expense incurred for leased vessels due to down time of vessels owned by the sulfur services segment and repairs and maintenance on vessels owned by the sulfur services segment to bring them up to higher quality standards adopted by our marine transportation group. Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.1 million, or 2%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 8%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This is attributable to our sulfuric acid facility coming online in the fourth quarter of 2007. In summary, our sulfur services operating income increased $4.5 million, or 95%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. - 60 - Statement of Operations Items as a Percentage of Revenues In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended December 31, 2007 and December 31, 2006. The following table summarizes, on a comparative basis, these items of our statement of operations as a percentage of our revenues. Years Ended December 31, 2007 2006 (In thousands) Revenues................................................................................................. Cost of products sold .............................................................................. Operating expenses ................................................................................. Selling, general and administrative expenses.......................................... Depreciation and amortization ................................................................ 100% 81% 11% 2% 3% 100% 80% 11% 2% 3% Equity in Earnings of Unconsolidated Entities For the years ended December 31, 2007 and 2006, equity in earnings of unconsolidated entities relates to our unconsolidated interest in BCP subsequent to its acquisition on June 30, 2006 and the unconsolidated interests in Waskom, Matagorda and PIPE. Interest Expense Our interest expense for all operations was $14.5 million for 2007 compared to $13.6 million for 2006, an increase of $0.9 million, or 7%. This increase was primarily due to an increase in average debt outstanding offset by a decrease in interest rates throughout 2007 compared to 2006 which also included a debt prepayment premium of $1.2 million. Also, we had non-cash mark-to-market charges of $0.8 million which increased interest expense in 2007. Indirect Selling, General and Administrative Expenses Indirect selling, general and administrative expenses were $3.2 million for 2007 compared to $3.3 million for 2006, a decrease of $0.1 million or 2%. Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income. Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For both the years ended December 31, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $1.5 million reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. Liquidity and Capital Resources Impact of Current Economic Crisis We believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2009. However, current economic conditions, including wide fluctuations in commodity prices and deteriorating credit markets, have created constraints on liquidity within the capital markets and the ability to obtain credit in the markets. Due to restrictions on liquidity within the capital markets and existing litigation at Martin Resource - 61 - Managment (See “Item 9B. Other Information”) we expect our ability to access the capital markets to remain constrained over the next twelve months. Our near-term focus is to ensure we have sufficient liquidity to fund our growth programs, while continuing the present distribution rate to our unitholders. The current economic crisis has created a challenging operating environment for us to maintain our liquidity and operating cash flows at levels consistent with the recent past while maintaining the present distribution rate to our unitholders. We continue to evaluate our liquidity and capital resources and may consider sales of non-performing or non-core assets for additional liquidity. We intend to move forward with our commercially supported internal growth projects. Our ability to access the capital markets to fund new projects in the future at prices that make the proposed projects accretive is likely to be limited. We may revise the timing and scope of other projects as necessary to adapt to existing economic conditions and the incremental benefits expected to accrue to our unitholders from our expansion activities are likely to be decreased by substantial cost of capital increases during this period. In addition, if there is need to access the credit markets and the credit markets do not improve, we cannot assure you that we would be able to secure additional financing if needed, and, if such funds were available, whether the terms or conditions would be acceptable to us. Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. For example, the impact of the current economic crisis may significantly affect our customers, including their ability to satisfy receivables to us on a timely basis. Please read “Item 1A. Risk Factors – Risks Related to Our Business” for a discussion of such risks. General In 2008, cash increased $3.9 million as a result of $79.9 million provided by operating activities, $100.2 million used in investing activities and $24.2 million provided by financing activities. In 2007, cash increased $0.8 million as a result of $58.0 million provided by operating activities, $127.1 million used in investing activities and $69.9 million provided by financing activities. In 2006, cash decreased $2.8 million as a result of $39.3 million provided by operating activities, $95.1 million used in investing activities and $53.0 million provided by financing activities. For 2008, our investing activities of $100.2 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, insurance proceeds from involuntary conversion of property, plant and equipment, and investments in and returns of investments from unconsolidated partnerships. Our investment in unconsolidated partnerships helped to fund $0.9 million and $5.2 million in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December 31, 2008, respectively. For 2007, our investing activities of $127.1 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, and investments in and returns of investments from unconsolidated partnerships. Our investment in unconsolidated partnerships helped to fund $1.2 million and $8.2 million in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December 31, 2007, respectively. For 2006, our investing activities of $95.1 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, insurance proceeds from involuntary conversion of property, plant and equipment, and investments in and returns of investments from unconsolidated partnerships. For 2008, 2007 and 2006 our capital expenditures for property and equipment were $101.0 million, $118.2 million, and $90.7 million, respectively. As to each period: (cid:2) (cid:2) In 2008, we spent $84.4 million for expansion and $16.5 million for maintenance (including $6.6 million for maintenance in the fourth quarter of 2008). Our expansion capital expenditures were made in connection with marine vessel purchases and conversions, construction projects associated with our terminalling business. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and in our terminalling and sulfur services at our Neches facility, where $1.5 million in maintenance capital expenditures was spent in connection with restoration of assets destroyed in Hurricanes Gustav and Ike. In 2007, we spent $107.9 million for expansion and $10.3 million for maintenance (including $3.7 million for maintenance in the fourth quarter of 2007). Our expansion capital expenditures were made in connection with the Woodlawn and Mega Lube acquisitions, marine vessel purchases and conversions, - 62 - construction projects associated with our terminalling business, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and include $0.3 million spent in connection with the restoration of assets destroyed in hurricanes Rita and Katrina. (cid:2) In 2006, we spent $78.3 million for expansion and $12.4 million for maintenance. Our expansion capital expenditures were made in connection with our marine vessel purchases, acquiring assets relating to the South Houston and Prime Asphalt terminal acquisitions, the Corpus Christi barge terminal, the sulfur priller construction project at our Neches facility in Beaumont, Texas, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and in our terminal segment for terminal facilities where $4.7 million in maintenance capital expenditures was spent in connection with restoration of assets destroyed in Hurricanes Rita and Katrina. In 2008, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $45.7 million, purchase of treasury stock of $0.1 million, payments of long-term debt under our current and predecessor credit facilities of $257.2 million and borrowings of long-term debt under our current and predecessor credit facilities of $327.2 million and payments of debt issuance costs of $18k. In 2007, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $37.9 million, net proceeds from a follow-on public equity offering of $55.9 million, contributions of $1.2 million from our general partner to maintain its 2% general partner interest, payments of long-term debt under our current and predecessor credit facilities of $169.0 million and borrowings of long-term debt under our current and predecessor credit facilities of $220.0 million and payments of debt issuance costs of $0.3 million. In 2006, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $32.1 million, net proceeds from a follow-on public equity offering of $95.3 million, net proceeds from the issuance of common units of $15.0 million, contributions of $2.4 million from our general partner to maintain its 2% general partner interest, payments of long-term debt under our current and predecessor credit facilities of $163.0 million and borrowings of long-term debt under our current and predecessor credit facilities of $135.8 million and payments of debt issuance costs of $0.4 million. Capital Resources Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity needs will be cash flows from operations and borrowings under our credit facility. As of December 31, 2008, we had $295.0 million of outstanding indebtedness, consisting of outstanding borrowings of $165.0 million under our revolving credit facility and $130.0 million under our term loan facility. On January 22, 2008, we financed the Stanolind asset acquisition through approximately $6.0 million in borrowings under our revolving credit facility. On October 2, 2007, we financed the Monarch acquisition through approximately $3.9 million in borrowings under our revolving credit facility. On June 13, 2007, we financed the Mega Lube acquisition through approximately $4.6 million in borrowings under our revolving credit facility. On May 2, 2007, we financed the Woodlawn acquisition through approximately $33.0 million in borrowings under our revolving credit facility. In May 2007, we completed a follow-on public offering of 1,380,000 common units, resulting in proceeds of $56.0 million, after payment of underwriters’ discounts, commissions, and offering expenses. Our general partner contributed $1.2 million in cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. The net proceeds were used to pay down revolving debt under our credit facility and to provide working capital. - 63 - Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2008 is as follows (dollars in thousands): Type of Obligation Total Obligation Payment due by period 1-3 Years 3-5 Years Less than One Year Due Thereafter Long-Term Debt........................................... Revolving credit facility............................ Term loan facility...................................... Other ......................................................... Non-competition agreements ....................... Operating leases ........................................... Interest expense(1) ....................................... Revolving Credit Facility.......................... Term loan facility...................................... Other ......................................................... $165,000 130,000 — 500 26,361 $ — — — 250 3,814 $ 165,000 130,000 — 100 10,297 17,096 15,898 — 9,145 8,504 — 7,951 7,394 — $ — — — 100 4,782 — — — $ — — — 50 7,468 — — — Total contractual cash obligations................ $354,855 $21,713 $320,742 $4,882 $7,518 (1) Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms. Letter of Credit At December 31, 2008, we had an outstanding irrevocable letter of credit in the amount of $0.1 million which was issued under our revolving credit facility. This letter of credit was issued to the Texas Commission on Environmental Quality to provide financial assurance for our used oil handling program. Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements. Description of Our Credit Facility On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of credit sub- limit. Our credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25.0 million resulting in a committed $120.0 million revolving credit facility. Effective December 28, 2007, we increased our revolving credit facility $75.0 million resulting in a committed $195.0 million revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of December 31, 2008, we had $165.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of December 31, 2008, we had $29.9 million available under our revolving credit facility. On July 14, 2005, we issued a $0.1 million irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program. Draws made under our credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on our credit facilities have ranged from a low of $225.0 million to a high of $319.1 million. As of December 31, 2008, we had $29.9 million available for working capital, internal expansion and acquisition activities under our credit facility. Our obligations under the credit facility are secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, marine vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees. We may prepay all amounts outstanding under this facility at any time without penalty. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to - 64 - 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing LIBOR borrowings is 2.50%. Effective January 1, 2009, the applicable margin for existing LIBOR borrowings will decrease to 2.00%. As a result of our leverage ratio test, effective April 1, 2009, the applicable margin for existing LIBOR borrowings will remain at 2.00%. We incur a commitment fee on the unused portions of the credit facility. Effective October 2008, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 2.820% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in October 2010 is accounted for using hedge accounting. Effective January 2008, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed rate. The fixed rate cost is 3.400% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in January 2010 is accounted for using hedge accounting. Effective September 2007, we entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus our applicable LIBOR borrowing spread. The cash flow hedge matures in September 2010 is accounted for using hedge accounting. Effective November 2006, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in December 2009 is accounted for using hedge accounting. Effective November 2006, we entered into an interest rate swap that swaps $30.0 million of floating rate to fixed rate. The fixed rate cost is 4.765% plus our applicable LIBOR borrowing spread. This interest rate swap, which matures in March 2010, is not accounted for using hedge accounting. Effective March 2006, we entered into an interest rate swap that swaps $75.0 million of floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in November 2010 is accounted for using hedge accounting. In addition, the credit facility contains various covenants, which, among other things, limit our ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless we are the survivor; (iv) sell all or substantially all of our assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) our joint ventures to incur indebtedness or grant certain liens. The credit facility also contains covenants, which, among other things, require us to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. We are in compliance with the debt covenants contained in the credit facility for the years ended December 31, 2008 and 2007. The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us. Any event of default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations as well as our ability to make distributions to unitholders. On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. No prepayments under the term loan were required to be made in 2008 and 2007. If we receive greater than $15.0 million from the incurrence of indebtedness other than under the credit facility, we must prepay indebtedness under the credit facility with all such proceeds in excess of $15.0 million. Any such prepayments are first applied to the term loans under the credit facility. We must prepay revolving loans under the credit facility with the net - 65 - cash proceeds from any issuance of its equity. We must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults. As of March 3, 2009, our outstanding indebtedness includes $310.0 million under our credit facility. Seasonality A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and sulfur- based fertilizer products, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season. The demand for fertilizers is strongest during the early spring planting season. However, our terminalling and storage and marine transportation businesses and the molten sulfur business are typically not impacted by seasonal fluctuations. We expect to derive approximately half of our net income from our terminalling and storage, marine transportation, natural gas and sulfur businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our terminalling and storage and marine transportation businesses. For example, Hurricanes Gustav and Ike in the third quarter of 2008 and Hurricanes Katrina and Rita in the third quarter of 2005 adversely impacted our operating expenses and adversely impacted our terminalling and storage and marine transportation business’s revenues. Impact of Inflation Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2008, 2007 and 2006. However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot assure our unitholders that we will be able to pass along increased costs to our customers. Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot assure our unitholders that we will be able to pass along increased operating expenses to our customers. Environmental Matters Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no significant environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2008, 2007 or 2006. Item 7A. Quantitative and Qualitative Disclosures about Market Risk Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not engaged in commodity contract trading or hedging activities. However, in connection with our acquisition of Prism Gas, we have established a hedging policy. For the year ended December 31, 2008, changes in the fair value of our derivative contracts were recorded both in earnings and accumulated other comprehensive income (“AOCI”) since we have designated a portion of our derivative instruments as hedges as of December 31, 2008. Commodity Price Risk We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not engaged in commodity contract trading or hedging activities. Under our hedging policy, we monitor and manage the commodity market risk associated with our commodity risk exposure. In addition, we are focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the commodity derivative contracts include Shell Energy North America (US), L.P., Morgan Stanley Capital Group Inc. and Wachovia Bank. - 66 - On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, and have established a maximum credit limit threshold pursuant to our hedging policy and monitor the appropriateness of these limits on an ongoing basis. Currently, we have entered into these derivative transactions with an investment grade subsidiary of a major oil company and investment grade banks. While we anticipate that future derivative transactions will be entered into with investment grade counterparties, and that we will actively monitor the credit rating of such counterparties, it is nevertheless possible that losses will result from counterparty credit risk in the future. Such risks may be more likely due to the worldwide financial and credit crisis. We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales activities. Gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on POL and POP basis. Prism Gas has entered into hedging transactions through 2010 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas, and natural gasoline. In October 2008, we elected to discontinue hedge accounting treatment for certain crude oil derivative contracts. The impact to the Consolidated Statement of Operations was a mark to market gain of $1.8 million for the year ended December 31, 2008. In December 2008, we terminated three commodity swap agreements resulting in a cash receipt from the counterparty of $1.9 million. These swap agreements were accounted for as cash flow hedges. As a result of the termination, a gain of $0.4 million was recorded to the Partnership’s Consolidated Statement of Operations for the year ended December 31, 2008. As a result of declining commodity prices, we determined that continued reporting of losses in AOCI for certain commodity hedges would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods. Accordingly, the calculated loss of $2.6 million was immediately classified into 2008 earnings. The remaining deferred gains of $1.5 million and deferred losses of $0.1 million pertaining to the above commodity hedges will remain in AOCI and are expected to be reclassified into earnings in the same period that the forecasted hedge transaction is reported in earnings. Based on estimated volumes, as of December 31, 2008, Prism Gas had hedged approximately 47% and 21% of its commodity risk by volume for 2009 and 2010, respectively. As of December 31, 2008, commodity derivative assets of $3.6 million were included in current assets and $1.5 million were included in non-current assets on the balance sheet. We anticipate entering into additional commodity derivatives on an ongoing basis to manage risk associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that we will be able to do so or that the terms thereof will be similar to our existing hedging arrangements. In addition, we will enter into derivative arrangements that include the specific NGL products as well as natural gas and crude oil. Natural Gas Commodity Hedged Year 2009 2009 Condensate & Natural Gasoline 2009 ENatural Gasoline 2009 2009 2010 Condensate 2010 Natural Gasoline 2010 Condensate 2010 Natural Gasoline Condensate Natural Gasoline Hedging Arrangements in Place As of December 31, 2008 Volume Type of Derivative 30,000 MMBTU/Month Natural Gas Swap ($9.025) Crude Oil Swap ($69.08) 3,000 BBL/Month Crude Oil Swap ($70.90) 3,000 BBL/Month Crude Oil Swap ($70.45) 1,000 BBL/Month Natural Gasoline Swap ($86.42) 2,000 BBL/Month Crude Oil Swap ($69.15) 2,000 BBL/Month Crude Oil Swap ($72.25) 3,000 BBL/Month Crude Oil Swap ($104.80) 1,000 BBL/Month Natural Gasoline Swap ($94.14) Mt. Belvieu (Non-TET) 1,000 BBL/Month Basis Reference Columbia Gulf NYMEX NYMEX NYMEX Mt. Belvieu (Non-TET) NYMEX NYMEX NYMEX Our principal customers with respect to Prism Gas’ natural gas gathering and processing services are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of our natural gas and NGL sales are made at market-based prices. Our standard gas and NGL sales contracts contain adequate - 67 - assurance provisions which allows for the suspension of deliveries, cancellation of agreements or continuance of deliveries to the buyer after the buyer provides security for payment in a form satisfactory to us. For additional information regarding our hedging activities, please see “Note 16 – Commodity Cash Flow Hedges” in our “Notes to Consolidated Financial Statements” contained herein. Interest Rate Risk We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 6.48% as of December 31, 2008. We had a total of $295.0 million of indebtedness outstanding under our credit facility as of the date hereof of which $60.0 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on December 31, 2008, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $0.6 million annually. We have entered into interest rate protection agreements to manage our interest rate risk exposure by fixing a portion of the interest expense we pay on our long-term debt under our credit facility. There is considerable turmoil in the world economy and banking markets which could affect whether the counterparties to such interest rate protection agreements are able to honor their agreements. If the counterparties fail to honor their commitments, we could experience higher interest rates, which could have a material adverse effect on our business, financial condition and results of operations. In addition, if the counterparties fail to honor their commitments, we also may be required to replace such interest rate protection agreements with new interest rate protection agreements, and such replacement interest rate protection agreements may be at higher rates than our current interest rate protection agreements. As of March 3, 2009, we had a total of $310.0 million of indebtedness outstanding under our credit facility. The impact of a 1% increase in interest rates on this amount of unhedged floating rate debt would result in an increase in interest expense, and a corresponding decrease in net income of approximately $3.0 million annually. - 68 - Item 8. Financial Statements and Supplementary Data The following financial statements of Martin Midstream Partners L.P. (Partnership): Page Report of Independent Registered Public Accounting Firm........................................................................................ 70 Report of Independent Registered Public Accounting Firm........................................................................................ 71 Consolidated Balance Sheets as of December 31, 2008 and 2007 .............................................................................. 72 Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006.............................. 73 Consolidated Statements of Changes in Capital for the years ended December 31, 2008, 2007 and 2006................. 74 Consolidated Statements of Comprehensive Income for the years ended December 31, 2008 and 2007 ................... 75 Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006 ............................ 76 Notes to the Consolidated Financial Statements ......................................................................................................... 77 - 69 - Report of Independent Registered Public Accounting Firm The Board of Directors Martin Midstream GP LLC: We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of Martin Midstream’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Martin Midstream Partners L.P. and subsidiaries and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Accounting Oversight Board (United States), Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 4, 2009 expressed an unqualified opinion on the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting. KPMG LLP /s/ KPMG LLP Shreveport, Louisiana March 4, 2009 - 70 - Report of Independent Registered Public Accounting Firm The Board of Directors Martin Midstream GP LLC: We have audited Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Martin Midstream’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A(b). Our responsibility is to express an opinion on Martin Midstream’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issue by the Committee of Sponsoring Organizations of the Treadway Commission. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three year period ended December 31, 2008 and our report dated March 4, 2009 expressed an unqualified opinion on those consolidated financial statements. . /s/ KPMG LLP KPMG LLP Shreveport, Louisiana March 4, 2009 - 71 - MARTIN MIDSTREAM PARTNERS L.P. CONSOLIDATED BALANCE SHEETS Assets Cash.................................................................................................................... Accounts and other receivables, less allowance for doubtful accounts of $481 and $394...................................................................................................... Product exchange receivables ............................................................................ Inventories.......................................................................................................... Due from affiliates ............................................................................................. Fair value of derivatives ..................................................................................... Other current assets ............................................................................................ Total current assets...................................................................................... Property, plant, and equipment, at cost .............................................................. Accumulated depreciation.................................................................................. Property, plant and equipment, net.............................................................. Goodwill............................................................................................................. Investment in unconsolidated entities ................................................................ Fair value of derivatives ..................................................................................... Other assets, net.................................................................................................. Liabilities and Capital Current installments of long-term debt............................................................... Trade and other accounts payable ...................................................................... Product exchange payables ................................................................................ Due to affiliates .................................................................................................. Income taxes payable ......................................................................................... Fair value of derivatives ..................................................................................... Other accrued liabilities...................................................................................... Total current liabilities ................................................................................ Long-term debt................................................................................................... Deferred income taxes........................................................................................ Fair value of derivatives ..................................................................................... Other long-term obligations ............................................................................... Total liabilities ............................................................................................ Partners’ capital.................................................................................................. Accumulated other comprehensive income (loss).............................................. Total partners’ capital ................................................................................. Commitments and contingencies........................................................................ See accompanying notes to consolidated financial statements. December 31, 2008 2007 (Dollars in thousands) $ 7,983 $ 4,113 68,117 6,924 42,461 555 3,623 1,079 130,742 537,381 (125,256) 412,125 37,405 79,843 1,469 7,332 $ 668,916 $ — 87,382 10,924 13,420 414 6,478 6,077 124,695 295,000 8,538 4,302 1,667 434,202 239,649 (4,935) 234,714 88,039 10,912 51,798 2,325 235 584 158,006 441,117 (98,080) 343,037 37,405 75,690 — 9,439 $ 623,577 $ 21 104,598 24,554 7,543 602 4,502 4,752 146,572 225,000 8,815 5,576 1,766 387,729 242,610 (6,762) 235,848 $ 668,916 $ 623,577 - 72 - MARTIN MIDSTREAM PARTNERS L.P. CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2006 2007 2008 (Dollars in thousands, except per unit amounts) Revenues: Terminalling and storage............................................................ Marine transportation ................................................................. $ 36,067 76,349 $ 29,400 59,579 $ 24,182 47,835 Product sales: Natural gas services ............................................................ Sulfur services..................................................................... Terminalling and storage ................................................... Total revenues .............................................................. Costs and expenses: Cost of products sold: Natural gas services ............................................................ Sulfur services..................................................................... Terminalling and storage .................................................... Expenses: Operating expenses .................................................................... Selling, general and administrative ............................................ Depreciation and amortization ................................................... Total costs and expenses ..................................................... Other operating income ..................................................................... Operating income................................................................ 679,375 371,949 50,218 1,101,542 1,213,958 657,662 313,142 42,721 1,013,525 102,894 16,939 31,218 1,164,576 209 49,591 Other income (expense): Equity in earnings of unconsolidated entities............................. Interest expense.......................................................................... Debt prepayment premium......................................................... Other, net.................................................................................... Total other income (expense).............................................. 13,224 (19,777) — 483 (6,070) Net income before taxes............................................................. Income taxes...................................................................................... 43,521 711 Net income ................................................................................. $ 42,810 515,992 131,326 29,525 676,843 765,822 495,641 97,577 25,471 618,689 83,533 11,985 23,442 737,649 703 28,876 10,941 (14,533) — 299 (3,293) 25,583 644 $ 24,939 389,735 102,597 12,035 504,367 576,384 374,218 75,165 9,787 459,170 65,387 10,977 17,597 553,131 3,356 26,609 8,547 (12,466) (1,160) 713 (4,366) 22,243 — $ 22,243 General partner’s interest in net income............................................ Limited partners’ interest in net income............................................ $ 3,301 $ 39,509 $ 1,564 $ 23,375 $ 949 $ 21,294 Net income per limited partner unit — basic and diluted ............... $ 2.72 $ 1.67 $ 1.69 Weighted average limited partner units — basic............................... Weighted average limited partner units — diluted............................ 14,529,826 14,534,722 14,018,799 14,022,545 12,602,000 12,604,425 See accompanying notes to consolidated financial statements. - 73 - MARTIN MIDSTREAM PARTNERS L.P. CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL For the years ended December 31, 2008, 2007 and 2006 Partners’ Capital Limited Partners Common Subordinated Units Amount Units Amount (Dollars in thousands) Amount General Partner Accumulated Comprehensive Income Amount Total Balances – December 31, 2005 .................................. 5,829,652 $ 100,206 3,402,690 $ (5,642) $ 1,001 — $ 95,565 5,225 949 — — — — — — — — 2,358 — — — 1,192 — — — — — — — — — 2 22,243 95,272 15,000 2,358 — 24 (32,059) 2 — — — — — 24,939 55,933 1,192 — 46 Net income.................................................................... — 16,069 Follow-on public offering ............................................ 3,450,000 95,272 Issuance of common units ........................................... 470,484 15,000 General partner contribution ........................................ — — — — — — Conversion of subordinated units to common units..... 850,672 (2,495) (850,672) 2,495 Unit-based compensation ............................................. 3,000 24 Cash distributions ($2.44 per unit).............................. Commodity hedging gains reclassified to earnings ..... — — (22,650) — — — — (8,302) (1,107) — — Adjustment in fair value of derivatives........................ — — — — — 120 120 Balances – December 31, 2006 .................................. 10,603,808 $ 201,426 2,552,018 $ (6,224) $ 3,201 $ 122 $ 198,525 Net Income ........................................................... — 19,781 Follow-on public offering .................................... 1,380,000 55,933 General partner contribution ................................ — — — — — 3,594 1,564 Conversion of subordinated units to common units..... 850,672 (3,243) (850,672) 3,243 Unit-based compensation ..................................... 3,000 46 — — Cash distributions ($2.60 per unit)...................... Commodity hedging gains reclassified to earnings ..... — — (29,423) — (6,635) (1,845) — (37,903) — — — — 478 478 Adjustment in fair value of derivatives................ — — — — — (7,362) (7,362) Balances – December 31, 2007 .................................. 12,837,480 $244,520 1,701,346 $ (6,022) $ 4,112 $ (6,762) $ 235,848 Net Income ........................................................... Cash distributions ($2.91 per unit)...................... — — 34,978 — 4,531 3,301 (37,357) — (4,951) (3,409) Conversion of subordinated units to common units..... 850,672 (2,754) (850,672) 2,754 Unit-based compensation ..................................... 3,000 Purchase of treasury units..................................... (3,000) 39 (93) — — — — — — — — — — — — 42,810 (45,717) — 39 (93) Adjustment in fair value of derivatives................ — — — — — 1,827 1,827 Balances – December 31, 2008 .......................... 13,688,152 $ 239,333 850,674 $ (3,688) $ 4,004 $ (4,935) $ 234,714 See accompanying notes to consolidated financial statements. - 74 - MARTIN MIDSTREAM PARTNERS L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in thousands) Year Ended December 31, 2008 2007 (Dollars in thousands) 2006 Net income .......................................................................... $ 42,810 $ 24,939 $ 22,243 Changes in fair values of commodity cash flow hedges ..... Cash flow hedging gains reclassified to earnings................ Changes in fair value of interest rate cash flow hedges ...... 4,219 3,043 (5,435) (3,569) 478 (3,793) 370 2 (250) Comprehensive income................................................ $ 44,637 $ 18,055 $ 22,365 See accompanying notes to consolidated financial statements. - 75 - MARTIN MIDSTREAM PARTNERS L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS Cash flows from operating activities: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization............................................................................... Amortization of deferred debt issue costs ............................................................. Deferred income taxes............................................................................................ Gain on disposition or sale of property, plant, and equipment.............................. Gain on involuntary conversion of property, plant, and equipment ...................... Equity in earnings of unconsolidated entities ........................................................ Distributions from unconsolidated entities.......................................................... Distribution in-kind from unconsolidated entities................................................. Non-cash mark-to-market on derivatives .............................................................. Other....................................................................................................................... Change in current assets and liabilities, excluding effects of acquisitions and dispositions: Accounts and other receivables...................................................................... Product exchange receivables ........................................................................ Inventories ...................................................................................................... Due from affiliates.......................................................................................... Other current assets ........................................................................................ Trade and other accounts payable.................................................................. Product exchange payables ............................................................................ Due to affiliates .............................................................................................. Income taxes payable ..................................................................................... Other accrued liabilities ................................................................................. Change in other non-current assets and liabilities ................................................. Net cash provided by operating activities ................................................ Cash flows from investing activities: Payments for property, plant, and equipment............................................................... Acquisitions, net of cash acquired ................................................................................ Proceeds from sale of property, plant, and equipment ................................................. Insurance proceeds from involuntary conversion of property, plant and equipment............................................................................................................... Return of investments from unconsolidated entities ........................................................... Distributions from (contributions to) unconsolidated entities for operations .............. Net cash used in investing activities....................................................... Cash flows from financing activities: Payments of long-term debt .......................................................................................... Proceeds from long-term debt ...................................................................................... Net proceeds from follow on public offering ............................................................... General partner contribution ......................................................................................... Purchase of treasury units ............................................................................................ Proceeds from issuance of common units .................................................................... Payments of debt issuance costs ................................................................................... Cash distributions paid.................................................................................................. Net cash provided by financing activities .............................................. Net increase(decrease) in cash................................................ Cash at beginning of period ................................................................................... Cash at end of period ............................................................................................. See accompanying notes to consolidated financial statements. 2008 Year Ended December 31, 2007 (Dollars in thousands) 2006 $ 42,810 $ 24,939 $ 22,243 31,218 1,120 (277) (144) (65) (13,224) 500 9,725 (2,328) 39 19,754 3,988 9,337 1,770 (495) (17,216) (13,630) 5,877 (188) 1,325 7 79,903 (94,969) (5,983) 419 1,503 1,225 (2,379) (100,184) (257,191) 327,170 — — (93) — (18) (45,717) 24,151 3,870 4,113 $ 7,983 23,442 1,233 (149) (703) — (10,941) 1,523 9,337 3,904 46 (27,066) (3,836) (18,297) (995) 198 47,535 9,817 (2,931) 245 870 (154) 58,017 (82,164) (41,271) 1,290 — 1,952 (6,910) (127,103) (169,024) 219,950 55,933 1,192 — — (252) (37,903) 69,896 810 3,303 $ 4,113 17,597 1,040 — (231) (3,125) (8,547) 541 8,311 (389) 24 13,763 (4,935) 890 145 115 (13,937) 5,113 6,982 — (5,912) (386) 39,302 (66,352) (24,306) 1,825 4,812 433 (11,510) (95,098) (163,010) 135,801 95,272 2,358 — 15,000 (371) (32,059) 52,991 (2,805) 6,108 $ 3,303 - 76 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) (1) ORGANIZATION AND DESCRIPTION OF BUSINESS Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the United Stated Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products, natural gas services, marine transportation services for petroleum products and by products, and sulfur and sulfur based products processing, manufacturing, marketing and distribution. The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry. The Partnership owns Prism Gas Systems I, L.P. (“Prism Gas”) which is engaged in the gathering, processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana. Prism Gas owns a 50% ownership interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”), and Bosque County Pipeline (“BCP”) each accounted for under the equity method of accounting. (2) SIGNIFICANT ACCOUNTING POLICIES (a) Principles of Presentation and Consolidation The consolidated financial statements include the financial statements of the Partnership and its wholly- owned subsidiaries and equity method investees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities as defined by FASB Interpretation No 46(R) Consolidation of Variable Interest Entities (“FIN 46R”) and to assess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with FIN 46(R). No such variable interest entities exist as of December 31, 2008 or 2007. (b) Product Exchanges The Partnership enters into product exchange agreements with third parties whereby the Partnership agrees to exchange NGLs and sulfur with third parties. The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method. (c) Inventories Inventories are stated at the lower of cost or market. Cost is determined by using the first-in, first-out (FIFO) method for all inventories. - 77 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) (d) Revenue Recognition Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the product from either the storage facility or pipeline. Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip. For time charters, revenue is recognized based on a per day rate. Sulfur services – Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership based on specific contract terms at either the shipping or delivery point. (e) Equity Method Investments The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. No portion of the net income from these entities is included in the Partnership’s operating income. The Partnership’s Prism Gas subsidiary owns an unconsolidated 50% interest in Waskom, Matagorda, and PIPE. As a result, these assets are accounted for by the equity method. On June 30, 2006, the Partnership, through the Partnership’s Prism Gas subsidiary, acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). The lease contract provides for termination in June 2009 and an extension of the lease is not currently contemplated. This interest is accounted for by the equity method of accounting. (f) Property, Plant, and Equipment Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets. Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss. Goodwill and Other Intangible Assets (g) Goodwill represents the excess of costs over fair value of assets of businesses acquired. Goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually in accordance with the provisions of Statement of Financial Accounting Standards No. 142 (“SFAS No. 142”), Goodwill and Other Intangible Assets. Intangible assets with estimated useful lives are amortized over their respective estimated useful lives to their estimated residual values, - 78 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) and reviewed for impairment in accordance with Statement of Financial Accounting Standards No. 144 (“SFAS No. 144”), Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible assets primarily consist of covenants not-to-compete and contracts obtained through business combinations and are being amortized over the life of the respective agreements. Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify their reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. Goodwill is assigned to reporting units at the date the goodwill is initially recorded. Once goodwill has been assigned to reporting units, it no longer retains its association with a particular acquisition, and all of the activities within a reporting unit, whether acquired or organically grown, are available to support value of the goodwill. The Partnership performed the annual impairment tests as of September 30, 2008, September 30, 2007 and September 30, 2006, respectively. In performing such tests, it was determined that there were four “reporting units” which contained goodwill. These reporting units were in each of the four reporting segments: terminalling, natural gas services, marine transportation, and sulfur services. The estimated fair value of the reporting units with goodwill were developed using the guideline public company method, the guideline transaction method, and the discounted cash flow (“DCF”) method using observable market data where available. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired. At September 30, 2008, 2007 and 2006 the estimated fair value of each of the four reporting units was in excess of its carrying value resulting in no impairment. As a result of the deterioration in the overall stock market subsequent to September 30, 2008 and the decline in the Partnership’s unit price, the Partnership reviewed specific factors, as outlined in SFAS No. 142, to determine if the Partnership had a trigging event that required it to test the goodwill for impairment as of December 31, 2008. These factors included whether there have been any significant fundamental changes since the annual impairment test to (i) the Partnership as a whole or to the reporting units, including regulatory changes, (ii) the level of operating cash flows, (iii) the expectation of future levels of operating cash flows, (iv) the executive management team, and (v) the carrying value of the other long-lived assets. While these factors did not indicate a triggering event occurred, the Partnership’s unit price fell to a point by December 31, 2008 that resulted in the total market capitalization being less than the partner’s equity. The Partnership determined this to be a triggering event requiring the Partnership to perform an impairment test as of December 31, 2008. As a result of the goodwill impairment test for each of the four reporting units as of December 31, 2008, no impairment was determined to exist. (h) Debt Issuance Costs In connection with the Partnership’s multi-bank credit facility, on November 10, 2005, it incurred debt issuance costs of $3,258. In connection with the amendment and expansion of the Partnership’s multi-bank credit facility on June 30, 2006, it incurred debt issuance costs of $372. In connection with the amendment and expansion of the Partnership’s multi-bank credit facility on December 28, 2007, it incurred debt issuance costs of $252. These debt issuance costs, along with the remaining unamortized deferred issuance costs relating to the line of credit facility as of November 10, 2005 which remain deferred, are amortized over the remainder of the 60 month term of the original debt arrangement. Amortization of debt issuance cost, which is included in interest expense for the years ended December 31, 2008, 2007 and 2006, totaled $1,120, $1,233, and $1,040, respectively, and accumulated amortization amounted to $5,445 and $4,324 at December 31, 2008 and 2007, respectively. The unamortized balance of debt issuance costs, classified as other assets amounted to $2,086 and $3,188 at December 31, 2008 and 2007, respectively. (i) Impairment of Long-Lived Assets In accordance with SFAS No. 144, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the - 79 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. The Partnership has not identified any triggering events in 2008, 2007 or 2006 that would require an assessment for impairment of long-lived assets. (j) Asset Retirement Obligation Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143) and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143, which provide accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an Asset Retirement Obligation (“ARO”) at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. The Partnership’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment. The transportation equipment includes pipeline systems. The Partnership transports NGLs through the pipeline system and gathering system. The Partnership also gathers natural gas from wells owned by producers and delivers natural gas and NGLs on the Partnership’s pipeline systems, primarily in Texas and Louisiana to the fractionation facility of the Partnership’s 50% owned joint venture. The Partnership is obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of the Partnership’s assets. However, the Partnership is not able to reasonably determine the fair value of the asset retirement obligations for the Partnership’s trunk and gathering pipelines and the Partnership’s surface facilities, since future dismantlement and removal dates are indeterminate. In order to determine a removal date of the Partnership’s gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of natural gas, the Partnership is not a producer of the field reserves, and the Partnership therefore does not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which the Partnership gathers natural gas. In the absence of such information, the Partnership is not able to make a reasonable estimate of when future dismantlement and removal dates of the Partnership’s gathering assets will occur. With regard to the Partnership’s trunk pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. The Partnership’s right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, the Partnership can evaluate the Partnership’s trunk pipelines for alternative uses, which can be and have been found. The Partnership will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. (k) Derivative Instruments and Hedging Activities In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, the Partnership has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in accumulated other comprehensive income as a component of equity. (l) Comprehensive Income Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the partnership includes unrealized gains and losses on derivative financial instruments. In accordance with SFAS No. 133, the partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income. - 80 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) (m) Unit Grants In May 2008, the Partnership issued 1,000 restricted common units to each of its three independent, non- employee directors under its long-term incentive plan from treasury shares purchased by the Partnership in the open market for $93. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012. In May 2007, the Partnership issued 1,000 restricted common units to each of its three independent, non- employee directors under its long-term incentive plan. These units vest in 25% increments beginning in January 2008 and will be fully vested in January 2011. In January 2006, the Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010. The Partnership accounts for the transaction under Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based payment transactions was $39, $46 and $24 for the years ended December 31, 2008, 2007 and 2006, respectively. The Partnership’s general partner contributed cash of $2 in May 2007 and $2 in January 2006 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership. (n) Incentive Distribution Rights The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights in the Partnership. Incentive distribution rights represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the partnership agreement. The target distribution levels entitle the general partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unit holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the years ended December 31, 2008, 2007 and 2006, the general partner received $2,495, $1,087 and $484 in incentive distributions. (o) Net Income per Unit Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest (including its incentive distribution in excess of its 2% interest) by the weighted average number of outstanding limited partner units during the period. Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06’’), “Participating Securities and the Two-Class Method under FASB Statement No. 128,’’ as discussed below, Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership. EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period where the Partnership’s aggregate net income exceeds the Partnership’s aggregate distribution for such period, the Partnership is required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF 03-06 does not impact the Partnership’s overall net income or other financial results; however, for periods in which aggregate net income exceeds the Partnership’s aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of the Partnership’s aggregate earnings is allocated to the incentive distribution rights held by the Partnership’s general partner, as if distributed, even though the Partnership makes cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In - 81 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) accounting periods where aggregate net income does not exceed the Partnership’s aggregate distributions for such period, EITF 03-06 does not have any impact on the Partnership’s earnings per unit calculation. The weighted average units outstanding for basic net income per unit were 14,529,826, 14,018,799 and 12,602,000 for years ended December 31, 2008, 2007 and 2006, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 4,896 units, 3,746 units and 2,425 for the years ended December 31, 2008, 2007 and 2006, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan. (p) Indirect Selling, General and Administrative Expenses Indirect selling, general and administrative expenses are incurred by Martin Resource Management Corporation (“Martin Resource Management”) and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2,896, $1,493 and $1,493, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. (q) Environmental Liabilities The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. (r) Allowance for Doubtful Accounts. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable. (s) Use of Estimates Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. (t) Income Taxes With respect to our taxable subsidiary (Woodlawn Pipeline Co., Inc.), income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. - 82 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) (3) FAIR VALUE MEASUREMENTS During the first quarter of 2008, the Partnership adopted FASB Statement No. 157, Fair Value Measurements (FAS 157). FAS 157 established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of FAS 157 had no impact on the Partnership’s financial position or results of operations. FAS 157 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that each asset and liability carried at fair value be classified into one of the following categories: Level 1: Quoted market prices in active markets for identical assets or liabilities. Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data. Level 3: Unobservable inputs that are not corroborated by market data. The Partnership’s derivative instruments which consist of commodity and interest rate swaps are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Refer to Notes 13 and 16 for further information on the Partnership’s derivative instruments and hedging activities. As prescribed by the FAS 157 levels listed above, the Partnership considers the Partnership’s derivative assets and liabilities as Level 2. The net fair value of the Partnership’s assets and liabilities measured on a recurring basis was a liability of $5,688 and $9,843 at December 31, 2008 and December 31, 2007, respectively. (4) RECENT ACCOUNTING PRONOUNCEMENTS In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133” (SFAS No. 161). SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and is effective for the Partnership on January 1, 2009. Since SFAS No. 161 requires enhanced disclosures, without a change to existing standards relative to measurement and recognition, the Partnership’s adoption of SFAS No. 161 will not have any effect on our consolidated financial statements. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes new accounting, disclosure and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 is effective for the Partnership on January 1, 2009. The adoption of SFAS No. 160 will not have a material impact on the Partnership’s consolidated financial statements. However, it could impact accounting for future transactions. In December 2007, the FASB issued SFAS No. 141(Revised 2007), “Business Combinations” (SFAS No. 141(R)). SFAS No. 141(R) retains the underlying concepts of SFAS No. 141 in that all business combinations are still required to be accounted for at fair value under the acquisition method of accounting, but SFAS No. 141(R) establishes revised principles and requirements for how entities will recognize and measure assets and liabilities acquired in a business combination, including but not limited to, generally expensing of acquisition costs as incurred and valuing noncontrolling interests (minority interests) at fair value at the acquisition date. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. The Partnership will adopt the provisions of SFAS No. 141(R) to business combinations completed on or after January 1, 2009. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Partnership to choose, at specified election dates, to measure eligible items at fair value (the “fair value - 83 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) option”). The Partnership would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. SFAS No. 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Partnership adopted SFAS No. 159 on January 1, 2008 but has not elected to apply the fair value option provided under SFAS No. 159 to any eligible assets or liabilities.. In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (SFAS No. 157), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) FAS 157-2, which delayed the effective date of SFAS No. 157 for certain nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statement on a recurring basis, to fiscal years beginning after November 15, 2008. In February 2008, the FASB issued FSP SFAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP SFAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. On January 1, 2008, the Partnership adopted the portion of SFAS No. 157 that was not delayed, and since the Partnership’s existing fair value measurements are consistent with the guidance of SFAS No. 157, the partial adoption of SFAS No. 157 did not have a material impact on the Partnership’s consolidated financial statements. The adoption of the deferred portion of SFAS No. 157 on January 1, 2009 is not expected to have a material impact on the Partnership’s consolidated financial statements. See Note 3 for expanded disclosures about fair value measurements. (5) ACQUISITIONS (a) Stanolind Terminal Assets. In January 2008, The Partnership acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management Corporation (“Martin Resource Management”) for $5,983 which was allocated to property, plant and equipment. The Partnership entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks. In connection with the acquisition, the Partnership borrowed approximately $6,000 under its credit facility. (b) Asphalt Terminal. In October 2007, the Partnership acquired the asphalt assets of Monarch Oil, Inc. and related companies (“Monarch Oil”) for $3,927 which was allocated to property, plant and equipment. The results of Monarch Oil’s operations have been included in the consolidated financial statements beginning October 2, 2007. The assets are located in Omaha, Nebraska. The Partnership entered into an agreement with Martin Resource Management, whereby Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will bear all additional expenses to operate the facility. In connection with the Partnership’s Monarch Oil acquisition on October 2, 2007, the Partnership borrowed approximately $3,900 under its revolving credit facility. (c) Lubricants Terminal In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) located in Channelview, Texas. The results of Mega Lubricant’s operations have been included in the consolidated financial statements beginning June 13, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the - 84 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) remaining $1,020 was recorded as goodwill. The goodwill was a result of Mega Lubricant’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional lubricant blending and truck loading and unloading services to customers. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment. The terminal is located on 5.6 acres of land, and consists of 38 tanks with a storage capacity of approximately 15,000 Bbls, pump and piping infrastructure for lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an administrative office. The purchase price of $4,738, including two three-year non-competition agreements totaling $530 and goodwill of $1,020, was allocated as follows: Current assets Property, plant and equipment, net Goodwill Other assets Other liabilities Total $ 446 3,042 1,020 530 (300) 4,738 $ In connection with the acquisition, the Partnership borrowed approximately $4,600 under its credit facility. (d) Woodlawn Pipeline Co., Inc. On May 2, 2007, the Partnership, through its subsidiary Prism Gas, acquired 100% of the outstanding stock of Woodlawn. The results of Woodlawn’s operations have been included in the consolidated financial statements beginning May 2, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $8,785 was recorded as goodwill. The goodwill was a result of Woodlawn’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional gathering services to customers through internal growth projects including natural gas processing, fractionation and pipeline expansions as well as new pipeline construction. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment. Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 MMcfd processing plant. Prism Gas also acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from Woodlawn to the Texas Eastern Transmission pipeline system. The selling parties in this transaction were Lantern Resources, L.P., David P. Deison, and Peak Gas Gathering L.P. The final purchase price, after final adjustments for working capital, was $32,606 and was funded by borrowings under the Partnership’s credit facility. The purchase price of $32,606, including four two-year non-competition agreements and other intangibles reflected as other assets, was allocated as follows: Current assets Property, plant and equipment, net Goodwill Other assets Current liabilities Deferred income taxes Other long-term obligations Total - 85 - $ 4,297 29,101 8,785 3,339 (3,889) (8,964) (63) 32,606 $ MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) The identifiable intangible assets of $3,339 are subject to amortization over a weighted-average useful life of approximately ten years. The intangible assets include four non-competition agreements totaling $40, customer contracts associated with the gathering and processing assets of $3,002, and a transportation contract associated with the residue gas pipeline of $297. In connection with the acquisition, the Partnership borrowed approximately $33,000 under its credit facility. (e) Asphalt Terminals. In August 2006 and October 2006, respectively, the Partnership acquired the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (“Prime”), for $4,679 which was allocated to property, plant and equipment. The assets are located in Houston, Texas and Port Neches, Texas. The Partnership entered into an agreement with Martin Resource Management, which Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will assume all additional expenses to operate the facility. (f) Corpus Christi Barge Terminal. In July 2006, the Partnership acquired a marine terminal located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6,200 which was all allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land, and includes three tanks with a combined shell capacity of approximately 240,000 barrels, pump and piping infrastructure for truck unloading and product delivery to two oil docks, and there are several pumps, controls, and an office building on site for administrative use. (g) Marine Vessels. In November 2006, the Partnership acquired the La Force, an offshore tug, for $6,001 from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 with new engines installed in 2005. In January 2006, the Partnership acquired the Texan, an offshore tug, and the Ponciana, an offshore NGL barge, for $5,850 from Martin Resource Management. The acquisition price was based on a third party appraisal. In March 2006, these vessels went into service under a long term charter with a third party. In February 2006, the Partnership acquired the M450, an offshore barge, for $1,551 from a third party. In March 2006, this vessel went into service under a one-year charter with an affiliate of Martin Resource Management. (6) PUBLIC OFFERINGS In May 2007, the Partnership completed a public offering of 1,380,000 common units at a price of $42.25 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 64.3% limited partnership interest in the Partnership. Total proceeds from the sale of the 1,380,000 common units, net of underwriters’ discounts, commissions and offering expenses were $55,933. The Partnership’s general partner contributed $1,190 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital. A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows (all amounts are in thousands): Proceeds received: Sale of common units ........................................................................................... General partner contribution ................................................................................. Total proceeds received................................................................................. $ 58,305 1,190 $ 59,495 - 86 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Use of Proceeds: Underwriter’s fees ................................................................................................ Professional fees and other costs .......................................................................... Repayment of debt under revolving credit facility ............................................... Working capital .................................................................................................... Total use of proceeds.............................................................................. $ 2,107 265 55,850 1,273 $ 59,495 In January 2006, the Partnership completed a public offering of 3,450,000 common units at a price of $29.12 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 61.6% limited partnership interest in the Partnership. Total proceeds from the sale of the 3,450,000 common units, net of underwriters’ discounts, commissions and offering expenses were $95,272. The Partnership’s general partner contributed $2,050 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital. A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows (all amounts are in thousands): Proceeds received: Sale of common units ........................................................................................... General partner contribution ................................................................................. Total proceeds received................................................................................. $100,464 2,050 $102,514 Use of Proceeds: Underwriter’s fees ................................................................................................ Professional fees and other costs .......................................................................... Repayment of debt under revolving credit facility ............................................... Working capital .................................................................................................... Total use of proceeds.............................................................................. $ 4,521 671 62,000 35,322 $102,514 (7) INVENTORIES Components of inventories at December 31, 2008 and 2007 were as follows: Natural gas liquids ................................................................................... Sulfur ....................................................................................................... Sulfur Based Products.............................................................................. Lubricants ................................................................................................ Other ........................................................................................................ 2008 $10,530 6,522 14,879 8,110 2,420 $42,461 2007 $31,283 7,490 6,626 5,345 1,054 $51,798 (8) PROPERTY, PLANT AND EQUIPMENT At December 31, 2008 and 2007, property, plant, and equipment consisted of the following: Depreciable Lives 2008 2007 Land ........................................................................... Improvements to land and buildings.......................... Transportation equipment .......................................... Storage equipment ..................................................... — 10-25 years 3-7 years 5-20 years $ 15,647 43,092 1,768 45,196 $14,515 34,585 616 38,652 - 87 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Depreciable Lives 2008 2007 Marine vessels ........................................................... Operating equipment ................................................. Furniture, fixtures and other equipment..................... Construction in progress ............................................ 4-25 years 3-20 years 3-20 years 200,473 192,434 1,548 37,223 $537,38 1 147,627 172,282 1,542 31,298 $441,117 Depreciation expense for the year ended December 31, 2008, 2007, and 2006 was $30,319, $22,455, and $16,932 respectively. (9) GOODWILL AND OTHER INTANGIBLE ASSETS At December 31, 2008 and 2007, goodwill balances consisted of the following: Carrying amount of goodwill: Terminalling and storage ................................................................. Natural gas services ......................................................................... Marine transportation....................................................................... Sulfur services ................................................................................. 2008 2007 $ 1,020 29,010 2,026 5,349 $37,405 $ 1,020 29,010 2,026 5,349 $37,405 At December 31, 2008 and 2007, covenants not-to-compete balances consisted of the following: Covenants not-to-compete: Terminalling and storage ..................................................................... Natural gas services ............................................................................. Sulfur services ..................................................................................... Less accumulated amortization............................................................ 2008 2007 $ 1,928 40 790 2,758 1,539 $ 1,219 $ 1,928 640 790 3,358 1,610 $ 1,748 Intangible assets consists of the covenants not-to-compete listed above, customer contracts associated with gathering and processing assets and a transportation contract associated with the residue gas pipeline. The covenants not-to-compete and contracts are presented in the consolidated balance sheets as other assets, net. Aggregate amortization expense for amortizing intangible assets was $899, $987, and $665 for the years ended December 31, 2008, 2007, and 2006, respectively. Estimated amortization expense for the years subsequent to December 31, 2008 are as follows: 2009 - $888; 2010 - $597; 2011 - $513; 2012 - $509; 2013 - $511; subsequent years -$1,731. (10) LEASES The Partnership has numerous non-cancelable operating leases primarily for transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine vessel charters. The future minimum lease payments under non-cancelable operating leases for years subsequent to December 31, 2008 are as follows: 2009 - $3,814; 2010 - $3,652; 2011 - $3,459; 2012 - $3,186; 2013 - $2,488; subsequent years - $9,761. - 88 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Rent expense for operating leases for the years ended December 31, 2008, 2007 and 2006 was $12,527, $12,492 and $8,407, respectively. (11) INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES The Partnership, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”) and a 20% ownership interest in a partnership which owns the lease rights to Bosque County Pipeline (“BCP”). Each of these interests is accounted for under the equity method of accounting. In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $594 for both the years ended December 31, 2008 and 2007 has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $10,091 and $10,685 at December 31, 2008 and 2007, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in 2008, 2007 or 2006. As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids (“NGLs”) that are retained according to Waskom’s contracts with certain producers. The NGLs are valued at prevailing market prices. In addition, cash distributions are received and cash contributions are made to fund operating and capital requirements of Waskom. Activity related to these investment accounts is as follows: Waskom PIPE Matagorda BCP Total Investment in unconsolidated entities, December 31, 2006 $ 64,937 $ 1,718 $ 3,786 $ 210 $ 70,651 Distributions in kind............................................................. Return on investments.......................................................... Contributions to (distributions from) unconsolidated entities for operations.......................................................... . Return of investments .......................................................... Equity in earnings: Equity in earnings from operations................................. Amortization of excess investment................................. (9,337) (884) 6,803 (1,741) — (517) — (118) — (122) — (93) — — (9,337) (1,523) 107 — 6,910 (1,952) 11,009 (550) 514 (15) 151 (29) (139) — 11, 535 (594) Investment in unconsolidated entities, December 31, 2007 $ 70,237 $ 1,582 $ 3,693 $ 178 $ 75,690 Distributions in kind............................................................. Return on investments.......................................................... Contributions to (distributions from) unconsolidated entities: Cash contributions............................................................ Contributions to (distributions from) unconsolidated entities for operations ...................................................... Return of investments .......................................................... Equity in earnings: Equity in earnings from operations................................. Amortization of excess investment................................. (9,725) (500) — — — — — — (9,725) (500) 1,250 129 — 80 1,459 920 (300) — (180) — (745) — — 920 (1,225) 13,646 (550) (302) (15) 640 (29) (166) — 13,818 (594) Investment in unconsolidated entities, December 31, 2008 $74,978 $ 1,214 $ 3,559 $ 92 $ 79,843 - 89 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Select financial information for significant unconsolidated equity method investees is as follows: Total Assets Long- Term Debt Partners’ Capital Revenues Net Income 2008 Waskom.......................................................................... $ 78,661 $ — $ 67,730 $115,031 $ 27,292 2007 Waskom.......................................................................... $ 66,772 $ — $ 57,149 $ 81,797 $ 22,019 2006 Waskom.......................................................................... $ 53,260 $ — $ 45,450 $ 65,600 $ 17,246 As of December 31, 2008 and 2007, the Partnership’s interest in cash of the unconsolidated equity method investees is $1,956 and $1,018, respectively. (12) LONG-TERM DEBT At December 31, 2008 and December 31, 2007, long-term debt consisted of the following: **$195,000 Revolving loan facility at variable interest rate (6.04%* weighted average at December 31, 2008), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees.................................. $ 165,000 $ 95,000 December 31, 2008 December 31, 2007 ***$130,000 Term loan facility at variable interest rate (7.04%* at December 31, 2008), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries........... Other secured debt maturing in 2008, 7.25% Total long-term debt Less current installments Long-term debt, net of current installments 130,000 130,000 — 295,000 — $295,000 21 225,021 21 $225,000 *Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing LIBOR borrowings is 2.50%. Effective January 1, 2009, the applicable margin for existing LIBOR borrowings will decrease to 2.00%. As a result of our leverage ratio test as of December 31, 2008, effective April 1, 2009, the applicable margin for existing LIBOR borrowings will remain at 2.00%. The Partnership incurs a commitment fee on the unused portions of the credit facility. **Effective October, 2008, the Partnership entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 2.820% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in October, 2010. ** Effective January, 2008, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 3.400% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in January, 2010. - 90 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) ** Effective September, 2007, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in September, 2010. **Effective November, 2006, the Partnership entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 4.82% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in December, 2009. ***The $130,000 term loan has $105,000 hedged. Effective March, 2006, the Partnership entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010. Effective November 2006, the Partnership entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This cash flow hedge matures in March, 2010. On November 10, 2005, the Partnership entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the Partnership increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. Effective December 28, 2007, the Partnership increased its revolving credit facility $75,000 resulting in a committed $195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of December 31, 2008, the Partnership had $165,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of December 31, 2008, the Partnership had $29,880 available under its revolving credit facility. On July 14, 2005, the Partnership issued a $120 irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program. The Partnership’s obligations under the credit facility are secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time without penalty. In addition, the credit facility contains various covenants, which, among other things, limit the Partnership’s ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell all or substantially all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) its joint ventures to incur indebtedness or grant certain liens. The credit facility also contains covenants, which, among other things, require the Partnership to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. The Partnership was in compliance with the debt covenants contained in credit facility for the years ended December 31, 2008 and 2007. The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls the Partnership’s general partner, the lenders under the Partnership’s credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under the Partnership’s credit facility if it is deemed to have a material adverse effect on the - 91 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Partnership. Any event of default and corresponding acceleration of outstanding balances under the Partnership’s credit facility could require the Partnership to refinance such indebtedness on unfavorable terms and would have a material adverse effect on the Partnership’s financial condition and results of operations as well as its ability to make distributions to unitholders. On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made or required under the term loan through December 31, 2008. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Partnership must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross- defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults. Draws made under the Partnership’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Partnership’s credit facility have ranged from a low of $225,000 to a high of $319,100. As of December 31, 2008, the Partnership had $29,880 available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility. In connection with the Partnership’s Stanolind asset acquisition on January 22, 2008, the Partnership borrowed approximately $6,000 under its revolving credit facility. In connection with the Partnership’s Monarch acquisition on October 2, 2007, the Partnership borrowed approximately $3,900 under its revolving credit facility. In connection with the Partnership’s Mega Lubricants acquisition on June 13, 2007, the Partnership borrowed approximately $4,600 under its revolving credit facility. In connection with the Partnership’s Woodlawn acquisition on May 2, 2007, the Partnership borrowed approximately $33,000 under its revolving credit facility. The Partnership paid cash interest in the amount of $18,744, $17,253 and $12,426 for the years ended December 31, 2008, 2007 and 2006 respectively. Capitalized interest was $1,296, $2,483 and $1,546 for the years ended December 31, 2008, 2007 and 2006 respectively. (13) INTEREST RATE CASH FLOW HEDGES The Partnership has entered into several cash flow hedge agreements with an aggregate notional amount of $235,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. The Partnership designated these swap agreements as cash flow hedges. Under these swap agreements, the Partnership pays a fixed rate of interest and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because these swaps are designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of these hedges, these swaps were identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and these swaps remain equal. This condition results in a 100% effective swap for the following hedges: Date of Hedge October 2008 January 2008 September 2007 Notional Amount $40,000 $25,000 $25,000 Fixed Rate 2.820% 3.400% 4.605% Maturity Date October 2010 January 2010 September 2010 - 92 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) November 2006 March 2006 $40,000 $75,000 4.820% 5.250% December 2009 November 2010 In December 2006, the Partnership entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006, therefore, hedge accounting was not utilized. The swap has been recorded at fair value at December 31, 2008 with an offset to current operations. During the year ended December 31, 2008, the Partnership recognized increases in interest expense of $3,416 related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps. The total fair value of the interest rate swaps agreement was a liability of $10,780 and $4,677 at December 31, 2008 and 2007. The fair value of derivative liabilities is as follows: December 31, 2008 December 31, 2007 Fair value of derivative liabilities — current............................................... Fair value of derivative liabilities — long term.......................................... Net fair value of derivatives ........................................................................ $ (6,478) (4,302) $ (10,780) $ (1,241) (3,436) $ (4,677) (14) RELATED PARTY TRANSACTIONS Included in the consolidated financial statements are various related party transactions and balances primarily with 1) Martin Resource Management and affiliates, and 2) Waskom. Related party transactions include sales and purchases of products and services between the Partnership and these related entities as well as payroll and associated costs and allocation of overhead. The impact of these related party transactions is reflected in the consolidated financial statement as follows: Revenues: Terminalling and storage........................................................... $ 18,362 24,956 Marine transportation ................................................................ $ 11,816 23,729 $ 8,926 15,319 2008 2007 2006 Product sales: Natural gas services............................................................ Sulfur services .................................................................... Terminalling and storage ................................................... 4,024 22,631 49 26,704 $ 70,022 3,206 4,326 45 7,577 $ 43,122 1,303 24 59 1,386 $ 25,631 Costs and expenses: Cost of products sold: Natural gas services............................................................ Sulfur services .................................................................... Terminalling and storage.................................................... $ 92,322 13,282 533 $ 106,137 $ 62,686 13,992 — $ 76,678 $ 52,030 11,913 1 $ 63,944 Expenses: Operating expenses Marine transportation ......................................................... Natural gas services............................................................ Sulfur services .................................................................... Terminalling and storage.................................................... $ 22,586 1,625 3,737 9,713 $ 37,661 $ 20,891 1,538 1,234 5,328 $ 28,991 $ 20,051 1,560 928 3,931 $ 26,470 - 93 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Selling, general and administrative: Natural gas services............................................................ Sulfur services .................................................................... Terminalling and storage.................................................... Indirect overhead allocation, net of reimbursement ........... 880 2,508 — 2,896 $ 6,284 927 1,770 41 1,351 $ 4,089 773 1,714 74 1,305 $ 3,866 (15) FINANCIAL INSTRUMENTS Statement of Financial Accounting Standards No. 107, Disclosures about Fair Value of Financial Instruments, requires that the Partnership disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for the Partnership’s financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument: (cid:2) Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable and due from/to affiliates -- The carrying amounts approximate fair value because of the short maturity of these instruments. (cid:2) Long-term debt including current installments -- The carrying amount of the revolving and term loan facilities approximates fair value due to the debt having a variable interest rate. (16) COMMODITY CASH FLOW HEDGES The Partnership is exposed to market risks associated with commodity prices, counterparty credit and interest rates. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. In addition, the Partnership is focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership uses derivatives to manage the risk of commodity price fluctuations. Additionally, the Partnership manages interest rate exposure by targeting a ratio of fixed and floating interest rates it deems prudent and using hedges to attain that ratio. In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income until such time as the hedged item is recognized in earnings. The Partnership has adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, the Partnership has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity. The components of gain/loss on derivatives qualifying for hedge accounting and those that do not qualify for hedge accounting are included in the revenue of the hedged item in the Consolidated Statements of Operations for the year ended December 31, 2008, 2007 and 2006 as follows: Change in fair value of derivatives that do not qualify for hedge accounting and settlements of maturing hedges .............................................................................. $ 1,222 $ (3,129) $ 1,117 December 31, 2007 2006 2008 - 94 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Ineffective portion of derivatives qualifying for hedge accounting ....................... 2008 (224) December 31, 2007 (586) 2006 (2) Gain (loss) of derivatives in the Consolidated Statement of Operations ................ $ 998 $ (3,715) $ 1,115 The fair value of derivative assets and liabilities are as follows: Fair value of derivative assets — current........................................ Fair value of derivative assets — long term ................................... Fair value of derivative liabilities — current .................................. Fair value of derivative liabilities — long term .............................. Net fair value of derivatives............................................................ December 31, 2008 2007 $ 3,623 1,469 — — $ 5,092 $ 235 — (3,261) (2,140) $ (5,166) Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2008 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of December 31, 2008, the remaining term of the contracts extend no later than December 2010, with no single contract longer than one year. The Partnership’s counterparties to the derivative contracts include Shell Energy North America (US) L.P., Morgan Stanley Capital Group Inc. and Wachovia Bank. For the period ended December 31, 2008, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in accumulated other comprehensive income as a component of equity since the Partnership has designated a portion of its derivative instruments as hedges as of December 31, 2008. Transaction Type Total Volume Per Month Mark to Market Derivatives:: December 31, 2008 Pricing Terms Remaining Terms of Contracts Fair Value Crude Oil Swap 3,000 BBL Fixed price of $69.08 settled against WTI NYMEX average monthly closings Crude Oil Swap 3,000 BBL Fixed price of $70.90 settled against WTI NYMEX average monthly closings Crude Oil Swap 3,000 BBL Fixed price of $72.25 settled against WTI NYMEX average monthly closings Crude Oil Swap 1,000 BBL Fixed price of $104.80 settled against WTI NYMEX average monthly closings Total swaps not designated as cash flow hedges Cash Flow Hedges: Natural Gas swap 30,000 Fixed price of $9.025 settled against MMBTU Inside Ferc Columbia Gulf daily average Crude Oil Swap 1,000 BBL Fixed price of $70.45 settled against WTI NYMEX average monthly closings January 2009 to December 2009 January 2009 to December 2009 January 2010 to December 2010 January 2010 to December 2010 January 2009 to December 2009 January 2009 to December 2009 Natural Gasoline 2,000 BBL Fixed price of $86.42 settled against Mt. January 2009 to - 95 - 565 628 300 453 $ 1,946 1,033 204 1,193 MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Swap Belvieu Non-TET natural gasoline average monthly postings. December 2009 Crude Oil Swap 2,000 BBL Fixed price of $69.15 settled against WTI NYMEX average monthly closings Natural Gasoline Swap 1,000 BBL Fixed price of $94.14 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings January 2010 to December 2010 January 2010 to December 2010 Total swaps designated as cash flow hedges Total net fair value of derivatives 132 584 $ 3,146 $ 5,092 On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, and has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Partnership has incurred no losses associated with the counterparty non-performance on derivative contracts. The Partnership is exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales activities. The Partnership’s gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (“POL”) and percent-of- proceeds (“POP”) basis. The Partnership has entered into hedging transactions through 2010 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas, and natural gasoline. In October 2008, the Partnership elected to discontinue hedge accounting treatment for certain crude oil derivative contracts. The impact to the Consolidated Statement of Operations was a mark to market gain of $1,790 for the year ended December 31, 2008. In December 2008, the Partnership terminated three commodity swap agreements resulting in a cash receipt from the counterparty of $1,935. These swap agreements were accounted for as cash flow hedges. As a result of the termination, a gain of $400 was recorded to the Partnership’s Consolidated Statement of Operations for the year ended December 31, 2008. As a result of declining commodity prices, the Partnership determined that continued reporting of losses in accumulated other comprehensive income (“AOCI”) for certain commodity hedges would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods. Accordingly, the calculated loss of $2,608 was immediately classified into 2008 earnings. The remaining deferred gains of $1,534 and deferred losses of $116 pertaining to the above commodity hedges will remain in AOCI and are expected to be reclassified into earnings in the same period that the forecasted hedge transaction is reported in earnings. Based on estimated volumes, as of December 31, 2008, the Partnership had hedged approximately 47% and 21% of its commodity risk by volume for 2009, and 2010, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements. - 96 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Natural Gas Commodity Hedged Year 2009 2009 Condensate & Natural Gasoline 2009 ENatural Gasoline 2009 2009 2010 Condensate 2010 Natural Gasoline 2010 Condensate 2010 Natural Gasoline Condensate Natural Gasoline Hedging Arrangements in Place As of December 31, 2008 Volume Type of Derivative 30,000 MMBTU/Month Natural Gas Swap ($9.025) Crude Oil Swap ($69.08) 3,000 BBL/Month Crude Oil Swap ($70.90) 3,000 BBL/Month Crude Oil Swap ($70.45) 1,000 BBL/Month Natural Gasoline Swap ($86.42) 2,000 BBL/Month Crude Oil Swap ($69.15) 2,000 BBL/Month Crude Oil Swap ($72.25) 3,000 BBL/Month Crude Oil Swap ($104.80) 1,000 BBL/Month Natural Gasoline Swap ($94.14) Mt. Belvieu (Non-TET) 1,000 BBL/Month Basis Reference Columbia Gulf NYMEX NYMEX NYMEX Mt. Belvieu (Non-TET) NYMEX NYMEX NYMEX The Partnership’s principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of the Partnership’s natural gas and NGL sales are made at market-based prices. The Partnership’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Partnership. Impact of Cash Flow Hedges Crude Oil For the years ended December 31, 2008, 2007 and 2006, net gains and losses on swap hedge contracts increased crude revenue by $1,745, decreased crude revenue by $3,374 and increased crude revenue by $76, respectively. As of December 31, 2008 an unrealized derivative fair value gain of $842, related to current and terminated cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). Fair value gains of $197, $22 and $623 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at December 31, 2008 adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above. Natural Gas For the years ended December 31, 2008, 2007 and 2006, net gains and losses on swap hedge contracts decreased gas revenue by $431 and increased gas revenue by $180 and $1,097, respectively. As of December 31, 2008 an unrealized derivative fair value gain of $1,033 related to cash flow hedges of natural gas was recorded in other comprehensive income (loss). This fair value gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above. Natural Gas Liquids For the years ended December 31, 2008, 2007 and 2006, net losses on swap hedge contracts decreased liquids revenue by $316, $521 and $58, respectively. As of December 31, 2008, an unrealized derivative fair value gain of $2,669 related to current and terminated cash flow hedges of natural gas liquids price risk was recorded in other comprehensive income (loss). Fair value gains of $1,193, $584 and $892 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at December 31, 2008 adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above. - 97 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) (17) PARTNERS’ CAPITAL As of December 31, 2008, partners’ capital consists of 13,688,152 common limited partner units, representing a 92.3% partnership interest, 850,674 subordinated limited partner units, representing a 5.7% partnership interest and a 2% general partner interest. Martin Resource Management through a subsidiary, owned an approximate 34.9% limited partnership interest consisting of 4,334,143 common limited partner units and 850,674 subordinated limited partner units and a 2% general partner interest. The Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts. Distributions of Available Cash The Partnership distributes all of its Available Cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Subordination Period During the subordination period (defined in the Partnership Agreement), the common units have the right to receive distributions of available cash in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The subordination period ends on the first day of any quarter beginning after September 30, 2009, when certain financial tests (defined in the Partnership Agreement) are met. Additionally, a portion of the subordinated units may convert earlier into common units on a one-for-one basis if additional financial tests (defined in the Partnership Agreement) are met. The partnership agreement provides that before the end of the subordination period, a portion of the subordinated units may convert into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after: (cid:2) (cid:2) (cid:2) (cid:2) September 30, 2005 with respect to 20% of the subordinated units; September 30, 2006 with respect to 20% of the subordinated units; September 30, 2007 with respect to 20% of the subordinated units; September 30, 2008 with respect to 20% of the subordinated units; As a result of achieving the defined financial test, 850,672 subordinated units representing 20% of the total originally issued subordinated units were converted into common units on each of November 14, 2008, 2007, 2006 and 2005. A total of 3,402,688 subordinated units representing 80% of the total originally issued subordinated units have been converted into common units as of December 31, 2008. When the subordination period ends, any remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. (18) HURRICANE DAMAGE During the third quarter of 2008, several of the Partnership’s facilities in the Gulf of Mexico were in the path of two major hurricanes, Hurricane Gustav and Hurricane Ike. Physical damage to the Partnership’s assets - 98 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a deductible. Losses incurred as a result of a single hurricane (an “occurrence”) are limited to a maximum aggregate deductible of $250 for flood damage and $1,000 minimum plus 2% of total insured value at each location for wind damage. The Partnership’s total flood coverage is $15,000 and total wind coverage is $100,000. The most significant damage to the Partnership’s assets was sustained at the Neches location. Property damage also occurred at the Partnership’s Galveston, Sabine Pass, Intracoastal City, Cameron East, Cameron West, Freeport, Venice, Port Fourchon, Stanolind, Mont Belvieu, and Spindletop locations. The Partnership performed a damage analysis and has estimated its non-cash charge as $1,269 for all locations which is equal to the net-book value of the damaged assets. A receivable of $4,351 has been recorded for the expected insurance recovery equal to the impairment charge and for all expenditures related to water damage less the fore mentioned deductible. This receivable was reduced by insurance proceeds received of $1,375. These insurance proceeds may exceed net book value of the Partnership’s assets determined to be impaired, which will result in the recognition of a gain equal to the amount of the excess. No net gain or loss has been recognized from the impairment of these damaged assets at December 31, 2008. Any gain or loss will be recognized after the full amount of insurance proceeds are received. The Partnership recognized hurricane costs of $1,461 for the year ended December 31, 2008, which approximates the Partnership’s hurricane deductibles under its applicable insurance policies, incurred as a result of Hurricanes Gustav and Ike for the year ended December 31, 2008. The actual hurricane cost payments for the year ended December 31, 2008 were $949. Insurance proceeds received as a result of the claims from damages incurred during Hurricanes Katrina and Rita in 2005 exceeded net book value of the Partnership’s assets determined to be impaired. During 2006, the Partnership received insurance proceeds of $4,812 for this involuntary conversion of assets, which resulted in a gain of $3,125 which is reported in other operating income. (19) INCOME TAXES The operations of a partnership are generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. The net tax basis in the Partnership’s assets and liabilities is less than the reported amounts on the financial statements by approximately $3.9 million as of December 31, 2008 and more than the reported amounts on the financial statements by approximately $35.4 million as of December 31, 2007. Effective January 1, 2007, the Partnership became subject to the Texas margin tax as described below. Our subsidiary, Woodlawn, is subject to income taxes due to its corporate structure. Current income taxes related to the operations of this subsidiary were $239 and $118 for the years ended December 31, 2008 and 2007, respectively. In connection with the Woodlawn acquisition, the Partnership also established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment. A deferred tax benefit related to these basis differences of $277 and $149 was recorded for the years ended December 31, 2008 and 2007, respectively, and a deferred tax liability of $8,538 and $8,815 related to the basis differences existed at December 31, 2008 and 2007, respectively. As a result of its acquisition of Prism Gas, the Partnership assumed a current tax liability of $6.3 million as a result of a tax event triggered by the transfer of the ownership of the assets of Prism Gas in 2005 from a corporate to a partnership structure through the partial liquidation of the corporation. This liability was paid in 2006. The final liquidation of this corporate entity was completed on November 15, 2006. Additional federal and state income taxes of $173 resulting from the liquidation were recorded in income tax expense for the year ended December 31, 2007. On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Partnership has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change was immaterial. The impact of the change in deferred tax assets does not have a material impact on tax expense. State income taxes attributable to the Texas margin - 99 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) tax of $749 and $538 were recorded in income tax expense for the years ended December 31, 2008 and 2007, respectively. The Partnership was not subject to income taxes prior to January 1, 2007. In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Partnership adopted FIN 48 effective January 1, 2007. There was no impact to the Partnership’s financial statements as a result of adopting FIN 48. The components of income tax expense (benefit) from operations recorded for the years ended December 31, 2008 and 2007 are as follows: Current: Federal ....................................................................... State ........................................................................... Deferred: Federal ....................................................................... (20) BUSINESS SEGMENTS 2008 2007 $ 239 749 988 $ 274 519 793 (277) $ 711 (149) $ 644 The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions. The accounting policies of the operating segments are the same as those described in Note 2 of the notes to consolidated financial statements. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense. Operating Revenues Intersegment Eliminations Operating Revenues After Eliminations Depreciation and Amortization Operating Income (Loss) after Eliminations Capital Expenditures Year ended December 31, 2008: Terminalling and storage ............... Natural gas services ....................... Marine transportation .................... Sulfur services ............................... Indirect selling, general, and $ 90,474 679,375 80,059 372,987 $ (4,189) — (3,710) (1,038) $ 86,285 679,375 76,349 371,949 $ 9,272 4,067 12,128 5,751 $ 8,626 3,725 5,570 37,180 administrative ............................ — — — — (5,510) Total........................................... $ 1,222,895 $ (8,937) $ 1,213,958 $ 31,218 $ 49,591 Year ended December 31, 2007: Terminalling and storage ............... Natural gas services ....................... Marine transportation .................... Sulfur services ............................... Indirect selling, general, and $ 59,790 515,992 63,533 131,602 $ (865) — (3,954) (276) $ 58,925 515,992 59,579 131,326 $ 6,358 3,252 8,819 5,013 $ 10,273 4,492 4,270 13,040 administrative ............................ — — — — (3,199) Total........................................... $ 770,917 $ (5,095) $ 765,822 $ 23,442 $ 28,876 $ 24,958 9,565 53,562 6,884 — $ 94,969 $ 26,023 4,090 37,562 14,489 — $ 82,164 Year ended December 31, 2006: Terminalling and storage ............... Natural gas services ....................... $ 36,606 389,735 $ (389) — $ 36,217 389,735 $ 4,700 1,667 $ 12,504 4,239 $ 13,371 5,552 - 100 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Operating Revenues 50,174 102,646 Intersegment Eliminations (2,339) (49) Operating Revenues After Eliminations 47,835 102,597 Depreciation and Amortization 6,609 4,621 Operating Income (Loss) after Eliminations 6,411 6,708 Marine transportation .................... Sulfur services ............................... Indirect selling, general, and administrative ............................ — — — — (3,253) Total........................................... $ 579,161 $ (2,777) $ 576,384 $ 17,597 $ 26,609 Capital Expenditures 18,840 28,589 — $ 66,352 The following table reconciles operating income to net income: Operating income............................................................. Equity in earnings of unconsolidated entities .................. Interest expense ............................................................... Debt prepayment premium .............................................. Other, net ......................................................................... Income taxes .................................................................... Net income s............................................................. 2008 $ 49,591 13,224 (19,777) — 483 (711) $ 42,810 Year Ended December 31, 2007 $ 28,876 10,941 (14,533) — 299 (644) $ 24,939 2006 $ 26,609 8,547 (12,466) (1,160) 713 — $ 22,243 Revenues from one customer in the Natural gas services segment were $103,424, $66,989, and $60,870 for the years ended December 31, 2008, 2007 and 2006, respectively. Total assets by segment at December 31, 2008, 2007 and 2006 are as follows: Total assets: Terminalling and storage ................................................... Natural gas services ........................................................... Marine transportation ........................................................ Sulfur services ................................................................... Total assets...................................................................... $ 157,598 232,161 150,733 128,424 $ 668,916 $ 126,575 268,230 107,081 121,691 $ 623,577 $ 89,354 184,464 77,668 105,975 $ 457,461 2008 2007 2006 Investments in unconsolidated entities totaled $79,843 and $75,690 at December 31, 2008 and 2007, respectively, and are included in the natural gas services segment. (21) QUARTERLY FINANCIAL INFORMATION CONSOLIDATED QUARTERLY INCOME STATEMENT INFORMATION First Quarter (Dollar in thousands, except per unit amounts) Fourth Quarter Second Quarter (Unaudited) Third Quarter 2008 Revenues....................................................................... Operating Income ......................................................... Equity in earnings of unconsolidated entities ............... Net income.................................................................... Net income per limited partner unit .............................. $313,016 9,008 3,510 8,017 $ 0.51 $308,143 4,295 4,372 4,317 $ 0.25 $364,386 15,420 3,503 13,747 $ 0.88 $228,413 (1) 20,868 (2) 1,839 (3) 16,729(2) $ 1.08 First Quarter (Dollar in thousands, except per unit amounts) Fourth Quarter Third Quarter Second Quarter 2007 Revenues....................................................................... $155,796 $162,314 $184,850 $262,862(4) - 101 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Operating Income ......................................................... Equity in earnings of unconsolidated entities ............... Net income.................................................................... Net income per limited partner unit .............................. 7,600 2,050 5,803 $ 0.42 6,167 2,418 5,927 $ 0.41 6,565 2,736 5,503 $ 0.35 8,544 3,737 7,706 $ 0.49 First Quarter (Dollar in thousands, except per unit amounts) Fourth Quarter Second Quarter Third Quarter 2006 Revenues........................................................................................... Operating Income ............................................................................. Equity in earnings of unconsolidated entities ................................... Net income........................................................................................ Net income per limited partner unit .............................. $146,822 5,884 2,412 4,287 $ 0.33 $133,052 5,874 2,310 5,248 $ 0.40 $147,505 4,720 2,720 4,329 $ 0.32 $149,005 10,131(5) 1,105(6) 8,378(5) $ 0.64 (1) Decreased revenues were primarily related to NGL and Sulfur Services. NGL revenues decreased because of a $1.09 decrease in average sales price. Sulfur Services decreased because of a $465.50 L/T price decrease on molten sulfur. (2) Relates to Sulfur Services segment due to certain Sulfur contract pricing provisions which allowed for increased margins during a falling price environment. (3) Decrease in equity in earnings of unconsolidated entities due to falling commodity prices. (4) Increased total revenues of $78,012 were due primarily to a 35% increase in NGL sales volumes in the fourth quarter and an increase in the NGL average sales price. (5) Includes recognition of gain on involuntary conversion of assets of $2,272 due to Hurricanes Katrina and Rita. (6) Decrease in equity in earnings of unconsolidated entities due a shutdown of the Waskom plant in the fourth quarter. (22) COMMITMENTS AND CONTINGENCIES As a result of a routine inspection by the U.S. Coast Guard of the Partnership’s tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, the Partnership has been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two employees of Martin Resource Management who provide services to the Partnership were served with grand jury subpoenas during the fourth quarter of 2007. The Partnership is cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against the Partnership. In addition to the foregoing, 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 May 2, 2008, the Partnership received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management. The Plaintiff and the Defendant are executive officers of Martin Resource Management and the general partner of the Partnership, the Defendant is a director of both Martin Resource Management and the general partner of the Partnership, and the Plaintiff is a director of Martin Resource Management. The lawsuit alleges that the Defendant breached a settlement agreement with the Plaintiff concerning certain Martin Resource Management matters and that the Defendant breached fiduciary duties allegedly owed to the Plaintiff in connection with their respective ownership and other positions with Martin Resource Management. The Partnership is not a party to the lawsuit and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations or (iii) against the Defendant with respect to his service as an officer or director of the general partner of the Partnership. - 102 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of the general partner of the Partnership. The Partnership is not a party to this lawsuit, and it does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations or (iii) against the MRMC Director Defendants or Other MRMC Defendants with respect to their service to the Partnership. The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares. The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, and who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached the fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, it should be noted that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s recent activities, which the Board of Directors of Martin Resource Management determined were detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of the general partner of the Partnership. The position on the board of directors of the general partner of the Partnership vacated by the Plaintiff will be filled in accordance with the existing procedures for replacement of a departing director utilizing the Nominations Committee of the board of directors of the general partner of the Partnership. (23) CONSOLIDATING FINANCIAL STATEMENTS In connection with the Partnership’s filing of a shelf registration statement on Form S-3 with the Securities and Exchange Commission (the “Registration Statement”), Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, may issue unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time under the registration statement. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities under the Registration - 103 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Statement which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. The Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has no independent assets or operations, the guarantees are full and unconditional and the other subsidiary of the Partnership is minor. There are no significant restrictions on the ability of the Partnership or the Operating Partnership to obtain funds from any of their respective subsidiaries by dividend or loan. - 104 - 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 Rule 13a-15(e) of the Exchange Act) as of December 31, 2008. 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, 2008. (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, 2008. The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report appearing on page 71. (c) Changes in internal controls. The following changes in our internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. On October 24, 2008, we were advised by our independent registered public accounting firm, KPMG LLP, of the discovery of an error in the failure to record in the statement of operations the ineffective portion of certain commodity price swaps we had in place which did not qualify for hedge accounting at September 30, 2008. This error resulted from our failure to consult with our third party derivatives specialist which is a component of our internal control process. We have corrected this error, which resulted in recording additional earnings of $1.7 million before taxes in the third quarter of 2008. No results of operations for prior periods were affected by this error. We believe that our control procedures over recording the fair value of outstanding derivatives were not operating effectively at September 30, 2008, and that this deficiency in internal control over financial reporting at September 30, 2008 was a material weakness. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. This control deficiency could result in a misstatement to our annual or interim financial statements that would not be prevented or detected. We have remediated this material weakness through the implementation of procedures that require the quarterly consultation with and review by our third party advisor with respect to our hedging activity and accounting for our derivative instruments.(cid:2) Item 9B. Other Information Indemnification Agreements. On November 6, 2008, we and Martin Midstream GP entered into an Indemnification Agreement with each of the directors of our general partner, Ruben S. Martin, III, John P. Gaylord, Howard Hackney and C. Scott Massey. Each Indemnification Agreement requires us and our general partner to indemnify each such indemnitee to the fullest extent permitted by law, from and against all liabilities and expenses incurred in connection with any proceeding against such indemnitee. Each Indemnification Agreement also provides for the advancement of expenses incurred by such indemnitee in connection with any proceeding against - 105 - such indemnitee with respect to which such indemnitee may be entitled to indemnification by us or our general partner. The foregoing description of each Indemnification Agreement is qualified in its entirety by reference to the form of Indemnification Agreement included as Exhibit 10.28 to this Annual Report, which is incorporated herein by reference. Certain Other Information. On May 2, 2008, we received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management. The Plaintiff is a director of Martin Resource Management and an executive officer of our general partner. The Defendant is a director and executive officer of Martin Resource Management and our general partner. The lawsuit alleges that the Defendant breached a settlement agreement with the Plaintiff concerning certain Martin Resource Management matters and that the Defendant breached fiduciary duties allegedly owed to the Plaintiff in connection with their respective ownership and other positions with Martin Resource Management. We are not a party to the lawsuit and the lawsuit does not assert any claims (i) against us, (ii) concerning our governance or operations or (iii) against the Defendant with respect to his service as an officer or director of our general partner On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of our general partner. We are not a party to this lawsuit, and it does not assert any claims (i) against us, (ii) concerning our governance or operations or (iii) against the MRMC Director Defendants or Other MRMC Defendants with respect to their service to us. The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares. The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, and who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached the fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, it should be noted that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. On September 24, 2008, Martin Resource Management removed the Plaintiff as a director of our general partner. Such action was taken as a result of the collective effect of the Plaintiff’s recent activities, which the Board of Directors of Martin Resource Management determined were detrimental to both Martin Resource Management and us. The Plaintiff does not serve on any committees of the board of directors of our general partner. The position on the board of directors of our general partner will be filled in accordance with the existing procedures for - 106 - replacement of a departing director utilizing the Nominations Committee of the board of directors of our general partner. Item 10. Directors and Executive Officers of the Registrant Management of Martin Midstream Partners L.P. PART III Martin Midstream GP LLC, as our general partner, manages our operations and activities on our behalf. Our general partner was not elected by our unitholders and will not be subject to re-election in the future. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. However, whenever possible, our general partner seeks to provide that our indebtedness or other obligations are non-recourse to our general partner. Three directors of our general partner serve on a conflicts committee to review specific matters that the directors believe may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by NASDAQ and applicable securities laws. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, the members of the conflicts committee also serve on an audit committee that reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. The members of the conflicts committee also serve on the compensation committee, which oversees compensation decisions for the officers of our general partner as well as the compensation plans described below. The current members of our conflicts committee, audit committee, nominating committee and compensation committee are our outside directors, John P. Gaylord, C. Scott Massey and Howard Hackney, all of whom meet the independence standards established by NASDAQ. We are managed and operated by the directors and officers of our general partner. All of our operational personnel are employees of Martin Resource Management. All of the officers of our general partner will spend a substantial amount of time managing the business and affairs of Martin Resource Management and its other affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Martin Resource Management. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. Directors and Executive Officers of Martin Midstream GP LLC The following table shows information for the directors and executive officers of our general partner. Executive officers and directors are elected for one-year terms. Name Age Position with the General Partner Ruben S. Martin Robert D. Bondurant Donald R. Neumeyer Wesley M. Skelton Randy Tauscher Scott D. Martin Chris Booth John P. Gaylord C. Scott Massey Howard Hackney 57 50 61 61 43 43 39 48 56 69 President, Chief Executive Officer and Director Executive Vice President and Chief Financial Officer Executive Vice President and Chief Operating Officer Executive Vice President, Chief Administrative Officer and Controller Executive Vice President Executive Vice President Vice President, General Counsel and Secretary Director Director Director - 107 - 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 and Scott D. Martin, see below, are brothers. Mr. Martin holds a bachelor of science degree in industrial management from the University of Arkansas. Robert D. Bondurant serves as Executive Vice President and Chief Financial Officer of our general partner. Mr. Bondurant has served in such capacities since June 2002. Mr. Bondurant joined Martin Resource Management in 1983 as Controller and subsequently was appointed Chief Financial Officer and a member of its Board of Directors in 1990. Mr. Bondurant served in the audit department at Peat Marwick, Mitchell and Co from 1980 to 1983. Mr. Bondurant holds a bachelor of business administration degree in accounting from Texas A&M University and is a Certified Public Accountant, licensed in the state of Texas. Donald R. Neumeyer serves as Executive Vice President and Chief Operating Officer of our general partner. Mr. Neumeyer has served in such capacities since June 2002. Mr. Neumeyer joined Martin Resource Management in March of 1982 as an operations manager. He has served as Vice President of Operations and Chief Operating Officer since 1983 and as a Director since 1990. From 1978 to 1982 Mr. Neumeyer was employed by Crystal Oil Company of Shreveport, Louisiana as Vice President of Marketing, Refining and Gas Processing. From 1970 to 1978 Mr. Neumeyer was employed by Mobil Oil Corporation in various capacities within its pipeline, crude oil, and gas liquid operations. Mr. Neumeyer holds a bachelor of science in mechanical engineering from Southern Methodist University in Dallas and is a registered professional engineer in the state of Texas. Wesley M. Skelton serves as Executive Vice President, Controller and Chief Administrative Officer of our general partner. Mr. Skelton has served in such capacities since June 2002. Mr. Skelton joined Martin Resource Management in 1981 and has served as Chief Administrative Officer since 1981 and a Director since 1990. Prior to joining Martin Resource Management, Mr. Skelton served as Treasurer of First Federal Savings & Loan, Marshall, Texas from January 1977 through January 1981 and was employed by Peat Marwick, Mitchell & Co. from August 1973 through January 1977. Mr. Skelton holds a bachelor of business administration degree from the University of Texas, and is a Certified Public Accountant licensed in the state of Texas. Scott D. Martin serves as Executive Vice President of our general partner. He served as a General Manager, Marine Operations of our general partner from June 2002 until February 2006, at which time he was appointed as Executive Vice President of our general partner. He served as a member of the Board of Directors of our general partner from 2002 until September 2008. Mr. Martin has served as a Director of Martin Resource Management since 1990. He has held a variety of positions in marketing, transportation, terminalling, finance, operations and business development with Martin Resource Management since 1988. Mr. Martin and Ruben S. Martin, see above, are brothers. Mr. Martin holds a bachelor of science degree in business administration from University of Arkansas, where he previously served as a member of the Walton Business School advisory board. Randy Tauscher serves as Executive Vice President of our general partner. Mr. Tauscher has served in this capacity since November 1, 2007. 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. Chris Booth serves as Vice-President, General Counsel and Secretary of our general partner. Mr. Booth has served in the capacities of Vice President and General Counsel since February 2006 and in the capacity of Secretary since November 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 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. John P. Gaylord serves as a member of the Board of Directors of our general partner. Mr. Gaylord has served as a Director since June 2002. Mr. Gaylord has served as the President of Jacintoport Terminal Company since 1992. He originally joined Jacintoport Terminal Company when it was founded in 1989 as Vice President of Finance. Jacintoport Terminal Company is the general partner of Chartco Terminal L.P. which has terminalling and storage - 108 - operations in Houston, Texas. Mr. Gaylord holds a bachelor of arts degree from Texas Christian University and a master of business administration degree from Southern Methodist University. C. Scott Massey serves as a member of the Board of Directors of our general partner. Mr. Massey has served as a Director since June 2002. Mr. Massey has been self employed as a Certified Public Accountant since 1998. From 1977 to 1998, Mr. Massey worked for KPMG Peat Marwick, LLP in various positions, including, most recently, as a Partner in the firm’s Tax Practice — Energy, Real Estate, Timber from 1986 to 1998. Mr. Massey received a bachelor of business administration degree from the University of Texas at Austin and a juris doctor degree from the University of Houston. Mr. Massey is a Certified Public Accountant, licensed in the states of Louisiana and Texas. Howard Hackney serves as a member of the Board of Directors of our general partner. Mr. Hackney has served as a Director since May 2005. Mr. Hackney currently serves as a director of Texas Bank and Trust of Longview, Texas and Federal Home Loan Bank of Dallas, Texas, where he is the Chairman of the Audit Committee and a member of the Executive and Risk Management Committees. Mr. Hackney from time to time is an adjunct faculty member at LeTourneau University Business School in finance and management. His past experience includes service as the President of Texas Bank and Trust of Longview, Texas, President of Bank One of Longview, Texas, President and a director of Merchant and Planters National Bank of Sherman, Texas and Executive Vice President and a director of Capital National Bank of Houston, Texas. Mr. Hackney received a BBA and MBA from Southern Methodist University. Independence of Directors Messrs. Gaylord, Massey and Hackney 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, 2008 to December 31, 2008, the Board of Directors of our general partner held 16 meetings. All directors then in office attended each of these meetings, either in person, by teleconference or by videoconference. Additionally, the Board of Directors undertook action one time during 2008 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, Compensation, Nominating and Conflicts Committees 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 “Governance” section. The current members of the committees, the number of meetings held by each committee from January 1, 2008 to December 31, 2008, and a brief description of the functions performed by each committee are set forth below: Conflicts Committee (4 meetings). The members of the conflicts committee are Messrs. Gaylord (chairman), Massey and Hackney. 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 employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by NASDAQ. 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 (6 meetings). The members of the audit committee are Messrs. Gaylord, Massey (chairman) and Hackney. All of the members, attended all meetings of the audit committee for the period noted above. The - 109 - 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 (5 meetings). The members of the compensation committee are Messrs. Gaylord, Massey and Hackney (chairman). 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 (3 meetings). The members of the nominating committee are Messrs. Gaylord, Massey and Hackney (chairman). The primary responsibility of the nominating committee is to select and recommend nominees for election to the Board of Directors of our general partner. Compensation of Directors Officers of our general partner who also serve as directors will not receive additional compensation. Non- employee directors of our general partner are entitled to receive an annual retainer fee of $35,000. 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. 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 . These restricted common units vest in equal installments of 250 units on January 24, 2009, 2010, 2011 and 2012. On May 3, 2007, 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, 2008, 2009, 2010 and 2011, respectively. On January 24, 2006, 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, 2007, 2008, 2009 and 2010, respectively. Compensation Committee Interlocks and Insider Participation The current members of the compensation committee of our general partner that are identified above were the only persons who served on such committee during 2008. 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. 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 - 110 - 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 “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, officers and beneficial owners of more than 10 percent 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 reports that are filed. Based on our review of copies of such forms and amendments, we believe directors, executive officers and greater than 10% beneficial owners complied with all filing requirements during the year ended December 31, 2008 except as follows: 13 reports on Form 4 following allocations pursuant to a benefit plan of Martin Resource Management were filed late by each of Messrs. Ruben Martin, Scott Martin, Skelton, Neumeyer, Bondurant and Booth. 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 $67.5 million of direct costs and expenses for the twelve months ended December 31, 2008 compared to $53.9 million for the twelve months ended December 31, 2007. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses. 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. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008 , 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. 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 — Agreements — Omnibus Agreement.” Item 11. Executive Compensation Compensation Discussion and Analysis 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. 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. Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. Please see “Item 13. Certain Relationships and Related Transactions — Agreements — Omnibus Agreement” for a discussion of the omnibus agreement. - 111 - The compensation policies and philosophy of Martin Resource Management govern the types and amount of compensation granted each of the named executive officers of our general partner listed in the summary compensation table set forth below (the “Named Executive Officers”). The board of directors and the compensation committee of our general partner do not have responsibility for approving the elements of compensation presented in the tables which follow this discussion. 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 for managerial, administrative and operational support, including compensation of the Named Executive Officers, provided by Martin Resource Management under the omnibus agreement. 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. 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 practices of Martin Resource Management. Ruben S. Martin, the Chief Executive Officer of our general partner, controls Martin Resource Management and has ultimate decision-making authority with respect to compensation of the Named Executive Officers. The following elements of compensation, and Martin Resource Management’s decisions with respect to determinations on payments, will not be subject to approvals by our general partner’s board of directors or its Compensation Committee. Awards under our long-term incentive plan, which to date have consisted only of the grant of restricted common units to the independent directors of our general partner, are approved by the Compensation Committee. Martin Resource Management does not have a separate compensation committee. 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 drive performance and reward contributions in support of the business strategies of Martin Resource Management and its affiliates, including us. During 2008, Martin Resource Management did not use any elements of compensation based on specific performance-based criteria and did not have any other specific performance-based objectives. During 2008, elements of compensation paid to the Named Executive Officers by Martin Resource Management consisted of the following: (cid:2) Annual base salary; (cid:2) Discretionary annual cash awards; (cid:2) Awards pursuant to Martin Resource Management employee benefit plans; and (cid:2) Other compensation, including limited perquisites. With respect to compensation objectives and decisions regarding the Named Executive Officers during 2008, Martin Resource Management takes note of market data for determining relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, various relevant compensation surveys. Martin Resource Management did not consult with any compensation consultants with respect to determining 2008 compensation for any of our named executive officers. The compensation paid by Martin Resource Management to the Named Executive Officers is intended to yield competitive total cash compensation and drive performance in support of our business strategies, as well as the performance of Martin Resource Management and other Martin Resource Management affiliates for which the Named Executive Officers perform services. - 112 - The 2008 equity-based awards under our long-term incentive plan that were given to our independent directors were determined by the Compensation Committee. Any equity-based awards under Martin Resource Management employee benefit plans given to the Named Executive Officers are determined by Mr. Ruben Martin. Martin Midstream Partners L.P. Long-Term Incentive Plan Our general partner has adopted the Martin Midstream Partners L.P. Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform services for us. The long-term incentive plan was amended in January 2006 to clarify the Partnership’s ability to grant restricted common units under the long-term incentive plan and to remove provisions relating to grants of distribution equivalent rights and phantom units. The long-term incentive plan consists of two components, restricted units and unit options. The long-term incentive plan 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 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 long-term incentive plan 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 long-term incentive plan 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 May 5, 2008, 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, 2009, 2010, 2011 and 2012, respectively. On May 3, 2007, 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, 2008, 2009, 2010 and 2011, respectively. On January 24, 2006, we issued 1,000 restricted common units to each of our three independent directors. These - 113 - restricted common units vest in equal installments of 250 units on each of the four anniversaries following the grant date. Unit Options. The long-term incentive plan currently permits the grant of options covering common units. As of March 4, 2009, 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 ownership plan that covers employees who satisfy certain minimum age and service requirements. This employee stock ownership plan is referred to as the “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 ESOP 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 ESOP. Martin Resource Management 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. - 114 - 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 Phantom Stock Plan. Under Martin Resource Management’s phantom stock plan, phantom stock units granted there under have a ten year life and are non-transferable. Each recipient may exercise an election to receive either (cid:2) (cid:2) an equivalent number of shares of Martin Resource Management or cash based on the latest valuation of the shares of common stock of Martin Resource Management held by the ESOP. Any common stock of Martin Resource Management received under this phantom stock plan cannot be pledged or encumbered. The recipient must sign an agreement waiving any voting rights with respect to shares received under this plan. Cash elections are paid in five equal annual installments. A put option, exercisable at the then fair market value of the common stock, is exercisable by the employee in the event Martin Resource Management is sold prior to an employee’s election to receive common stock or cash. 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, car allowances, 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 periods from January 1, 2008 to December 31, 2008, January 1, 2007 to December 31, 2007 and January 1, 2006 to December 31, 2006. Name and Principal Position Year Salary ($) Bonus ($) Total Compensation Ruben S. Martin President and Chief Executive Officer 2008 2007 2006 $73,500 $ - $73,500 $134,271 $ - $134,271 $137,718 $ - $137,718 - 115 - Name and Principal Position Year Salary ($) Bonus ($) Total Compensation Robert D. Bondurant Executive Vice President and Chief Financial Officer 2008 $38,040 $ - $38,040 Donald R. Neumeyer Executive Vice President and Chief Operating Officer 2007 2006 2008 $116,234 $ - $116,234 $105,565 $ - $105,565 $37,283 $ - 2007 $116,170 $ - $37,283 $116,170 Wesley M. Skelton Executive Vice President, Controller and Chief Administrative Officer Randall L. Tauscher Executive Vice President Chris H. Booth Vice President, General Counsel and Secretary 2006 $108,065 $ - $108,065 2008 2007 2006 2008 2007 2006 2008 2007 $108,358 $ - $108,358 $151,936 $ - $151,936 $117,780 $ - $117,780 $300,000 $300,000 $600,000 $ - $ - $ - $ - $ - $ - $77,625 $ - $77,625 $120,938 $ - $120,938 2006 $98,585 $ - $98,585 Director Compensation As a partnership, we are managed by our general partner. The board of directors of our general partner performs for us the functions of a board of directors of a business corporation. We are allocated 100 percent of the director compensation of these board members. Martin Resource Management employees who are a member of the board of directors of our general partner do not receive any additional compensation for serving in such capacity. The following table sets forth the compensation of our board members for the period from January 1, 2008 through December 31, 2008. - 116 - Name Ruben S. Martin John P. Gaylord C. Scott Massey Howard Hackney ____________ Fees Earned Paid in Cash ($) Stock Awards ($)(1) N/A $35,000 $35,000 $35,000 N/A $34,750 $34,750 $34,750 Total ($) N/A $69,750 $69,750 $69,750 (1) On May 5, 2008, 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, 2009, 2010, 2011 and 2012, 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, May 5, 2008, 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. /s/ Howard Hackney Howard Hackney, Committee Chair /s/ John P. Gaylord John P. Gaylord /s/ C. Scott Massey C. Scott Massey 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, 2009 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) Martin Resource Management Corporation(3)................................ Martin Resource LLC(3) ........................ Ruben S. Martin(4)................................. Scott D. Martin(5) ................................. Donald R. Neumeyer.............................. Wesley M. Skelton ................................. Robert D. Bondurant .............................. Chris Booth ............................................ Randall Tauscher.................................... John P. Gaylord(6) ................................. C. Scott Massey(6)(7)............................. Howard Hackney(6) ............................... Kayne Anderson Capital Advisors, L.P.(8) All directors and executive officers as a group (10 persons)(9) ..................... Common Units Beneficially Owned Percentage of Common Units Beneficially Owned(2) Subordinated Units Beneficially Owned Percentage of Subordinated Units Beneficially Owned Percentage of Total Units Beneficially Owned(2) 4,334,143 4,334,143 4,363,543 4,346,931 3,999 3,062 10,787 1,586 6,890 33,000 7,250 3,000 1,499,705 31.7% 31.7% 31.9% 31.8% — — — — — — — — 11.0% 850,674 850,674 850,674 850,674 — — — — — — — — — 4,445,905 32.5% 850,674 100% 100% 100% 100% — — — — — — — — — 100% 35.7% 35.7% 35.9% 35.7% — — — — — — — — 10.3% 36.4% - 117 - ____________ (1) (2) (3) (4) (5) (6) (7) (8) (9) 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. The percent of class shown is less than one percent unless otherwise noted. Martin Resource Management Corporation is the owner of Martin Resource LLC, and as such may be deemed to beneficially own the common and subordinated units held by Martin Resource LLC. The 4,334,143 common units and 850,674 subordinated units beneficially owned by Martin Resource Management Corporation 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. Includes 4,334,143 common units and 850,674 subordinated units beneficially owned by Martin Resource Management Corporation through its ownership of Martin Resource LLC. Ruben S. Martin beneficially owns securities in Martin Resource Management Corporation representing approximately 42.5% of the voting power 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 Corporation. Includes 4,334,143 common units and 850,674 subordinated units beneficially owned by Martin Resource Management Corporation through its ownership of Martin Resource LLC. Scott D. Martin beneficially owns securities in Martin Resource Management Corporation representing approximately 48.5% of the voting power thereof and serves on its Board of Directors. As a result, Scott D. Martin may be deemed to be the beneficial owner of the common units and the subordinated units owned by Martin Resource Management Corporation. On May 5, 2008, we issued 1,000 restricted common units to each of our three independent directors. These restricted common units vest in equal installments of 250 units on January 24, 2009, 2010, 2011 and 2012, respectively. On May 3, 2007, we issued 1,000 restricted common units to each of our three independent directors. These restricted common units vest in equal installments of 250 units on January 24, 2008, 2009, 2010 and 2011, respectively. On January 24, 2006, we issued 1,000 restricted common units to each of our three independent directors. These restricted common units vest in equal installments of 250 units on each of the four anniversaries following the grant date. Mr. Massey may be deemed to be the beneficial owner of 250 common units held by his wife. Based on a Schedule 13G (Amendment No. 4), dated February 11, 2009 filed by Kayne Anderson Capital Advisors, L.P. with the United States Securities and Exchange Commission. The filing is made jointly with Richard A. Kayne. The filers report that they have shared voting power with respect to the 1,499,705 common units. The address of Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067. 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 and subordinated units beneficially owned by Martin Resource Management Corporation as both Ruben S. Martin and Scott D. Martin may be deemed to be the beneficial owners thereof. Martin Resource Management Corporation owns our general partner and, together with our general partner, owns approximately 35.7% of our outstanding limited partner units. The table below sets forth information as of - 118 - March 4, 2009 concerning (i) each person owning beneficially in excess of 5% of common stock of Martin Resource Management Corporation, and (ii) the beneficial common stock ownership of (a) each director of Martin Resource Management Corporation, (b) each executive officer of Martin Resource Management Corporation, and (c) all such executive officers and directors of Martin Resource Management Corporation as a group. Except as indicated, each individual has sole voting and investment power over all shares listed opposite his or her name. Name of Beneficial Owner(1) R.S. Martin Jr. Children’s Trust No. One f/b/o Angela Santi Jones (2) ...................... Martin Resource Management Corporation Employee Stock Ownership Trust (3)..... CNRT LLC (4) ............................................................................................................ Ruben S. Martin III Dynasty Trust (5)......................................................................... SKM Partnership, Ltd. (6) ........................................................................................... Martin Transport, Inc. (7) Ruben S. Martin (3) (4) (7) (8) .................................................................................... Scott D. Martin (3) (6) (7) (9)...................................................................................... Donald R. Neumeyer (10) (11) (12)............................................................................. Wesley M. Skelton (3) (10)(11) (12) ........................................................................... Robert D. Bondurant (10) (11) (12) ............................................................................. Executive officers and directors as a group (5 individuals) _____________ * Represents less than 1.0% Beneficial Ownership of Common Stock Number of Shares Percent of Outstanding 1,278.00 1,922.00 2,266.67 635.00 2,560.00 40.00 4,523.00 5,156.00 116.00 2,030.00 200.00 8,131.00 12.0% 18.1% 21.3% 6.0% 24.1% * 42.5% 48.5% 1.1% 19.0% 1.8% 76.5% (1) (2) (3) (4) (5) 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. Karen Yost is the sole investment trustee and the sole dispositive trustee of the R.S. Martin Jr. Children’s Trust No. One f/b/o Angela Santi Jones and exercises control over the voting of the securities owned by this trust and exercises sole control over the disposition of the securities owned by this trust. As a result, this person may be deemed to be the beneficial owners of the securities held by such trust. Karen Yost is an officer of Martin Resource Management. Ruben S. Martin, Scott D. Martin and Wesley M. Skelton are the co-trustees of the Martin Resource Management Corporation Employee Stock Ownership Trust and exercise shared control over the voting and disposition of the securities owned by this trust. As a result, these persons may be deemed to be the beneficial owners of the securities held by such trust; thus, the number of shares of common stock reported herein as beneficially owned by such individuals includes the 1,922 shares owned by such trust. Mr. Skelton disclaims beneficial ownership of these 1,922 shares. Ruben S. Martin is the beneficial owner of the general partner of CNRT LLC and exercises control over the voting and disposition of the securities owned by this entity. As a result, he 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 2,266.67 shares owned by such entity. 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. Scott D. Martin was the trustee of this trust until he resigned effective February 16, 2009 and was previously shown as the beneficial owner of the securities held by this trust. These 635 shares have been pledged as security to a third party to secure payment for a loan made by such third party. - 119 - (6) (7) (8) (9) Scott D. Martin is the beneficial owner of the general partner of SKM Partnership, Ltd. and exercises control over the voting and disposition of the securities owned by this entity. As a result, he 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 2,560 shares owned by such entity. Ruben S. Martin beneficially owns securities in Martin Resource Management Corporation representing approximately 42.5% of the voting power thereof and serves as its Chairman of the Board and President. Scott D. Martin beneficially owns securities in Martin Resource Management Corporation representing approximately 48.5% of the voting power thereof and serves as an executive officer thereof and as a member of its Board of Directors. Martin Transport, Inc. is a wholly owned subsidiary of Martin Resource Management Corporation. As a result, each of Ruben S. Martin and Scott D. 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 such individuals includes the 40 shares owned by Martin Transport, Inc. Ruben S. Martin directly owns 294.33 shares of common stock. Scott D. Martin directly owns 634 shares of common stock. (10) Messrs. Neumeyer, Skelton and Bondurant have the right to acquire 50, 48 and 140 shares, respectively, by virtue of options issued under Martin Resource Management Corporation’s nonqualified stock option plan. (11) Messrs. Neumeyer, Skelton and Bondurant own securities in Martin Resource Martin Corporation of 16, 10 and 10 shares of common stock, respectively, obtained by the exercise of options issued under Martin Resource Management Corporation’s nonqualified stock option plan. (12) Messrs. Neumeyer, Skelton and Bondurant each own securities in Martin Resource Martin Corporation of 50 restricted common shares representing shares by virtue of restricted stock issued under Martin Resource Management Corporation’s 2007 Long-Term Incentive Plan. The following table sets forth information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2008: Equity Compensation Plan Information Number of securities to be issued upon exercise of outstanding options, Warrants and rights (a) Weighted-average exercise price of outstanding options, warrants and rights (b) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) N/A 0 0 N/A $0 $0 N/A 716,000 716,000 Plan Category Equity compensation plans approved by security holders................. Equity compensation plans not approved by security holders (1)..... Total.................................................................................................... _________________ (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 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. - 120 - On May 3, 2007, we issued 1,000 restricted common units to each of our three independent directors under our long-term incentive plan. These restricted common units vest in equal installments of 250 units on each of the four anniversaries following the grant date. On January 24, 2006, we issued 1,000 restricted common units to each of our three independent directors under our long-term incentive plan. These restricted common units vest in equal installments of 250 units on each of the four anniversaries following the grant date. Item 13. Certain Relationships and Related Transactions Martin Resource Management owns 4,334,143 of our common units and 850,674 subordinated units collectively representing approximately 35.7% of our outstanding limited partnership units. 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, as general partner, to manage and operate us, and Martin Resource Management’s ownership of approximately 35.7% of our outstanding 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 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 ................................................... Operational Stage Distributions of available cash to our general partner ................................... Payments to our general partner and its affiliates ........................................ (cid:2) (cid:2) (cid:2) 4,253,362 subordinated units; (A total 3,402,688 of the original subordinated units issued to Martin Resource Management have been converted into common units on a one-for-one basis since the formation of the Partnership. (850,672 subordinated units were converted on each of November 14, 2005, 2006, 2007 and 2008, respectively). 2% general partner interest; and the incentive distribution rights. 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 distributions of approximately $0.6 million on its 2.0% general partner interest and Martin Resource Management would receive an aggregate annual distribution of approximately $1.7 million on its subordinated units. 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 - 121 - 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 amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. Please read “Agreements — Omnibus Agreement” below. 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. Withdrawal or removal of our general partner................................................ 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 We and Martin Resource Management have entered into various agreements that are not the result of arm’s- length negotiations and consequently may not be as favorable to us as they might have been if we had negotiated them with unaffiliated third parties. Omnibus Agreement We and our general partner are parties to an omnibus agreement with Martin Resource Management 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 (cid:2) (cid:2) (cid:2) providing terminalling and storage services for hydrocarbon products and by-products; providing marine transportation of hydrocarbon products and by-products; distributing NGLs; and (cid:2) manufacturing and selling sulfur-based fertilizer products and other sulfur-related products. This restriction does not apply to: (cid:2) (cid:2) (cid:2) (cid:2) the 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, - 122 - (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas, operating a small crude oil gathering business in Stephens, Arkansas, operating a small lube oil processing business in Smackover, Arkansas, operating an underground NGL storage facility in Arcadia, Louisiana, building and marketing sulfur prillers, developing an underground natural gas storage facility in Arcadia, Louisiana, operating, solely for our account, an NGL truck loading and unloading and pipeline distribution terminal in Mont Belvieu, Texas. 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. Indemnification Provisions. Under the omnibus agreement, Martin Resource Management was obligated to indemnify us for five years after the closing of our initial public offering for: (cid:2) (cid:2) certain potential environmental liabilities associated with the operation of the assets contributed to us, and assets retained, by Martin Resource Management that relate to events or conditions occurring or existing before November 1, 2002; and any payments we were required to make, as a successor in interest to affiliates of Martin Resource Management, under environmental indemnity provisions contained in the contribution agreement associated with the contribution of assets by Martin Resource Management to CF Martin Sulphur in November 2000. These environmental indemnity provisions expired on November 1, 2007. 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. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008, 2007 and 2006, the Conflicts Committee of - 123 - our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses cover all of the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. 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, 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 with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. This agreement replaced a prior agreement between us and Martin Transport, Inc. for land transportation services. Under the agreement, Martin Transport agreed to ship our NGL shipments as well as other liquid products. Term and Pricing. This agreement was amended in November 2006, January 2007, April 2007 and January 2008 to add additional point-to-point rates and to lower certain fuel and insurance surcharges being charged to us. The agreement has an initial term that expired in December 2007 but which automatically renewed through December 2008. This agreement will continue to automatically renew for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. We have the right to terminate this agreement at anytime by providing 90 days prior notice. Under this agreement, Martin Transport transports our NGL shipments as well as other liquid products. Our shipping rates were fixed for the first year of the agreement, subject to certain cost adjustments. These rates are subject to any adjustment to which we mutually agree or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list. 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. - 124 - Other Agreements Terminal Services Agreement. We are a party to a terminal services agreement with Martin Resource Management under which we provide the following services for Martin Resource Management at our terminals: (cid:2) we unload, transfer and store products received from vessels or trucks at the terminal; and (cid:2) we transfer products stored at the terminal to vessels or trucks. Effective each December 1, this agreement will automatically renew on a month-to- month basis until either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term. 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. This agreement replaced a prior agreement between us and Martin Resource Management covering marine transportation services which expired November 2005. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then- applicable term. The fees we charge Martin Resource Management are based on applicable market rates. Product Storage Agreement. We are a party to a product storage agreement with Martin Resource Management under which we lease storage space at Martin Resource Management’s underground storage facility located in Arcadia, Louisiana. Effective each November 1, this agreement automatically renews for consecutive one- year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Our per-unit cost under this agreement may be adjusted annually based on a price index. We indemnified Martin Resource Management from any damages resulting from our delivery of products that are contaminated or otherwise fail to conform to the product specifications established in the agreement, as well as any damages resulting from our transportation, storage, use or handling of products. Marine Fuel. We are a party to an agreement with Martin Resource Management under which Martin Resource Management provides us with marine fuel at its docks located in Mobile, Alabama, Theodore, Alabama, Pascagoula, Mississippi and Tampa, Florida. We agreed to purchase all of our marine fuel requirements that occur in the areas serviced by these docks under this agreement. Martin Resource Management provides fuel at an established margin above its cost on a spot-contract basis. This agreement had an initial term that expired in October 2005 and 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. Effective January 1, 2006 a new agreement was entered into 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. Throughput Agreement. We are a party to an agreement under which Martin Resource Management agreed to provide us with sole access to and use of a NGL truck loading and unloading and pipeline distribution terminal located at Mont Belvieu, Texas. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Our throughput fee may be adjusted annually based on a price index. Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement. We entered into a Purchaser Use Easement, Ingress-Egress Easement and Utility Facilities Easement with Martin Resource Management under which we have complete, non-exclusive access to, and use of, all marine terminal facilities, all loading and unloading facilities for vessels, barges and trucks and other common use facilities located at the Stanolind terminal. This easement has a perpetual duration. We did not incur any expenses, costs or other financial obligations under the easement. Martin Resource Management is obligated to maintain, and repair all common use areas and facilities located at this terminal. We share the use of these common use areas and facilities only with - 125 - Martin Resource Management who also have tanks located at the Stanolind facility. See “Item 1. Business — Terminalling and Storage Business — Marine Terminals — Specialty Petroleum Terminals.” Terminal Services Agreement. We entered into a terminal services agreement under which we provide terminalling services to Martin Resource Management. Effective each December 1, this agreement will automatically renew on a month-to- month basis until either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term. The per gallon throughput fee we charge under this agreement may be adjusted annually based on a price index. Specialty Terminal Services Agreement. We entered into an agreement under which Martin Resource Management provides terminal services to us. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The fees we charge under this agreement are adjusted annually based on a price index. Terminal Services Agreement — under which we provide terminalling services to Martin Resource Management. This agreement 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. Lubricants and Drilling Fluids Terminal Services Agreement — under which Martin Resource Management provides terminal services to us. Effective each January 1 this agreement, which was amended in July 2004, automatically renews for successive one-year terms until either party terminates the agreement by giving written notice to the other party at least 60 days prior to the end of the then-applicable term. The per gallon handling fee and the percentage of our commissions we are charged under this agreement may be adjusted annually based on a price index. Cross Terminalling Agreement — under which we provide terminalling services to Cross Oil Refining & Marketing, Inc., an affiliate of Martin Resource Management. This agreement expired on October 27, 2008 and we entered into a new five year agreement which expires October 31, 2013. The per gallon throughput fee we charge under this agreement may be adjusted during each year of the agreement. Sulfuric Acid Sales Agency Agreement — 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, which was amended and restated in August 2008, 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. 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 2007 Public Offering. In May 2007, we completed a public offering of 1,380,000 common units, resulting in proceeds of $55.9 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $1.2 million in cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. The net proceeds were used to used to pay down revolving debt under our credit facility and to provide working capital. Issuance of Common Units. In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a capital contribution of approximately $0.3 million made by our general partner in order to maintain its 2% general partner interest in us. These funds were used to pay down our revolving line of credit. - 126 - 2006 Public Offering. In January 2006, we completed a follow-on public offering of 3,450,000 common units, resulting in proceeds of $95.4 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $2.1 million in cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. Of the net proceeds, $62.0 million was used to pay then current balances under our revolving credit facility and $7.5 million was used to fund a portion of the redemption price for our U.S. Government Guaranteed Ship Financing Bonds. The remainder of the net proceeds has been or will be used to fund future organic growth projects. 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 transactions for such directors, officers and employees were conducted by such broker-dealers in the ordinary course of business. Waskom Agreements. Prism Gas is a party to a product purchase agreement and a gas processing agreement with Waskom whereby Prism Gas purchases product from and supplies product to Waskom. These intercompany transactions totaled approximately $77.3 million for the year ended December 31, 2008. In addition, Prism Gas provides certain administrative services for Waskom pursuant to Waskom’s partnership agreement. 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. - 127 - Item 14. Principal Accounting Fees and Services KPMG LLP served as our independent auditors for the fiscal years ended December 31, 2008 and 2007. The following fees were paid to KPMG LLP for services rendered during our last two fiscal years: Audit fees Audit related fees Audit and audit related fees Tax fees All other fees 2008 2007 $ 837,500(1) 12,800(3) 850,300 $ 850,000(2) 15,175(3) 865,175 80,725 (4) — 101,483(4) — Total fees _________________ (1) the audit of Martin Midstream GP LLC and fees related to services in connection with transactions. 2008 audit fees include fees for the annual integrated audit, the audit of Waskom Gas Processing Company, $ 931,025 $ 966,658 2007 audit fees include fees for the annual integrated audit, the audit of Waskom Gas Processing Company, (2) the audit of Martin Midstream GP LLC, issuance of the comfort letter related to the May 2007 equity offering and the review of registration statements and issuing related consents. (3) 2007. Audit related fees include fees for accounting consultations on various transactions occurring in 2008 and (4) consultations on other tax related matters. Tax fees are for services related to the review of our partnership K-1’s returns, and research and 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, 2008 and December 31, 2007 were approved in advance by the Audit Committee. - 128 - Item 15. Exhibits and Financial Statement Schedules PART IV (a) (1) Financial Statements and Schedules 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, 2008 and 2007 Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006 Consolidated Statements of Changes in Capital for the years ended December 31, 2008, 2007 and 2006 Consolidated Statements of Comprehensive Income for the years ended December 31, 2008 and 2007. Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006 Notes to the Consolidated Financial Statements (2) Financial Statements of Waskom Gas Processing Company for the year ended December 31, 2008, 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 131 for a list of all exhibits filed as part of this report. - 129 - 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. SIGNATURES Date: March 4, 2009 Martin Midstream Partners L.P. (Registrant) By: Martin Midstream GP LLC It’s General Partner 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, 2009. Signature Title /s/ Ruben S. Martin Ruben S. Martin /s/ Robert D. Bondurant Robert D. Bondurant /s/ Wesley M. Skelton Wesley M. Skelton /s/ John P. Gaylord John P. Gaylord /s/ C. Scott Massey C. Scott Massey /s/ Howard Hackney Howard Hackney President, Chief Executive Officer and Director of Martin Midstream GP LLC (Principal Executive Officer) Executive Vice President and Chief Financial Officer of Martin Midstream GP LLC (Principal Financial Officer) Executive Vice President, Chief Administrative Officer, Secretary and Controller of Martin Midstream GP LLC (Principal Accounting Officer) Director of Martin Midstream GP LLC Director of Martin Midstream GP LLC Director of Martin Midstream GP LLC - 130 - Exhibit Number 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 4.1 4.2 10.1 10.2 10.3 10.4 10.5 INDEX TO EXHIBITS Exhibit Name 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 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference). First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 6, 2002 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Martin Midstream Partners L.P., dated November 1, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 2, 2007, and incorporated herein by reference). Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated effective January 1, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed April 7, 2008, and incorporated herein by reference). 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 (Reg. No. 333- 91706), filed July 1, 2002, and incorporated herein by reference). 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, filed November 19, 2002, and incorporated herein by reference). 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 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference). 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 (Red. No. 33-91706), filed July 1, 2002, and incorporated herein by reference). 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 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference). 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 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference). Specimen Unit Certificate for Common Units (contained in Exhibit 3.2). 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 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference). Amended and Restated Credit Agreement, dated October 29, 2004, 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, filed November 11, 2004, and incorporated herein by reference). First Amendment to Credit Agreement, dated May 3, 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, filed May 4, 2005, and incorporated herein by reference). 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, filed January 2, 2008, and incorporated herein by reference). 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, filed November 14, 2005, and incorporated herein by reference). Omnibus Agreement dated November 1, 2002, by and among Martin Resource Management, the General - 131 - Exhibit Number 10.6 10.7 10.8 10.9 10.10 Exhibit Name Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). Motor Carrier Agreement dated November 1, 2002, by and between the Operating Partnership and Transport (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). Terminal Services Agreement dated November 1, 2002, by and between the Operating Partnership and Martin gas Sales LLC (“MGSLLC”) (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). Throughput Agreement dated November 1, 2002, by and between MGSLLC and the Operating Partnership (filed as Exhibit 10.6 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). Contract for Marine Transportation dated November 1, 2002, by and between the Operating Partnership and Martin Resource Management (filed as Exhibit 10.7 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). 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, filed November 19, 2002, and incorporated herein by reference). 10.11 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, filed November 19, 2002, and incorporated herein by reference). Product Supply Agreement dated November 1, 2002, by and between MGSLLC and the Operating Partnership (filed as Exhibit 10.10 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). 10.12 10.13† Martin Midstream Partners L.P. Long-Term Incentive Plan (filed as Exhibit 10.11 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). 10.14† Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to 10.15† 10.16 10.17 the Partnership’s Current Report on Form 8-K, filed January 26, 2006, and incorporated herein by reference). Form of Restricted Common Unit Award Notice (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed January 26, 2006, and incorporated herein by reference). Assignment and Assumption of Lease and Sublease dated November 1, 2002, by and between the Operating Partnership and MGSLLC (filed as Exhibit 10.12 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference). 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, filed November 19, 2002, and incorporated herein by reference). 10.18 Marine Transportation Agreement, by and between the Operating Partnership and Cross Oil Refining & 10.19 10.20 10.21 10.22 10.23 Marketing, Inc., dated October 27, 2003 (filed as Exhibit 10.14 to the Partnership’s Quarterly Report of Form 10-Q, filed November 10, 2003, and incorporated herein by reference). Terminalling Agreement, by and between the Operating Partnership and Cross Oil Refining & Marketing, Inc., dated October 27, 2003 (filed as Exhibit 10.15 to the Partnership’s Quarterly Report of Form 10-Q, filed November 10, 2003, and incorporated herein by reference). 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, filed January 23, 2004, and incorporated herein by reference). 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, filed September 6, 2005, and incorporated herein by reference). Amended and Restated Terminal Services Agreement by and between the Operating Partnership and MFSLLC, dated October 27, 2004 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed October 28, 2004, and incorporated herein by reference). Transportation Services Agreement by and between the Operating Partnership and MFSLLC, dated December 23, 2003 (filed as Exhibit 10.3 to the Partnership’s Amendment No. 1 to Current Report on Form - 132 - Exhibit Number 10.24 Exhibit Name 8-K, filed January 23, 2004, and incorporated herein by reference). 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, filed January 23, 2004, and incorporated herein by reference). 10.28 10.29 10.26 10.27 10.25† 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 (Reg. No. 333-140152), filed January 23, 2007, and incorporated herein by reference). Stock Purchase Agreement, dated April 27, 2007, by and among Woodlawn Pipeline Co., Inc., Lantern Resources, L.P., David P. Deison and Prism Gas Systems I, L.P. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 2, 2007, and incorporated herein by reference). Asset Purchase Agreement, dated April 27, 2007, by and among Peak Gas Gathering L.P. and Prism Gas Systems I, L.P. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed May 2, 2007, and incorporated herein by reference). Form of Indemnification Agreement (filed as Exhibit 10.1 to the Partnership’s Quarterly Report of Form 10- Q, filed November 6, 2008, and incorporated herein by reference). 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 filed September 30, 2008, and incorporated herein by reference). List of Subsidiaries. Consent of KPMG LLP. Consent of KPMG LLP. Consent of KPMG LLP. Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 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.” 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.” Balance Sheets as of December 31, 2008 and 2007 (audited) of Martin Midstream GP LLC. 21.1* 23.1* 23.2* 23.3* 31.1* 31.2* 32.1* 32.2* 99.1* * 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. - 133 - Financial Statement Schedule Pursuant to Item 15(a)(2) Waskom Gas Processing Company Consolidated Financial Statements December 31, 2008 and 2007 and for each of the years in the three- year period ended December 31, 2008, (with Independent Auditors’ Report Thereon) INDEPENDENT AUDITORS’ REPORT To the Partners of Waskom Gas Processing Company: We have audited the accompanying consolidated balance sheets of Waskom Gas Processing Company and subsidiary (the “Partnership”) as of December 31, 2008 and 2007 and the related consolidated statements of income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit 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 audit provides 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 the Partnership as of December 31, 2008 and 2007 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. /s/ KPMG LLP KPMG LLP Shreveport, Louisiana March 4, 2009 WASKOM GAS PROCESSING COMPANY CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2008 AND 2007 ASSETS CURRENT ASSETS: Cash Accounts receivable Accounts receivable—partners Accounts receivable—state grant Inventories Prepaid expenses 2008 2007 $ 1,388,434 236,207 10,356,710 1,114,314 463,575 3,989 $ 265,786 613,648 9,775,681 - 433,273 - Total current assets 13,563,229 11,088,388 PROPERTY AND EQUIPMENT: Gas plant asset and gas gathering equipment Other fixed assets Accumulated depreciation and amortization 80,210,281 734,871 (15,847,301) 67,931,309 584,747 (12,832,563) Net property and equipment 65,097,851 55,683,493 TOTAL $ 78,661,080 $ 66,771,881 LIABILITIES AND PARTNERS’ EQUITY CURRENT LIABILITIES: Accounts payable and accrued liabilities Accounts payable—partners $ 6,813,545 3,776,855 $ 6,939,543 2,485,286 Total current liabilities 10,590,400 9,424,829 LONG-TERM LIABILITIES—Asset retirement obligation 340,893 197,740 COMMITMENTS AND CONTINGENCIES PARTNERS’ CAPITAL 67,729,787 57,149,312 TOTAL $ 78,661,080 $ 66,771,881 See accompanying notes to consolidated financial statements. (cid:2) (cid:3)(cid:2)(cid:4)(cid:2)(cid:3)(cid:2) WASKOM GAS PROCESSING COMPANY CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 and 2006 2008 2007 2006 OPERATING REVENUES: Natural gas processing and other revenues Natural gas liquid sales Gain/(Loss) on disposal of assets $ 35,868,029 79,225,191 (61,891) $ 27,832,704 54,123,606 (159,724) $ 21,844,945 43,755,076 500 Total operating revenues 115,031,329 81,796,586 65,600,521 OPERATING COSTS AND EXPENSES: Cost of sales - natural gas liquids Operating costs Depreciation and amortization 78,008,310 6,414,677 3,129,246 53,014,173 4,595,878 1,925,840 42,505,653 4,355,646 1,493,499 Total operating costs and expenses 87,552,233 59,535,891 48,354,798 OPERATING INCOME BEFORE TAXES 27,479,096 22,260,695 17,245,723 Income tax expense 186,722 241,864 - NET INCOME $ 27,292,374 $ 22,018,831 $ 17,245,723 See accompanying notes to consolidated financial statements. (cid:2) (cid:3)(cid:2)(cid:5)(cid:2)(cid:3)(cid:2) WASKOM GAS PROCESSING COMPANY CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006 Total Partners' Capital BALANCE—December 31, 2005 $ 22,649,871 Cash contributions for capital expenditures Cash contributions for working capital Cash distributions Distributions in-kind Net income 19,980,733 2,494,939 (300,000) (16,621,349) 17,245,723 BALANCE—December 31, 2006 $ 45,449,916 Cash contributions for capital expenditures Cash distributions in excess of working capital Cash distributions Distributions in-kind Net income BALANCE—December 31, 2007 Cash contributions for capital expenditures Cash distributions in excess of working capital Cash distributions Distributions in-kind Net income 17,733,619 (4,128,057) (5,250,000) (18,674,997) 22,018,831 57,149,312 12,921,736 (8,583,683) (1,600,000) (19,449,952) 27,292,374 BALANCE—December 31, 2008 $ 67,729,787 See accompanying notes to consolidated financial statements. (cid:2) (cid:3)(cid:2)(cid:6)(cid:2)(cid:3)(cid:2) WASKOM GAS PROCESSING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006 OPERATING ACTIVITIES: Net income Adjustments to reconcile net income to cash used in operating activities: Depreciation and amortization Distributions in-kind to partners Loss/(Gain) on sale of asset Changes in operating assets and liabilities: Accounts receivable Accounts receivable - partners Inventory Prepaid expenses Accounts payable and accrued liabilites Accounts payable - partners 2008 2007 2006 $ 27,292,374 $ 22,018,831 $ 17,245,723 3,129,246 (19,449,952) 61,891 1,925,840 (18,674,997) 159,724 1,493,499 (16,621,349) (500) 377,441 (581,029) (30,302) (3,989) (125,998) 1,291,569 (286,895) 1,452,006 3,146 - 1,023,403 778,741 (391,548) (5,560,870) (412,779) - 805,279 1,275,364 Net cash provided by (used in) operating activities 11,961,251 8,399,799 (2,167,181) INVESTING ACTIVITIES: Additions to property and equipment Proceeds from sale of an asset (13,592,311) 15,655 (16,829,754) 15,200 (20,834,411) 500 Net cash used in investing activities (13,576,656) (16,814,554) (20,833,911) FINANCING ACTIVITIES: Contributions from partners Distrubutions to partners 12,921,736 (10,183,683) 17,733,619 (9,378,057) 22,475,672 (300,000) Net cash provided by financing activities 2,738,053 8,355,562 22,175,672 NET INCREASE (DECREASE) IN CASH 1,122,648 (59,193) (825,420) CASH—Beginning of year CASH—End of year 265,786 324,979 1,150,399 $ 1,388,434 $ 265,786 $ 324,979 SUPPLEM ENTAL CASH FLOW DISCLOSURES: Interest paid $ - $ - $ - Taxes paid $ 206,911 $ - $ - NON-CASH: State grant receivable Addition to asset retirement obligation $ $ 1,114,314 130,367 $ $ - - $ $ - - See accompanying notes to consolidated financial statements. (cid:2) (cid:3)(cid:2)(cid:7)(cid:2)(cid:3)(cid:2) 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, 2008 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 and marketing of natural gas and natural gas liquids (“NGL’s”), predominantly in Texas and northwest Louisiana. The Plant is a 265 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 and July of 2008 increasing the capacity from 150 MMcf/d to 265 MMcf/d. In January 2007 the Waskom fractionator was expanded to a capacity of 12,500 barrels per day from 9,500 barrels per day. 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 and Devon Energy Corporation, which collectively represent approximately 70% of the 257 MMcf/d of natural gas supplied for the year ended December 31, 2008, 72% of the 229 MMcf/d of natural gas supplied for the year ended December 31, 2007 and 61% of the 183 MMcf/d for the year ended December 31, 2006 The Partnership’s processing contracts are predominately percent-of-liquids (POL) contracts, in which the Partnership retains a portion of the NGL’s recovered as a processing fee. The Partnership also operates under percent-of-proceeds (POP) contracts in which it retains a portion of both the residue gas and the NGL’ s as payment for services. There is currently one contract for processing on a keep-whole basis. The Partnership is not contractually required to process these keep-whole volumes and, therefore, only processes natural gas related to this contract under profitable conditions. 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 2008, Waskom Products Pipeline, LLC was formed as a wholly owned subsidiary of Waskom Gas Processing Company, to hold certain pipeline assets of the Partnership. Accordingly, the financial statements for 2008 are consolidated to include both of 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: Gas gathering equipment Gas plant Furniture and fixtures Computer equipment Computer software Years 10 20 1 3 3 Depreciation expense was $3,116,460, $1,915,089 and $1,483,332 in 2008, 2007 and 2006, respectively. Repairs and maintenance are charged to operations as incurred. Renewals and betterments are capitalized. Inventories—Substantially all inventory at December 31, 2008 and 2007 represents pipe held for future projects. Such pipe was valued at acquisition cost. Asset Retirement Obligations—Under SFAS No. 143, “Accounting for Asset Retirement Obligations” (“Statement No. 143) which provides accounting requirements for costs associated with legal obligations to (cid:2) (cid:3)(cid:2)(cid:8)(cid:2)(cid:3)(cid:2) retire tangible, long-lived assets, the Partnership records as an offset to the Asset Retirement Obligation (“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. Accretion expense for 2008, 2007 and 2006 was $12,786, $10,751 and $10,167, respectively. Financial Accounting Standards Board issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143 clarifies that the recognition and measurement provisions of SFAS 143 apply to asset retirement obligations in which the timing or method of settlement may be conditional on a future event that may or may not be within the control of the entity. Impairment of Long-Lived Assets—In accordance with SFAS No. 144, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. 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 current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Partnership has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change was immaterial. The impact of the change in deferred tax assets does not have a material impact on tax expense. Texas margin tax expense for 2008 and 2007 was $186,722 and $241,864, respectively. There was no income tax expense recorded for the year ended December 31, 2006. 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. Reclassifications—Certain reclassifications have been made to the 2007 and 2006 statements of income to conform to the 2008 presentation. Recently Issued Accounting Pronouncements—In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) FAS 157-2, which delayed the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statement on a recurring basis, to fiscal years beginning after November 15, 2008. On January 1, 2008 the Partnership adopted the portion of SFAS No. 157 that was not delayed, which did not have an impact on the Partnership’s consolidated financial statements as the Partnership does not have any such assets or liabilities measured and reported at fair value. The adoption of the deferred portion of SFAS No. 157 on January 1, 2009 is not expected to have a material impact on the Partnership’s consolidated financial statements. (cid:2) (cid:3)(cid:2)(cid:9)(cid:2)(cid:3)(cid:2) In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Partnership adopted FIN 48 effective January 1, 2007. There was no impact to the Partnership’s financial statements as a result of adopting FIN 48. 3. RELATED-PARTY TRANSACTIONS During 2008, 2007 and 2006, 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 December 31, 2008 and 2007, the Partnership had receivables of approximately $10.4 million and $9.8 million, respectively, and payables of approximately $3.8 million and $2.5 million, 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 $12,921,736, $17,733,619 and $19,980,733 for 2008, 2007 and 2006, respectively. Cash contributions for working capital totaled $2,494,939 in 2006. 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 $8,583,683 in 2008 and $4,128,057 in 2007. Other cash distributions totaled $1,600,000, $5,250,000 and $300,000 for 2008, 2007 and 2006, respectively. The Partnership purchases gas from third party producers and processes this gas based on processing contracts, which are primarily percent-of-liquids (POL) contracts. The percentage of liquids retained by the Partnership is distributed to the partners as distributions of products-in-kind based on the partners’ equity interest. Distributions of products in-kind of $19,449,952, $18,674,997 and $16,621,349 in 2008, 2007 and 2006, 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 $75,738,508, $53,365,845 and $43,678,571 in 2008, 2007 and 2006, respectively, and are included as natural gas liquid sales in the income statement. 4. STATE GRANT During 2008, the Partnership replaced certain equipment which entitled them to receive a partial reimbursement from the State of Texas. The necessary paperwork has been filed and the Partnership has completed its obligations to be eligible for reimbursement. The reimbursement is expected by April 30, 2009. The company recorded a receivable of $1.1 million with an offset to a contra account in property and equipment. The contra account will be amortized into income over the same period as the related equipment is depreciated. Such amortization in 2008 amounted to $16,715. 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. (cid:2) (cid:3)(cid:2)(cid:10)(cid:2)(cid:3)(cid:2) SUBSIDIARIES OF MARTIN MIDSTREAM PARTNERS L.P. Exhibit 21.1 Subsidiary Martin Operating GP LLC Martin Operating Partnership L.P. Prism Gas Systems GP, L.L.C. Prism Gas Systems I, L.P. Jurisdiction of Organization Delaware Delaware Texas Texas McLeod Gas Gathering and Processing Company, L.L.C. Louisiana Prism Gulf Coast Systems, L.L.C. Woodlawn Pipeline Co., Inc. Prism Liquids Pipeline LLC Texas Texas Texas (cid:2) Consent of Independent Registered Public Accounting Firm Exhibit 23.1 The Board of Directors Martin Midstream GP LLC: We consent to the incorporation by reference in the registration statements (No. 333-148146) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our reports dated March 4, 2009, with respect to the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008, and the effectiveness of internal control over financial reporting as of December 31, 2008, which reports appear in the December 31, 2008 annual report on Form 10-K of Martin Midstream Partners L.P. /s/ KPMG LLP Shreveport, Louisiana March 4, 2009 (cid:2) Independent Auditors’ Consent Exhibit 23.2 The Board of Directors Martin Midstream GP LLC: We consent to the incorporation by reference in the registration statements (No. 333-148146) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. and Subsidiaries of our report dated March 4, 2009, with respect to the balance sheets of Waskom Gas Processing Company as of December 31, 2008 and 2007, and the related statements of income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2008, which report appears in the December 31, 2008 annual report on Form 10-K of Martin Midstream Partners L.P. /s/ KPMG LLP Shreveport, Louisiana March 4, 2009 (cid:2) Independent Auditors’ Consent Exhibit 23.3 The Board of Directors Martin Midstream GP LLC: We consent to the incorporation by reference in the registration statements (No. 333-148146) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our report dated March 4, 2009, with respect to the balance sheets of Martin Midstream GP LLC as of December 31, 2008 and 2007 which report appears as Exhibit 99.1 to the December 31, 2008 annual report on Form 10-K of Martin Midstream Partners L.P. /s/ KPMG LLP Shreveport, Louisiana March 4, 2009 (cid:2) CERTIFICATION PURSUANT TO AND IN CONNECTION WITH THE ANNUAL REPORTS ON FORM 10-K TO BE FILED UNDER SECTIONS 13 AND 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED Exhibit 31.1 I, Ruben S. Martin, certify that: 1. 2. I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: March 4, 2009 /s/ Ruben S. Martin Ruben S. Martin, President and Chief Executive Officer of Martin Midstream GP LLC, the General Partner of Martin Midstream Partners L.P. CERTIFICATION PURSUANT TO AND IN CONNECTION WITH THE ANNUAL REPORTS ON FORM 10-K TO BE FILED UNDER SECTIONS 13 AND 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED Exhibit 31.2 I, Robert D. Bondurant, certify that: 1. 2. I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: March 4, 2009 /s/ Robert D. Bondurant Robert D. Bondurant, Executive Vice President and Chief Financial Officer of Martin Midstream GP LLC, the General Partner of Martin Midstream Partners L.P. Exhibit 32.1 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)* In connection with the Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-K for the year ending December 31, 2008 as filed with the Securities and Exchange Commission (the “Report”), I, Ruben S. Martin, President and Chief Executive Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership. /s/ Ruben S. Martin Ruben S. Martin, President and Chief Executive Officer of Martin Midstream GP LLC, General Partner of Martin Midstream Partners L.P. March 4, 2009 *A signed original of this written statement required by Section 906 has been provided to Martin Midstream Partners L.P. (the “Partnership”) and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission and shall not be deemed to be “filed.” Exhibit 32.2 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)* In connection with the Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-K for the year ending December 31, 2008 as filed with the Securities and Exchange Commission (the “Report”), I, Robert D. Bondurant, Executive Vice President and Chief Financial Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership. /s/ Robert D. Bondurant Robert D. Bondurant, Executive Vice President and Chief Financial Officer of Martin Midstream GP LLC, General Partner of Martin Midstream Partners L.P. March 4, 2009 *A signed original of this written statement required by Section 906 has been provided to Martin Midstream Partners L.P. (the “Partnership”) and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission and shall not be deemed to be “filed.” Independent Auditors’ Report Exhibit 99.1 The Board of Directors Martin Midstream GP LLC: We have audited the accompanying consolidated balance sheets of Martin Midstream GP LLC as of December 31, 2008 and 2007. These balance sheets are the responsibility of the Company’s management. Our responsibility is to express an opinion on these balance sheets based on our audit. We conducted our audit 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 balance sheet is free of material misstatement. An audit of a balance sheet includes examining, on a test basis, evidence supporting the amounts and disclosures in that balance sheet. An audit of a balance sheet also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated balance sheets referred to above present fairly, in all material respects, the financial position of Martin Midstream GP LLC at December 31, 2008 and 2007, in conformity with U.S. generally accepted accounting principles. /s/ KPMG LLP Shreveport, Louisiana March 4, 2009 MARTIN MIDSTREAM GP LLC CONSOLIDATED BALANCE SHEETS Assets Cash ...................................................................................................................... Accounts and other receivables, less allowance for doubtful accounts of $1,781 and $394 ............................................................................................................... Product exchange receivables............................................................................... Inventories ............................................................................................................ Due from affiliates................................................................................................ Fair value of derivatives ....................................................................................... Other current assets .............................................................................................. Total current assets ........................................................................................ Property, plant and equipment, at cost.................................................................. Accumulated depreciation .................................................................................... Property, plant and equipment, net................................................................ Goodwill ............................................................................................................... Investment in unconsolidated entities................................................................... Fair value of derivatives ....................................................................................... Other assets, net.................................................................................................... Liabilities and Members’ Equity Current installments of long-term debt................................................................. Trade and other accounts payable......................................................................... Product exchange payables................................................................................... Due to affiliates .................................................................................................... Income taxes payable............................................................................................ Fair value of derivatives ....................................................................................... Other accrued liabilities........................................................................................ Total current liabilities .................................................................................. Long-term debt ..................................................................................................... Deferred income taxes .......................................................................................... Fair value of derivatives ....................................................................................... Other long-term obligations.................................................................................. Total liabilities............................................................................................... Minority interests.................................................................................................. Members’ equity................................................................................................... Commitments and contingencies .......................................................................... See accompanying notes to the consolidated balance sheets. 1 December 31, 2007 2008 (Dollars in thousands) $ 7,983 $ 4,113 68,117 6,924 42,461 555 3,623 1,079 130,742 537,381 (125,256) 412,125 37,405 79,843 1,469 7,332 $ 668,916 $ — 87,382 10,924 12,522 1,236 6,479 6,089 124,632 295,000 9,172 4,302 1,667 434,773 230,712 3,431 234,143 88,039 10,912 51,798 2,325 235 584 158,006 441,117 (98,080) 343,037 37,405 75,690 — 9,439 $ 623,577 $ 21 104,598 24,554 9,323 974 4,502 4,762 148,734 225,000 9,244 5,576 1,767 390,321 231,737 1,519 233,526 $ 668,916 $ 623,577 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (1) ORGANIZATION AND DESCRIPTION OF BUSINESS Martin Midstream GP LLC (the “General Partner”) is a single member Delaware limited liability company formed on September 21, 2002 to become the general partner of Martin Midstream Partners L.P. (the “Company”). The General Partner owns a 2% general partner interest and incentive distribution rights in the Company. The General Partner is a wholly owned subsidiary of Martin Resource Management Corporation (“MRMC”). In September 2005 the FASB ratified EITF Issue 04-5, a framework for addressing when a limited company should be consolidated by its general partner. The framework presumes that a sole general partner in a limited company controls the limited company, and therefore should consolidate the limited company. The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited company or (b) substantive participating rights. The EITF reached a conclusion on the circumstances in which either kick-out rights or participating rights would be considered substantive and preclude consolidation by the general partner. Based on the guidance in the EITF, the General Partner concluded that the Company should be consolidated. As such, the accompanying balance sheets have been consolidated to include the General Partner and the Company. The Company is a publicly traded limited partnership which provides terminalling and storage services for petroleum products and by-products, natural gas services, marine transportation services for petroleum products and by-products, sulfur and sulfur-based product processing, manufacturing and distribution. The petroleum products and by-products the Company 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 Company, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, the Company’s primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Company operates primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry. The Company owns Prism Gas Systems I, L.P. (“Prism Gas”) which is engaged in the gathering, processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana. Through the acquisition of Prism Gas, the Company also acquired 50% ownership interest in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”), and Bosque County Pipeline (“BCP”) each accounted for under the equity method of accounting. (2) SIGNIFICANT ACCOUNTING POLICIES (a) Principles of Presentation and Consolidation The consolidated balance sheets include the financial position of the General Partner and the Company and its wholly-owned subsidiaries and its equity method investees. All significant intercompany balances and transactions have been eliminated in consolidation. As the General Partner only has a 2% interest in the Company, the remaining 98% not owned is shown as minority interests in the consolidated balance sheets. In addition, the Company evaluates its relationships with other entities to identify whether they are variable interest entities as defined by FASB Interpretation No 46(R) Consolidation of Variable Interest Entities (“FIN 46R”) and to assess whether they are the primary beneficiary of such entities. If the determination is made that the Company is the primary beneficiary, then that entity is included in the consolidated balance sheet in accordance with FIN 46(R). No such variable interest entities exist as of December 31, 2008 and December 31, 2007. 2 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (b) Product Exchanges Product exchange balances due to other companies under negotiated agreements are recorded at quoted market product prices while balances due from other companies are recorded at the lower of cost (determined using the first-in, first-out method) or market. (c) Inventories Inventories are stated at the lower of cost or market. Cost is determined by using the first-in, first-out (FIFO) method for all inventories. (d) Revenue Recognition Revenue for the Company’s 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 the Company’s terminals at the contracted rate. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, the Company recognizes NGL distribution revenue when the customer receives the product from either the storage facility or pipeline. Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip. For time charters, revenue is recognized based on a per day rate. Sulfur services – Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership based on specific contract terms at either the shipping or delivery point. (e) Equity Method Investments The Company 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 Company’s share of accumulated earnings less capital withdrawals and distributions. Any excess of cost over the underlying equity in net assets is recognized as goodwill. Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. (f) Property, Plant, and Equipment Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets. Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss. 3 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (g) Goodwill and Other Intangible Assets Goodwill represents the excess of costs over fair value of assets of businesses acquired. Goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. Intangible assets with estimated useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with. Other intangible assets primarily consist of covenants not-to-compete and contracts obtained through business combinations and are being amortized over the life of the respective agreements. Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Company is required to identify their reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. Goodwill is assigned to reporting units at the date the goodwill is initially recorded. Once goodwill has been assigned to reporting units, it no longer retains its association with a particular acquisition, and all of the activities within a reporting unit, whether acquired or organically grown, are available to support value of the goodwill. The Company performed the annual impairment tests as of September 30, 2008, September 30, 2007 and September 30, 2006, respectively. In performing such tests, it was determined that there were four “reporting units” which contained goodwill. These reporting units were in each of the four reporting segments: terminalling, natural gas services, marine transportation, and sulfur services. The estimated fair value of the reporting units with goodwill were developed using the guideline public company method, the guideline transaction method, and the DCF method using observable market data where available. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Company would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired. At September 30, 2008, 2007 and 2006 the estimated fair value of each of the four reporting units was in excess of its carrying value resulting in no impairment. As a result of the deterioration in the overall stock market subsequent to September 30, 2008 and the decline in the unit price, the Company reviewed specific factors, as outlined in SFAS No. 142, to determine if the Company had a trigging event that required it to test the goodwill for impairment as of December 31, 2008. These factors included whether there have been any significant fundamental changes since the annual impairment test to (i) the Company as a whole or to the reporting units, including regulatory changes, (ii) the level of operating cash flows, (iii) the expectation of future levels of operating cash flows, (iv) the executive management team, and (v) the carrying value of the other long-lived assets. While these factors did not indicate a triggering event occurred, the Company’s unit price fell to a point by December 31, 2008 that resulted in the total market capitalization being less than the partner’s equity. The Company determined this to be a triggering event requiring the Company to perform an impairment test as of December 31, 2008. As a result of the goodwill impairment test for each of the four reporting units as of December 31, 2008, no impairment was determined to exist. (h) Debt Issuance Costs In connection with the Company’s multi-bank credit facility, on November 10, 2005, it incurred debt issuance costs of $3,258. In connection with the amendment and expansion of the Partnership’s multi-bank credit facility on June 30, 2006, it incurred debt issuance costs of $372. In connection with the amendment and expansion of the Company’s multi-bank credit facility on December 28, 2007, it incurred debt issuance costs of $252. These debt issuance costs, along with the remaining unamortized deferred issuance costs relating to the line of credit facility as of November 10, 2005 which remain deferred, are amortized over the remainder of the 60 month term of the original debt arrangement. Accumulated amortization of debt issuance cost amounted to $5,445 and $4,324 at December 31, 2008 and 2007, respectively. The unamortized balance of debt issuance costs, classified as other assets amounted to $2,086 and $3,188 at December 31, 2008 and 2007, respectively. 4 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (i) Impairment of Long-Lived Assets In accordance with SFAS No. 144, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. 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 Company has not identified any triggering events in 2008, 2007 or 2006 that would require an assessment for impairment of long-lived assets. (j) Asset Retirement Obligation Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143) and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143, which provide accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Company 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 Company’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment. The transportation equipment includes pipelines system. The Company transports NGLs through the pipeline system and gathering system. The Company also gathers natural gas from wells owned by producers and delivers natural gas and NGLs on the Company’s pipeline systems, primarily in Texas and Louisiana to the fractionation facility of the Company’s 50% owned joint venture. The Company is obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of the Company’s assets. However, the Company is not able to reasonably determine the fair value of the asset retirement obligations for the Company’s trunk and gathering pipelines and the Company’s surface facilities, since future dismantlement and removal dates are indeterminate. In order to determine a removal date of the Company’s gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of natural gas, the Company is not a producer of the field reserves, and the Company therefore does not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which the Company gathers natural gas. In the absence of such information, the Company is not able to make a reasonable estimate of when future dismantlement and removal dates of the Company’s gathering assets will occur. With regard to the Company’s trunk pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. The Company’s right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, the Company can evaluate the Company’s trunk pipelines for alternative uses, which can be and have been found. The Company will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. (k) Derivative Instruments and Hedging Activities In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. 5 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, the Company has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in accumulated other comprehensive income as a component of equity. (l) 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 Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. (m) Unit Grants The Company 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 in the open market for $93 in May 2008. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012. The Company issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in May 2007. These units vest in 25% increments beginning in January 2008 and will be fully vested in January 2011. The Company issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in January 2006. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010. The Company accounts for these transactions under EITF Issue 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” (n) Incentive Distribution Rights The General Partner holds a 2% general partner interest and certain incentive distribution rights in the Company. Incentive distribution rights represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved. The Company is required to distribute all of its available cash from operating surplus, as defined in the Company agreement. The target distribution levels entitle the General Partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unit holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the years ended December 31, 2008 and 2007, the General Partner received incentive distributions. Such distributions have been eliminated in the accompanying consolidated balance sheet. (o) 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 their consolidated balance sheets in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. (p) Environmental Liabilities The Company’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 6 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) 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. (q) Income Taxes The General Partner is a disregarded entity for federal income tax purposes. Its activity is included in the consolidated federal income tax return of MRMC; however, for financial reporting purposes, current federal income taxes are computed and recorded as if the General Partner filed a separate federal income tax return. The Company’s subsidiary, Woodlawn Pipeline Co., Inc. (“Woodlawn”), is subject to income taxes. In connection with the Woodlawn acquisition, a deferred tax liability of $8,964 was established associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment. 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. Deferred tax liabilities relating primarily to book and tax basis differences of the acquired assets of Woodlawn, and the timing of recognizing Company earnings and insurance expense totaled $9,184 and $9,254 ($12 and $10 of which is included in other accrued liabilities) at December 31, 2008 and December 31, 2007, respectively. The operations of the Company are generally not subject to income taxes and as a result, the Company’s income is taxed directly to its owners, except for the Texas Margin Tax as described below and the taxes associated with Woodlawn as previously discussed. On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Company has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change and subsequent changes in deferred tax assets and liabilities are immaterial. At December 31, 2008 and 2007, the Company recorded a liability attributable to the Texas Margin tax of $805 and $538, respectively. In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes. FIN 48 is an interpretation of FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Company adopted FIN 48 effective January 1, 2007. There was no impact to the Company’s financial statements as a result of adopting FIN 48. (3) NEW ACCOUNTING PRONOUNCEMENTS In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133” (SFAS No. 161). SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and is effective for the Company on January 1, 2009. Since SFAS No. 161 requires enhanced disclosures, without a change to existing standards relative to measurement and recognition, the Company’s adoption of SFAS No. 161 will not have any effect on our consolidated financial statements. 7 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes new accounting, disclosure and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 is effective for the Company on January 1, 2009. The adoption of SFAS No. 160 will not have a material impact on the Company’s consolidated financial statements. However, it could impact accounting for future transactions. In December 2007, the FASB issued SFAS No. 141(Revised 2007), “Business Combinations” (SFAS No. 141(R)). SFAS No. 141(R) retains the underlying concepts of SFAS No. 141 in that all business combinations are still required to be accounted for at fair value under the acquisition method of accounting, but SFAS No. 141(R) establishes revised principles and requirements for how entities will recognize and measure assets and liabilities acquired in a business combination, including but not limited to, generally expensing of acquisition costs as incurred and valuing noncontrolling interests (minority interests) at fair value at the acquisition date. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. The Company will adopt the provisions of SFAS No. 141(R) to business combinations completed on or after January 1, 2009. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. SFAS No. 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Company adopted SFAS No. 159 on January 1, 2008 but has not elected to apply the fair value option provided under SFAS No. 159 to any eligible assets or liabilities.. In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (SFAS No. 157), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) FAS 157-2, which delayed the effective date of SFAS No. 157 for certain nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statement on a recurring basis, to fiscal years beginning after November 15, 2008. In February 2008, the FASB issued FSP SFAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP SFAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. On January 1, 2008, the Company adopted the portion of SFAS No. 157 that was not delayed, and since the Company’s existing fair value measurements are consistent with the guidance of SFAS No. 157, the partial adoption of SFAS No. 157 did not have a material impact on the Company’s consolidated financial statements. The adoption of the deferred portion of SFAS No. 157 on January 1, 2009 is not expected to have a material impact on the Company’s consolidated financial statements. See Note 4 for expanded disclosures about fair value measurements. (4) FAIR VALUE MEASUREMENTS During the first quarter of 2008, the Company adopted FASB Statement No. 157, Fair Value Measurements (FAS 157). FAS 157 established a framework for measuring fair value and expanded disclosures about fair value 8 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) measurements. The adoption of FAS 157 had no impact on the Company’s financial position or results of operations. FAS 157 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that each asset and liability carried at fair value be classified into one of the following categories: Level 1: Quoted market prices in active markets for identical assets or liabilities. Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data. Level 3: Unobservable inputs that are not corroborated by market data. The Company’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 Company’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Refer to Notes 12 and 13 for further information on the Company’s derivative instruments and hedging activities. As prescribed by the FAS 157 levels listed above, the Company considers the Company’s derivative assets and liabilities as Level 2. The net fair value of the Company’s assets and liabilities measured on a recurring basis was a liability of $5,688 and $10,077 at December 31, 2008 and 2007, respectively. (5) ACQUISITIONS (a) Stanolind Terminal Assets. In January 2008, the Company acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management Corporation (“Martin Resource Management”) for $5,983 which was allocated to property, plant and equipment. The Company entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks. In connection with the acquisition, the Company borrowed approximately $6,000 under its credit facility. (b) Asphalt Terminal. In October 2007, the Partnership acquired the asphalt assets of Monarch Oil, Inc (“Monarch Oil”) for $3,927 which was allocated to property, plant and equipment. The results of Monarch Oil’s operations have been included in the consolidated financial statements beginning October 2, 2007. The assets are located in Omaha, Nebraska. The Partnership entered into an agreement with Martin Resource Management, whereby Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will bear all additional expenses to operate the facility. In connection with the Partnership’s Monarch Oil acquisition on October 2, 2007, the Partnership borrowed approximately $3,900 under its revolving credit facility. (c) Lubricants Terminal In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) located in Channelview, Texas. The results of Mega Lubricant’s operations have been included in the consolidated financial statements beginning June 13, 2007. The fair market value of the assets acquired was appraised at $93,938. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $1,020 was recorded as goodwill. The goodwill was a result of Mega Lubricant’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional lubricant blending and truck loading and unloading services to customers. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment. The terminal is located on 5.6 acres of land, and consists of 38 tanks with a storage capacity of approximately 15,000 Bbls, pump and piping infrastructure for 9 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an administrative office. The purchase price of $4,738, including two three-year non-competition agreements totaling $530 and goodwill of $1,020, was allocated as follows: Current assets Property, plant and equipment, net Goodwill Other assets Other liabilities Total $ 446 3,042 1,020 530 (300) 4,738 $ In connection with the acquisition, the Partnership borrowed approximately $4,600 under its credit facility. (d) Woodlawn Pipeline Co., Inc. On May 2, 2007, the Partnership, through its subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), acquired 100% of the outstanding stock of Woodlawn Pipeline Co., Inc. (“Woodlawn”). The results of Woodlawn’s operations have been included in the consolidated financial statements beginning May 2, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $8,785 was recorded as goodwill. The goodwill was a result of Woodlawn’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional gathering services to customers through internal growth projects including natural gas processing, fractionation and pipeline expansions as well as new pipeline construction. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment. Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 Mcf/day processing plant. Prism Gas also acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from Woodlawn to the Texas Eastern Transmission pipeline system. The selling parties in this transaction were Lantern Resources, L.P., David P. Deison, and Peak Gas Gathering L.P. The final purchase price, after final adjustments for working capital, was $32,606 and was funded by borrowings under the Partnership’s credit facility. The purchase price of $32,606, including four two-year non-competition agreements and other intangibles reflected as other assets, was allocated as follows: Current assets Property, plant and equipment, net Goodwill Other assets Current liabilities Deferred income taxes Other long-term obligations Total $ 4,297 29,101 8,785 3,339 (3,889) (8,964) (63) 32,606 $ The identifiable intangible assets of $3,339 are subject to amortization over a weighted-average useful life of approximately ten years. The intangible assets include four non-competition agreements totaling $40, customer 10 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) contracts associated with the gathering and processing assets of $3,002, and a transportation contract associated with the residue gas pipeline of $297. In connection with the acquisition, the Partnership borrowed approximately $33,000 under its credit facility. (6) INVENTORIES Components of inventories at December 31, 2008 and 2007 were as follows: Natural gas liquids ................................................................................... Sulfur ....................................................................................................... Sulfur Based Products.............................................................................. Lubricants ................................................................................................ Other ........................................................................................................ 2008 $10,530 6,522 14,879 8,110 2,420 $42,461 2007 $31,283 7,490 6,626 5,345 1,054 $51,798 (7) PROPERTY, PLANT AND EQUIPMENT At December 31, 2008 and 2007, property, plant, and equipment consisted of the following: Depreciable Lives 2008 2007 Land ........................................................................... Improvements to land and buildings.......................... Transportation equipment .......................................... Storage equipment ..................................................... Marine vessels ........................................................... Operating equipment ................................................. Furniture, fixtures and other equipment..................... Construction in progress ............................................ — 10-25 years 3-7 years 5-20 years 4-25 years 3-20 years 3-20 years (8) GOODWILL AND OTHER INTANGIBLE ASSETS At December 31, 2008 and 2007, goodwill balances consisted of the following: Carrying amount of goodwill: Terminalling and storage ............................................................................... Natural gas services ....................................................................................... Marine transportation..................................................................................... Sulfur services ............................................................................................... $ 15,647 43,092 1,768 45,196 200,473 192,434 1,548 37,223 $537,38 1 $14,515 34,585 616 38,652 147,627 172,282 1,542 31,298 $441,117 2008 2007 $ 1,020 29,010 2,026 5,349 $37,405 $ 1,020 29,010 2,026 5,349 $37,405 11 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) At December 31, 2008 and 2007, covenants not-to-compete balances consisted of the following: Covenants not-to-compete: Terminalling and storage ..................................................................... Natural gas services ............................................................................. Sulfur services ..................................................................................... Less accumulated amortization............................................................ 2008 2007 $ 1,928 40 790 2,758 1,539 $ 1,219 $ 1,928 640 790 3,358 1,610 $ 1,748 Intangible assets consists of the covenants not-to-compete listed above, customer contracts associated with gathering and processing assets and a transportation contract associated with the residue gas pipeline. The covenants not-to-compete and contracts are presented in the consolidated balance sheets as other assets, net. (9) RELATED PARTY TRANSACTIONS Amounts due to and due from affiliates in the consolidated balance sheets as of December 31, 2008 (unaudited) and December 31, 2007, are primarily with MRMC and its affiliates and Waskom Gas Processing Company (“Waskom”). The General Partner’s balances are primarily related to (1) Company cash distributions that were paid to a related party on behalf of the General Partner and (2) director fees that were paid by a related party on behalf of the General Partner. The Company contributions and distributions have been eliminated in the accompanying consolidated balance sheet. The Company’s balances are related to transactions involving the purchase and sale of NGL products, lube oil products, sulfur and sulfuric acid products, sulfur-based fertilizer products; land and marine transportation services; terminalling and storage services, and other purchases of products and services representing operating expenses. (10) INVESTMENT IN UNCONSOLIDATED COMPANIES AND JOINT VENTURES The Company, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”) and a 20% ownership interest in a Company which owns the lease rights to Bosque County Pipeline (“BCP”). Each of these interests is accounted for under the equity method of accounting. In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $594 for both the years ended December 31, 2008 and 2007 has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $10,091 and $10,685 at December 31, 2008 and 2007, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in 2008, 2007 or 2006. As a partner in Waskom, the Company receives distributions in kind of natural gas liquids (“NGLs”) that are retained according to Waskom’s contracts with certain producers. The NGLs are valued at prevailing market prices. In addition, cash distributions are received and cash contributions are made to fund operating and capital requirements of Waskom. 12 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) Activity related to these investment accounts is as follows: Waskom PIPE Matagorda BCP Total Investment in unconsolidated entities, December 31, 2006 $ 64,937 $ 1,718 $ 3,786 $ 210 $ 70,651 Distributions in kind............................................................. Return on investments.......................................................... Contributions to (distributions from) unconsolidated entities for operations.......................................................... . Return of investments .......................................................... Equity in earnings: Equity in earnings from operations................................. Amortization of excess investment................................. (9,337) (884) 6,803 (1,741) — (517) — (118) — (122) — (93) — — (9,337) (1,523) 107 — 6,910 (1,952) 11,009 (550) 514 (15) 151 (29) (139) — 11, 535 (594) Investment in unconsolidated entities, December 31, 2007 $ 70,237 $ 1,582 $ 3,693 $ 178 $ 75,690 Distributions in kind............................................................. Return on investments.......................................................... Contributions to (distributions from) unconsolidated entities: Cash contributions........................................................... Contributions to (distributions from) unconsolidated entities for operations............................................ Return of investments .......................................................... Equity in earnings: Equity in earnings from operations................................. Amortization of excess investment................................. (9,725) (500) 1,250 920 — — 129 — — — — — — — (9,725) (500) 80 — 1,459 920 (300) (180) (745) — (1,225) 13,646 (550) (302) (15) 640 (29) (166) — 13,818 (594) Investment in unconsolidated entities, December 31, 2008 $74,978 $ 1,214 $ 3,559 $ 92 $ 79,843 Select financial information for significant unconsolidated equity method investees is as follows: Total Assets Long- Term Debt Partner’s Capital Revenues Net Income 2008 Waskom.......................................................................... $ 78,661 $ — $ 67,730 $ 115,031 $ 27,292 2007 Waskom.......................................................................... $ 66,772 $ — $ 57,149 $ 81,797 $ 22,019 2006 Waskom.......................................................................... $ 53,260 $ — $ 45,450 $ 65,600 $ 17,246 As of December 31, 2008 and 2007, the Company’s interest in cash of the unconsolidated equity method investees is $1,956 and $1,018, respectively. (11) LONG-TERM DEBT At December 31, 2008 and December 31, 2007, long-term debt consisted of the following: **$195,000 Revolving loan facility at variable interest rate (6.04%* weighted average at December 31, 2008), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees.................................. $ 165,000 $ 95,000 December 31, 2008 December 31, 2007 13 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) ***$130,000 Term loan facility at variable interest rate (7.04%* at December 31, 2008), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries........... Other secured debt maturing in 2008, 7.25% Total long-term debt Less current installments Long-term debt, net of current installments 130,000 130,000 — 295,000 — $295,000 21 225,021 21 $225,000 *Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing LIBOR borrowings is 2.50%. Effective January 1, 2009, the applicable margin for existing LIBOR borrowings will decrease to 2.00%. As a result of our leverage ratio test as of December 31, 2008, effective April 1, 2009, the applicable margin for existing LIBOR borrowings will remain at 2.00%. The Company incurs a commitment fee on the unused portions of the credit facility. **Effective October 2008, the Company entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 2.820% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in October 2010. ** Effective January 2008, the Company entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 3.400% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in January 2010. ** Effective September 2007, the Company entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in September 2010. **Effective November 2006, the Company entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 4.82% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in December 2009. ***The $130,000 term loan has $105,000 hedged. Effective March, 2006, the Company entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010. Effective November 2006, the Company entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This cash flow hedge matures in March, 2010. On November 10, 2005, the Company entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub- limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the Company increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. Effective December 28, 2007, the Company increased its revolving credit facility $75,000 resulting in a committed $195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general Company purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of December 31, 2008, the Company had $165,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of December 31, 2008, the 14 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) Company had $29,880 available under its revolving credit facility. On July 14, 2005, the Company issued a $120 irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program. The Company’s obligations under the credit facility are secured by substantially all of the Company’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Company 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 Company’s ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell all or substantially all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) its joint ventures to incur indebtedness or grant certain liens. The credit facility also contains covenants, which, among other things, require the Company to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. The Company was in compliance with the debt covenants contained in credit facility for the years ended December 31, 2008 and 2007. The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls the Company’s general partner, the lenders under the Company’s credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under the Company’s credit facility if it is deemed to have a material adverse effect on the Company. Any event of default and corresponding acceleration of outstanding balances under the Company’s credit facility could require the Company to refinance such indebtedness on unfavorable terms and would have a material adverse effect on the Company’s financial condition and results of operations as well as its ability to make distributions to unitholders. On November 10 of each year, commencing with November 10, 2006, the Company must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made or required under the term loan through December 31, 2008. If the Company receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Company must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Company must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross- defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults. Draws made under the Company’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Company’s credit facility have ranged from a low of $225,000 to a high of $319,100. As of December 31, 2008, the Company had $29,880 available for working capital, internal expansion and acquisition activities under the Company’s credit facility. In connection with the Company’s Stanolind asset acquisition on January 22, 2008, the Company borrowed approximately $6,000 under its revolving credit facility. 15 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) In connection with the Company’s Monarch acquisition on October 2, 2007, the Company borrowed approximately $3,900 under its revolving credit facility. In connection with the Company’s Mega Lubricants acquisition on June 13, 2007, the Company borrowed approximately $4,600 under its revolving credit facility. In connection with the Company’s Woodlawn acquisition on May 2, 2007, the Company borrowed approximately $33,000 under its revolving credit facility. (12) INTEREST RATE CASH FLOW HEDGES The Company has entered into several cash flow hedge agreements with an aggregate notional amount of $235,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. The Company designated these swap agreements as cash flow hedges. Under these swap agreements, the Company pays a fixed rate of interest and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because these swaps are designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of these hedges, these swaps were identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and these swaps remain equal. This condition results in a 100% effective swap for the following hedges: Date of Hedge October 2008 January 2008 September 2007 November 2006 March 2006 Notional Amount $40,000 $25,000 $25,000 $40,000 $75,000 Fixed Rate 2.820% 3.400% 4.605% 4.820% 5.250% Maturity Date October 2010 January 2010 September 2010 December 2009 November 2010 In December 2006, the Company entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006, therefore, hedge accounting was not utilized. The swap has been recorded at fair value at December 31, 2008 with an offset to current operations. During the year ended December 31, 2008, the Company recognized increases in interest expense of $3,416 related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps. The total fair value of the interest rate swaps agreement was a liability of $10,780 and $4,677 at December 31, 2008 and 2007. The fair value of derivative liabilities is as follows: December 31, 2008 December 31, 2007 Fair value of derivative liabilities — current............................................... Fair value of derivative liabilities — long term.......................................... Net fair value of derivatives ........................................................................ $ (6,478) (4,302) $ (10,780) $ (1,241) (3,436) $ (4,677) (13) COMMODITY CASH FLOW HEDGES The Company is exposed to market risks associated with commodity prices, counterparty credit and interest rates. The Company has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. In addition, the Company is focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. 16 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) The Company uses derivatives to manage the risk of commodity price fluctuations. Additionally, the Company manages interest rate exposure by targeting a ratio of fixed and floating interest rates it deems prudent and using hedges to attain that ratio. In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income until such time as the hedged item is recognized in earnings. The Company has adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, the Company has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity. The fair value of derivative assets and liabilities are as follows: Fair value of derivative assets — current........................................ Fair value of derivative assets — long term ................................... Fair value of derivative liabilities — current .................................. Fair value of derivative liabilities — long term .............................. Net fair value of derivatives............................................................ December 31, 2008 2007 $ 3,623 1,469 — — $ 5,092 $ 235 — (3,261) (2,140) $ (5,166) Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2008 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of December 31, 2008, the remaining term of the contracts extend no later than December 2010, with no single contract longer than one year. The Company’s counterparties to the derivative contracts include Shell Energy North America (US) L.P., Morgan Stanley Capital Group Inc. and Wachovia Bank. For the period ended December 31, 2008, changes in the fair value of the Company’s derivative contracts were recorded in both earnings and in accumulated other comprehensive income as a component of equity since the Company has designated a portion of its derivative instruments as hedges as of December 31, 2008. Transaction Type Total Volume Per Month Mark to Market Derivatives:: December 31, 2008 Pricing Terms Remaining Terms of Contracts Fair Value Crude Oil Swap 3,000 BBL Fixed price of $69.08 settled against WTI NYMEX average monthly closings Crude Oil Swap 3,000 BBL Fixed price of $70.90 settled against WTI NYMEX average monthly closings Crude Oil Swap 3,000 BBL Fixed price of $72.25 settled against WTI NYMEX average monthly closings Crude Oil Swap 1,000 BBL Fixed price of $104.80 settled against WTI NYMEX average monthly closings January 2009 to December 2009 January 2009 to December 2009 January 2010 to December 2010 January 2010 to December 2010 565 628 300 453 17 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) Total swaps not designated as cash flow hedges Cash Flow Hedges: Natural Gas swap 30,000 Fixed price of $9.025 settled against MMBTU Inside Ferc Columbia Gulf daily average Crude Oil Swap 1,000 BBL Fixed price of $70.45 settled against WTI NYMEX average monthly closings Natural Gasoline Swap 2,000 BBL Fixed price of $86.42 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings. Crude Oil Swap 2,000 BBL Fixed price of $69.15 settled against WTI NYMEX average monthly closings Natural Gasoline Swap 1,000 BBL Fixed price of $94.14 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings January 2009 to December 2009 January 2009 to December 2009 January 2009 to December 2009 January 2010 to December 2010 January 2010 to December 2010 Total swaps designated as cash flow hedges Total net fair value of derivatives $ 1,946 1,033 204 1,193 132 584 $ 3,146 $ 5,092 On all transactions where the Company is exposed to counterparty risk, the Company analyzes the counterparty’s financial condition prior to entering into an agreement, and has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Company has incurred no losses associated with the counterparty non-performance on derivative contracts. The Company is exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales activities. The Company’s gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (POL) and percent-of-proceeds (POP) basis. The Company has entered into hedging transactions through 2010 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas, and natural gasoline. As a result of declining commodity prices, the Company determined that continued reporting of losses in accumulated other comprehensive income (AOCI) for certain commodity hedges would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods. Accordingly, the calculated loss of $2,608 was immediately reclassified into 2008 earnings. The remaining deferred gains of $1,534 and deferred losses of $116 pertaining to the above commodity hedges will remain in AOCI and are expected to be reclassified into earnings in the same period that the forecasted hedge transaction is reported in earnings. Based on estimated volumes, as of December 31, 2008, the Company had hedged approximately 47% and 21% of its commodity risk by volume for 2009, and 2010, respectively. The Company anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Company will be able to do so or that the terms thereof will be similar to the Company’s existing hedging arrangements. 18 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) Natural Gas Commodity Hedged Year 2009 2009 Condensate & Natural Gasoline 2009 ENatural Gasoline 2009 2009 2010 Condensate 2010 Natural Gasoline 2010 Condensate 2010 Natural Gasoline Condensate Natural Gasoline Hedging Arrangements in Place As of December 31, 2008 Volume Type of Derivative 30,000 MMBTU/Month Natural Gas Swap ($9.025) Crude Oil Swap ($69.08) 3,000 BBL/Month Crude Oil Swap ($70.90) 3,000 BBL/Month Crude Oil Swap ($70.45) 1,000 BBL/Month Natural Gasoline Swap ($86.42) 2,000 BBL/Month Crude Oil Swap ($69.15) 2,000 BBL/Month Crude Oil Swap ($72.25) 3,000 BBL/Month Crude Oil Swap ($104.80) 1,000 BBL/Month Natural Gasoline Swap ($94.14) Mt. Belvieu (Non-TET) 1,000 BBL/Month Basis Reference Columbia Gulf NYMEX NYMEX NYMEX Mt. Belvieu (Non-TET) NYMEX NYMEX NYMEX The Company’s principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of the Company’s natural gas and NGL sales are made at market-based prices. The Company’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Company. (14) PUBLIC EQUITY OFFERING In May 2007, the Company completed a public offering of 1,380,000 common units at a price of $42.25 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 64.3% limited partnership interest in the Company. Total proceeds from the sale of the 1,380,000 common units, net of underwriters’ discounts, commissions and offering expenses were $55,933. The General Partner contributed $1,190 in cash to the Company in conjunction with the issuance in order to maintain its 2% general partner interest in the Company. The net proceeds were used to pay down revolving debt under the Company’s credit facility and to provide working capital. A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows (all amounts are in thousands): Proceeds received: Sale of common units ........................................................................................... General partner contribution ................................................................................. Total proceeds received................................................................................. $ 58,305 1,190 $ 59,495 Use of Proceeds: Underwriter’s fees ................................................................................................ Professional fees and other costs .......................................................................... Repayment of debt under revolving credit facility ............................................... Working capital .................................................................................................... Total use of proceeds ..................................................................................... $ 2,107 265 55,850 1,273 $ 59,495 (15) HURRICANE DAMAGE During the third quarter of 2008, several of the Company’s facilities in the Gulf of Mexico were in the path of two major hurricanes, Hurricane Gustav and Hurricane Ike. Physical damage to the Company’s assets caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a deductible. Losses incurred as a result of a single hurricane (an “occurrence”) are limited to a maximum aggregate deductible of 19 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) $250 for flood damage and $1,000 minimum plus 2% of total insured value at each location for wind damage. The Company’s total flood coverage is $15,000 and total wind coverage is $100,000. The most significant damage to the Company’s assets was sustained at the Neches location. Property damage also occurred at the Company’s Galveston, Sabine Pass, Intracoastal City, Cameron East, Cameron West, Freeport, Venice, Port Fourchon, Stanolind, Mont Belvieu, and Spindletop locations. Based on an analysis of the damage as performed by the Company has estimated its non-cash charge as $1,269 for all locations which is equal to the net-book value of the damaged assets. A receivable of $4,351 has been recorded for the expected insurance recovery equal to the impairment charge and for all expenditures related to water damage less the fore mentioned deductible. This receivable was reduced by insurance proceeds received of $1,375. These insurance proceeds may exceed net book value of the Company’s assets determined to be impaired, which will result in the recognition of a gain equal to the amount of the excess. The Company recognized hurricane costs of $1,461 for the year ended December 31, 2008, which approximates the Company’s hurricane deductibles under its applicable insurance policies, incurred as a result of Hurricanes Gustav and Ike for the year ended December 31, 2008. The actual hurricane cost payments for the year ended December 31, 2008 were $949. (16) COMMITMENTS AND CONTINGENCIES As a result of a routine inspection by the U.S. Coast Guard of the Company’s tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, the Company has been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two employees or Martin Resource Management who provide services to the Company were served with grand jury subpoenas during the fourth quarter of 2007. The Company is cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against the Company. In addition to the foregoing, from time to time, the Company 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 Company. On May 2, 2008, the Company received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management, the parent company of the General Partner. The Plaintiff and the Defendant are executive officers of Martin Resource Management and the General Partner, the Defendant is a director of both Martin Resource Management and the General Partner, and the Plaintiff is a director of Martin Resource Management. The lawsuit alleges that the Defendant breached a settlement agreement with the Plaintiff concerning certain Martin Resource Management matters and that the Defendant breached fiduciary duties allegedly owed to the Plaintiff in connection with their respective ownership and other positions with Martin Resource Management. The Company is not a party to the lawsuit and the lawsuit does not assert any claims (i) against the Company, (ii) concerning the Company’s governance or operations or (iii) against the Defendant with respect to his service as an officer or director of the General Partner. On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of the General Partner. The Company is not a party to this lawsuit, and it does not assert any claims (i) against the Company, (ii) concerning the Company’s governance or operations or (iii) against the MRMC Director Defendants or Other MRMC Defendants with respect to their service to the Company. 20 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares. The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, and who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached the fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, it should be noted that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the General Partner. Such action was taken as a result of the collective effect of Plaintiff’s recent activities, which the Board of Directors of Martin Resource Management determined were detrimental to both Martin Resource Management and the Company. The Plaintiff does not serve on any committees of the board of directors of the General Partner. The position on the board of directors of the General Partner vacated by the Plaintiff will be filled in accordance with the existing procedures for replacement of a departing director utilizing the Nominations Committee of the board of directors of the General Partner. 21 Distributable Cash Flow Reconciliation (in thousands) 2004 2005 2006 2007 2008 Net income $12,326 $13,880 $22,243 $ 24,939 $ 42,810 Adjustments to reconcile net income to distributable cash flow: Depreciation and amortization Amortization of deferred debt issue costs Deferred income taxes Distribution equivalents from unconsolidated entities Invested cash in unconsolidated entities 8,766 12,642 17,597 886 — 1,980 — 600 — 1,812 (322) 1,040 — 9,285 767 23,442 1,233 31,218 1,120 (149) (277) 12,812 1,338 11,450 2,793 Equity in earnings of unconsolidated entities (912) (1,591) (8,547) (10,941) (13,224) Non-cash mark-to-market on derivatives Non-cash hurricane costs (net of cash payments) — — (555) — (389) — 3,904 — (2,328) 512 Maintenance capital expenditures (5,182) (5,100) (7,732) (10,342) (15,004) Gain on disposition or sale of property, plant and equipment Gain on involuntary conversion of property, plant and equipment Repayment of debt Debt prepayment premium Other — — — — 162 — — (703) (144) — (3,125) (291) — 58 — 1,160 (159) — — — 46 (65) — — 39 Distributable Cash Flow $18,026 $21,133 $32,140 $ 45,579 $ 58,900 ...Isn’t Our... ...Isn’t Our... Company Information Company Information (cid:85) 17 marine terminal facilities and 6 inland terminal facilities located across the United States (cid:85) 17 marine terminal facilities and 6 inland terminal facilities located across the United States Gulf Coast with an aggregate storage capacity of 3.0 million barrels Gulf Coast with an aggregate storage capacity of 3.0 million barrels (cid:85) Ownership interests in over 669 miles of gathering and transmission pipelines located in the natural gas producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico (cid:85) Ownership interests in over 669 miles of gathering and transmission pipelines located in the natural gas producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico M I D S T R E A MP A R T N E R S M I D S T R E A MP A R T N E R S (cid:85) 50% ownership interest in a 265 million cubic feet per day natural gas processing plant located (cid:85) 50% ownership interest in a 265 million cubic feet per day natural gas processing plant located in East Texas in East Texas (cid:85) Over 2.1 million barrels of combined NGL storage capacity located in Louisiana, Mississippi (cid:85) Over 2.1 million barrels of combined NGL storage capacity located in Louisiana, Mississippi and Texas and Texas (cid:85) 42 inland marine tank barges, 18 inland push boats and 5 offshore tug barge units that (cid:85) 42 inland marine tank barges, 18 inland push boats and 5 offshore tug barge units that transport petroleum products and by-products primarily in the United States Gulf Coast region transport petroleum products and by-products primarily in the United States Gulf Coast region (cid:85) 2 sulfur prilling facilities with a combined 5,000 tons per day processing capacity located in (cid:85) 2 sulfur prilling facilities with a combined 5,000 tons per day processing capacity located in Stockton, California and Beaumont, Texas Stockton, California and Beaumont, Texas (cid:85) 6 sulfur-based fertilizer production plants, 1 sulfuric acid plant and 1 emulsified sulfur blend- ing plant located in Texas, Illinois and Utah with a combined production capacity of over 540 thousand tons per year (cid:85) 6 sulfur-based fertilizer production plants, 1 sulfuric acid plant and 1 emulsified sulfur blend- ing plant located in Texas, Illinois and Utah with a combined production capacity of over 540 thousand tons per year S S S S T T S S S S S S T S G G G G T G S G G G T G M S Terminalling and Storage Terminalling and Storage T Natural Gas Services Natural Gas Services G Marine Transportation Marine Transportation M Sulfur Services Sulfur Services S T T T S T M T T T T TT M G T T T G T T G S T M T T T T T T T T TT G G M G M T T T T T T M T S M T S T T M T T G T G T T T Company Information Company Information Principal Officers Principal Officers Martin Midstream GP LLC Martin Midstream GP LLC Board of Directors Board of Directors Martin Midstream GP LLC Martin Midstream GP LLC Corporate Offices Corporate Offices Martin Midstream GP LLC Martin Midstream GP LLC Ruben S. Martin Ruben S. Martin President President Chief Executive Officer Chief Executive Officer Robert D. Bondurant Executive Vice President Chief Financial Officer Robert D. Bondurant Executive Vice President Chief Financial Officer Donald R. Neumeyer Executive Vice President Chief Operating Officer Donald R. Neumeyer Executive Vice President Chief Operating Officer Wesley M. Skelton Executive Vice President Chief Administrative Officer Wesley M. Skelton Executive Vice President Chief Administrative Officer Ruben S. Martin Ruben S. Martin President President Chief Executive Officer Chief Executive Officer Martin Midstream GP LLC Martin Midstream GP LLC John R. Gaylord John R. Gaylord President President Jacintoport Terminal Company Jacintoport Terminal Company Howard R. Hackney Howard R. Hackney Director Director Texas Bank & Trust Texas Bank & Trust Federal Home Loan Bank of Dallas Federal Home Loan Bank of Dallas C. Scott Massey CPA C. Scott Massey, CPA LLC ManagerSandstone Ventures LLC C. Scott Massey CPA C. Scott Massey, CPA LLC ManagerSandstone Ventures LLC 4200 Stone Road Kilgore, Texas 75662 (903) 983-6200 4200 Stone Road Kilgore, Texas 75662 (903) 983-6200 Transfer Agent Transfer Agent BNY Mellon Shareowner Services 480 Washington Boulevard Jersey City, New Jersey 07310 (800) 301-0911 www.bnymellon.com/shareowner/isd BNY Mellon Shareowner Services 480 Washington Boulevard Jersey City, New Jersey 07310 (800) 301-0911 www.bnymellon.com/shareowner/isd Auditors Auditors KPMG LLP KPMG LLP 333 Texas Street 333 Texas Street Suite 1900 Suite 1900 Shreveport, Louisiana 71101 Shreveport, Louisiana 71101 Units Traded Units Traded NASDAQ Global Select Market Symbol: MMLP NASDAQ Global Select Market Symbol: MMLP Investor Information Investor Information Updated investor information on Updated investor information on the Company is available on our the Company is available on our website www.martinmidstream.com. website www.martinmidstream.com. Inquiries can also be sent to Inquiries can also be sent to info@martinmidstream.com. info@martinmidstream.com. m o c . s r o n n o c - n a r r u c . w w w / . c n I , s r o n n o C & n a r r u C y b d e n g i s e D m o c . s r o n n o c - n a r r u c . w w w / . c n I , s r o n n o C & n a r r u C y b d e n g i s e D 177523_Martin_CVR 3-4 177523_Martin_CVR 3-4 4/15/09 10:56:20 PM 4/15/09 10:56:20 PM M I D S T R E A MP A R T N E R S M I D S T R E A MP A R T N E R S M I D S T R E A MP A R T N E R S M I D S T R E A MP A R T N E R S M I D S T R E A MP A R T N E R S M I D S T R E A MP A R T N E R S M A R T I I N M D S T R E A M P A R T N E R S L . P . 2 0 0 8 A n n u a l R e p o r t M A R T I M A R T I I I N M D S T R E A M P A R T N E R S L N M D S T R E A M P A R T N E R S L . . P P . . 2 0 0 8 A n n u a l 2 0 0 8 A n n u a l R e p o r t R e p o r t 4200 Stone Road 4200 Stone Road 4200 Stone Road Kilgore, Texas 75662 Kilgore, Texas 75662 Kilgore, Texas 75662 903-983-6200 903-983-6200 903-983-6200 www.martinmidstream.com www.martinmidstream.com www.martinmidstream.com 2008 Annual Report 2008 Annual Report 2008 Annual Report Our Most Important Asset… Our Most Important Asset… Our Most Important Asset… 177523_Martin_CVR 1-2 177523_Martin_CVR 1-2 177523_Martin_CVR 1-2 4/15/09 10:56:18 PM 4/15/09 10:56:18 PM 4/15/09 10:56:18 PM 

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