Martin Midstream Partners
Annual Report 2007

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MARTIN MIDSTREAM PARTNERS Annual Report 2007 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 We have ownership interests in over 658 miles of gathering and transmission pipelines located in the natural gas producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast as well as a 250 million cubic feet per day natural gas processing plant located in East Texas. In addition to our natural gas gathering and processing business, we distribute, store and sell natural gas liquids utilizing our supply and storage facilities. These liquids are ultimately sold to propane retailers, refineries and industrial users in Texas and the Southeastern United States. Marine Transportation We own a fleet of 37 inland marine tank barges, 18 inland push boats and four offshore tug barge units that transport petroleum products and by-products primarily in the United States Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts. In addition, our marine segment manages our sulfur segment’s marine assets. Sulfur Services We process and distribute sulfur produced by oil refineries primarily located in the United States Gulf Coast region. We process molten sulfur into prilled sulfur under both fee-based volume contracts and buy/sell contracts at our facilities in California and Texas. We own and operate six sulfur-based fertilizer production plants and one emulsified sulfur blending plant that primarily manufacture sulfur-based fertilizer products for wholesale distributors and industrial users. In addition, we manufacture sulfuric acid which is used as a feedstock for many industrial and agricultural applications, including the manufacture of fertilizers. The petroleum products and by-products we collect, transport, store and distribute are produced by the independent oil and gas companies who often turn to third parties, such as us. Terminalling and Storage S S T S S S T G S G G G T Terminalling and Storage G Natural Gas Services M S Marine Transportation Sulfur Services T T T T T M T T G T G G M S T M T T TT G T T T T T T T M T S Natural Gas Services Marine Transportation Financial Highlights (in thousands, except per unit amounts) 2003 2004 2005 2006 2007 Total Assets Revenue Operating Income Adjusted EBITDA(1) Net Income Distributable Cash Flow(1) Distributions per Unit(2) $ 139,685 $ 188,332 $ 389,044 $ 457,461 $ 623,577 192,731 294,144 438,443 576,384 765,822 11,087 18,918 11,981 15,377 14,729 25,534 12,326 18,026 18,960 33,060 13,880 21,133 26,609 50,459 22,243 32,140 28,876 67,986 24,939 45,579 $ 2.00 $ 2.10 $ 2.19 $ 2.44 $ 2.60 (1) See Reconciliation on page following Form 10-K. (2) Actual distributions per unit. First quarter 2003 distribution assumes a full quarter distribution. $ 7 6 6 $ 5 7 6 $ 4 3 8 $ 2 9 4 $ 1 9 3 $ 6 8 . 0 $ 5 0 . 5 $ 3 3 . 1 $ 2 5 . 5 $ 1 8 . 9 $ 4 5 . 6 $ 3 2 . 1 $ 2 1 . 1 $ 1 8 . 0 $ 1 5 . 4 ’03 ’04 ’05 ’06 ’07 ’03 ’04 ’05 ’06 ’07 ’03 ’04 ’05 ’06 ’07 800000 700000 600000 500000 400000 300000 200000 100000 0 Revenue (in millions) $ 7 6 6 $ 5 7 6 $ 4 3 8 $ 2 9 4 $ 1 9 3 80000 70000 60000 50000 40000 30000 20000 10000 0 Adjusted EBITDA(1) (in millions) Distributable Cash Flow(1) (in millions) $ 6 7 . 9 $ 5 0 . 5 $ 3 3 . 1$ 2 5 . 5$ 1 8 . 9 $ 4 5 . 6 $ 3 2 . 1 $ 2 1 . 1 $ 1 8 . 0 $ 1 5 . 4 50000 40000 30000 20000 10000 0 Revenue (in millions) Adjusted EBITDA(1) (in millions) Distributable Cash Flow(1) (in millions) We operate primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the energy and petrochemical industries. Sulfur Services L E T T E R T O U N I T H O L D E R S Ruben S. Martin President and Chief Executive Officer To Our Partners: As in previous years, 2007 proved to be another successful year of growth and development for our partnership. The year was marked with many significant milestones, including our five-year anniversary as a publicly-traded company. Since our formation in October of 2002, we have developed into a unique, well-diversified company focused on providing services across the midstream energy value chain. Our market capitalization has grown from $135 million to approx- imately $500 million, while our annualized distributions have increased from $2.00 per unit to our most recently declared annualized distribution of $2.80 per unit. While it is true that we have not grown as rapidly as some of our peers over the past five years, we believe that our growth has been strategic and disciplined, with a focus on smart acquisitions and low- multiple organic growth. We continue to focus on this plan of long-term value creation for our unitholders. Furthermore, we continue to avoid higher multiple, non-strategic acquisitions. We believe this type of undisciplined growth ultimately leads to erosion of unitholder value, especially in the presence of systemic risk. As evidence of this risk, 2007 marked a turbulent year for master limited partnerships (MLPs) and for the financial markets in general. As an example, the Alerian MLP Index experienced a 17% increase during the first half of the year, followed up by a 9% decrease over the second half of the year. MMLP experienced similar volatility as evidenced by a 25% increase in unit price for the first half of 2007, followed by a 14% decline over the remainder of the year. And while MMLP’s unit price only slightly outperformed the Alerian MLP Index in 2007, we continued our consistent distribution growth with an 11% increase in our fourth quarter distribution when compared to the fourth quarter of 2006. As we continued our distribution growth throughout 2007, the oft-mentioned “credit crunch” deteriorated into a full-blown “credit crisis.” This resulted in significant liquidations of MLP hold- ings across the MLP universe of companies. Unfortunately, we were not immune to this trend. Despite this frustrating pattern, we believe it is shorter term in nature and is not unique to our Customer demand for our energy midstream services continues to grow. This growth provides opportunities to expand our infrastructure and earn attractive returns on our expansion through our organic growth projects. G R O W T H partnership. What is unique, however, is our proven track record of disciplined growth through diversification, strategic acquisitions and low-multiple organic growth projects. Diversification We believe we are one of the more diversified MLPs operating today. With our four segments, we operate along many links of the midstream energy value chain. Our business segments include Terminalling and Storage, Natural Gas Services, Marine Transportation and Sulfur Services. These segments allow us to provide energy and petrochemical companies with the transpor tation and logistics necessary to move and store their products. While each segment is dependent on underlying energy fundamentals, each segment has its own unique and independent factors that drive that particular business. This results in a diversification profile that we believe supports long-term, steady growth in our partnership. As you may recall, for the greater part of the last two years, we have been operating as five segments. In the fourth quarter of 2007 we combined the historical Sulfur and Fertilizer segments into one segment, the Sulfur Services segment. The major driver of this combination is that sulfur and its derivatives are a primary feedstock for our sulfur-based fertilizer products. With sulfur as the common denominator between the two historical segments, we have placed increased focus on maximizing the value of that sulfur through its highest and best use. To that end, we felt it was necessary to combine the two segments to more accurately reflect the way we run the two businesses. We believe this combination will have the added benefit of reduced segment volatility when compared to historical operations for each segment individually. Strategic Acquisitions As I mentioned previously, we are focused on pursuing only those acquisitions that are strategic in nature, with a primary focus on acquisitions that supplement our existing operations. Over the past two years, this strategy has become increasingly difficult to implement as acquisition multiples have expanded to double-digit levels. Despite this trend, however, we have stayed true to our strategy. As an example of this commitment, we acquired Woodlawn Pipeline Company and related assets in May 2007 for approximately $32.6 million. This gathering and processing system was a “bolt-on” acquisition that enhanced our existing East Texas natural gas gathering and processing footprint. This was a negotiated transaction based on existing relationships with the sellers that allowed us to avoid a bidding war often seen in auction We transport asphalt, fuel oil, gasoline, sulfur and other bulk liquids. We own a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products. W E L L P O S I T I O N E D processes. We have been extremely pleased with the performance of Woodlawn to date and look forward to a full year of operations in 2008. Organic Growth Projects As a result of the increasing multiples and competition for acquisitions, we have focused primarily on our organic growth plan over the last two years. In 2007, we spent over $100 million on various organic growth projects including our $25 million sulfuric acid plant which was completed in October. The sulfuric acid plant eliminates our reliance on third-party sulfuric acid to produce some of our sulfur-based fertilizers. With the combined effect of lower cost of sales and our ability to sell remaining product to outside parties, we expect the sulfuric acid plant to result in accretion to our unitholders. In addition to the sulfuric acid plant, we also completed our Waskom expansion in the second quarter, increasing our processing capacity from 150 million cubic feet per day to 250 million cubic feet per day. This expansion allows us to continue to take advantage of the prolific East Texas natural gas production base. As in previous years, many of our organic growth projects were not completed until late in the year, so we expect to benefit from a full year’s operations of these projects in 2008. In closing, I am pleased with our partnership’s growth and performance over the past year. Despite some challenges that have been out of our control, our diversified business model has performed well. We expect this trend to continue. To that end, we recently announced a $100 million organic growth plan for 2008 as evidence of our confidence in our businesses and the underlying fundamentals. Equally important, this investment represents the confidence in and commitment to our employees. Without their hard work and dedication, it is safe to say that we would not be discussing our outstanding growth over the first five years of our partnership. With their continued help, we will strive to make the next five even better. Yours truly, Ruben S. Martin President and Chief Executive Officer F O R M 1 0 - K TABLE OF CONTENTS Page PART I(cid:2) Business .................................................................................................................................................. 1(cid:2) Item 1.(cid:2) Item 1A.(cid:2) Risk Factors ......................................................................................................................................... 25(cid:2) Item 1B.(cid:2) Unresolved Staff Comments ................................................................................................................ 42(cid:2) Properties .............................................................................................................................................. 42(cid:2) Item 2. Legal Proceedings ................................................................................................................................ 42(cid:2) Item 3. Submission of Matters to a Vote of Security Holders .......................................................................... 43(cid:2) Item 4. PART II(cid:2) Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities ............................................................................................ 43(cid:2) Selected Financial Data ........................................................................................................................ 45(cid:2) Item 6.(cid:2) Item 7.(cid:2) Management’s Discussion and Analysis of Financial Condition and Results of Operations ............... 46(cid:2) Item 7A.(cid:2) Quantitative and Qualitative Disclosures about Market Risk .............................................................. 67(cid:2) Financial Statements and Supplementary Data .................................................................................... 69(cid:2) Item 8.(cid:2) Item 9.(cid:2) Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............. 105(cid:2) Item 9A.(cid:2) Controls and Procedures .....................................................................................................................105(cid:2) Item 9B.(cid:2) Other Information ...............................................................................................................................105(cid:2) PART III(cid:2) Item 10.(cid:2) Directors and Executive Officers of the Registrant ............................................................................ 106(cid:2) Executive Compensation .................................................................................................................... 110(cid:2) Item 11.(cid:2) Item 12.(cid:2) Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ........................................................................................... 116(cid:2) Item 13. Certain Relationships and Related Transactions ................................................................................ 118(cid:2) Item 14. Principal Accounting Fees and Services ............................................................................................. 126(cid:2) PART IV(cid:2) Item 15. Exhibits and Financial Statement Schedules ...................................................................................... 127(cid:2) i and 2005, 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%, 4% and 5% of our total revenues for the years ended December 31, 2007, 2006 and 2005, 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. Our Relationship with CF Martin Sulphur, L.P. On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin Sulphur from CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to this transaction, our unconsolidated non- controlling 49.5% limited partnership interest in CF Martin Sulphur, was accounted for using the equity method of accounting. In addition, on July 15, 2005, we acquired all of the outstanding membership interests in CF Martin Sulphur’s general partner. Subsequent to the acquisition, CF Martin Sulphur was a wholly owned partnership which is included in the consolidated financial presentation of our sulfur segment. Effective March 30, 2006, CF Martin Sulphur was merged into us. Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin Sulphur. We chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a guaranteed daily rate, subject to certain adjustments. This charter, which had an unlimited term, was terminated on November 18, 2005. CF Martin Sulphur paid to have this tug/barge tanker unit reconfigured to carry molten sulfur. In the event CF Martin Sulphur had terminated this charter agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such reconfiguration costs. As a result of the July 15, 2005 acquisition of all the outstanding interests in CF Martin Sulphur, this contingent obligation was terminated. Insurance Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance policies. Vessel operating liabilities such as collision, cargo, environmental and personal injury are insured primarily through our participation in mutual insurance associations and other reinsurance arrangements, pursuant to which we are potentially exposed to assessments in the event claims by us or other members exceed available funds and reinsurance. Protection and indemnity, or P&I, insurance coverage is provided by P&I associations and other insurance underwriters. Our vessels are entered in P&I associations that are parties to a pooling agreement, known as the International Group Pooling Agreement, or the Pooling Agreement, through which approximately 95% of the world’s commercial shipping tonnage is reinsured through a group reinsurance policy. With regard to collision coverage, the first $1.0 million of coverage is insured by our 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 - 20 - 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 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 - 22 - 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: (cid:120) 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:120) 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:120) Martin Resource Management may engage in limited competition with us. (cid:120) 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:120) 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:120) Our general partner determines which costs incurred by Martin Resource Management are reimbursable by us. (cid:120) 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:120) Our general partner controls the enforcement of obligations owed to us by Martin Resource Management. (cid:120) Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. (cid:120) (cid:120) 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:120) 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. - 40 - 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 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 - 41 - 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. Item 1B. Unresolved Staff Comments None. Item 2. Properties A description of our properties is contained in Item 1. Business. We believe we have satisfactory title to our assets. Some of the easements, rights-of-way, permits, licenses or similar documents relating to the use of the properties that have been transferred to us in connection with our initial public offering and the assets we acquired in our acquisitions, required the consent of third parties, which in some cases is a governmental entity. We believe we have obtained sufficient third-party consents, permits and authorizations for the transfer of assets necessary for us to operate our business in all material respects. With respect to any third-party consents, permits or authorizations that have not been obtained, we believe the failure to obtain these consents, permits or authorizations will not have a material adverse effect on the operation of our business. Title to our property may be subject to encumbrances, including liens in favor of our secured lender. We believe none of these encumbrances materially detract from the value of our properties or our interest in these properties, or materially interfere with their use in the operation of our business. Item 3. Legal Proceedings From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of our tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, we have been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two of our employees were served with grand jury subpoenas during the fourth quarter of 2007. We are cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against us. - 42 - Environmental Liabilities We have historically not experienced circumstances requiring us to account for environmental remediation obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other related environmental studies that we may elect to perform. We would record changes to our estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related eventual liability. Allowance for Doubtful Accounts In evaluating the collectibility of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and historical collection experience. Based on these assessments, we record both specific and general reserves for bad debts to reduce the related receivable to the amount we ultimately expect to collect from customers. Asset Retirement Obligation In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), we recognize and measure our asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset. Subsequent measurement and accounting provisions are in accordance with SFAS 143. On March 31, 2005, the Financial Accounting Standards Board issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143. FIN 47, which was effective for fiscal years ending after December 15, 2005, 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. 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 years 2003 and 2004. Since the reclassifications, as indicated in the tables set forth below, had no impact on the prior periods’ revenues, operating income, cash flows from operations or net income, 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 among the 2003-2004 annual periods when compared to our financial reporting for our current 2007 fiscal year. The following tables set forth the effects of the reclassifications on certain line items within our previously reported consolidated statements of income for the years ended December 31, 2004 and 2003 (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. Cost of products sold (as previously reported) Cost of products sold (as reclassified) Operating expenses (as previously reported) Operating expenses (as reclassified) Selling, general and administrative (as previously reported) Selling, general and administrative (as reclassified) Year Ended December 31, 2004 (In Thousands) Terminalling and Storage NGL Marine Sulfur Total $ 6,775 $ 197,859 $ — $ 25,207 $ 229,841 6,775 6,699 8,494 2,194 399 197,859 — 25,342 229,976 928 24,796 — 32,423 1,185 1,457 1,200 24,796 — 34,475 175 175 4,599 4,424 8,385 6,198 - 50 - Cost of products sold (as previously reported) Cost of products sold (as reclassified) Operating expenses (as previously reported) Operating expenses (as reclassified) Selling, general and administrative (as previously reported) Selling, general and administrative (as reclassified) Year Ended December 31, 2003 (In Thousands) Terminalling and Storage NGL Marine Sulfur Total $ 107 $ 128,055 $ — $ 22,605 $ 150,767 107 128,055 — 22,730 150,892 1,413 2,141 1,180 452 1,052 18,135 1,314 18,135 — — 1,362 1,100 305 305 3,254 3,129 20,600 21,590 6,101 4,986 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. Under the omnibus agreement, the reimbursement amount that we are required to pay to Martin Resource Management with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million. This cap expired on November 1, 2007. Effective January 1, 2008, the Conflicts Committee of our general partner approved a reimbursement amount for indirect expenses of $2.7 million for the year ending December 31, 2008 which is not expected to cover all of the indirect general and administrative and corporate overhead expenses attributable to the services provided to us. 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 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.” Our Relationship with CF Martin Sulphur, L.P. On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin Sulphur from CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to this transaction, our unconsolidated non- controlling 49.5% limited partnership interest in CF Martin Sulphur, was accounted for using the equity method of accounting. In addition, on July 15, 2005, we acquired all of the outstanding membership interests in CF Martin Sulphur’s general partner. Subsequent to the acquisition, CF Martin Sulphur was a wholly owned partnership which is included in the consolidated financial presentation of our sulfur services segment. Effective March 30, 2006, CF Martin Sulphur was merged into us. Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin Sulphur. We chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a guaranteed daily rate, subject to certain adjustments. This charter, which had an unlimited term, was terminated on November 18, 2005. CF Martin Sulphur paid to have this tug/barge tanker unit reconfigured to carry molten sulfur. In the event CF Martin Sulphur had terminated this charter agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such reconfiguration costs. As a result of the July 15, 2005 acquisition of all the outstanding interests in CF Martin Sulphur, this contingent obligation was terminated. - 51 - Results of Operations The results of operations for the twelve months ended December 31, 2007, 2006 and 2005 have been derived from our consolidated and condensed 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, 2007, 2006 and 2005. Operating Revenues Revenues Intersegment Eliminations Operating Revenues after Eliminations Operating Income (loss) (In thousands) Operating Income Intersegment Eliminations Operating Income (loss) after Eliminations 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) Total ............................................ $ 770,917 $ (5,095) $ 765,822 $ 28,876 $ — $ 28,876 Year ended December 31, 2006: Terminalling and storage ................. Natural gas services ......................... Marine transportation ...................... Sulfur services ................................. Indirect selling, general and administrative $ 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 Year ended December 31, 2005 Terminalling and storage ................. Natural gas services ......................... Marine transportation ...................... Sulfur services ................................. Indirect selling, general and administrative $ 32,962 301,676 37,724 68,418 — $ (64) — (2,273) — — $ 32,898 301,676 35,451 68,418 — $ 9,127 6,003 4,657 2,636 (3,463) $ 187 — (2,273) 2,086 — $ 9,314 6,003 2,384 4,722 (3,463) Total ............................................ $ 440,780 $ (2,337) $ 438,443 $ 18,960 $ — $ 18,960 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, 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. - 52 - 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. 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. Years Ended December 31, 2007 2006 (In thousands) 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 .............................................................................. $481,018 35,983 (3,104) (611) 2,706 515,992 $372,997 13,773 221 894 1,850 389,735 - 53 - 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 Other operating income ...................................................................... 716 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. 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. - 55 - 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 $102,646 76,372 14,283 2,651 4,621 $ 4,719 Sulfur Services Volumes (long tons) .................................................... 1,420.9 1,025.2 Revenues. Our sulfur services revenues increased $29.0 million, or 28%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was primarily a result of a 39% increase in sales volume. The sales volume increase was due to a new molten sulfur sales contract negotiated in 2007 and increased demand for our sulfur-based products, driven by higher agricultural commodity prices. Cost of products sold. Our cost of products sold increased $21.4 million, or 28%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This percentage increase was the same as our percentage increase in sales, as our margin per ton was approximately the same for both years. Operating expenses. Our operating expenses increased $2.8 million, or 19%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was a result of increased marine transportation costs relating to increased crew wages, outside towing expense incurred for leased vessels due to down time of vessels owned by the sulfur services segment and repairs and maintenance on vessels owned by the sulfur services segment to bring them up to higher quality standards adopted by our marine transportation group. Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.1 million, or 2%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 8%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This is attributable to our sulfuric acid facility coming online in the fourth quarter of 2007. In summary, our sulfur services operating income increased $4.5 million, or 95%, for the year ended December 31, 2007 compared to the year ended December 31, 2006 Statement of Operations Items as a Percentage of Revenues In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended December 31, 2007 and December 31, 2006. The following table summarizes, on a comparative basis, these items of our statement of operations as a percentage of our revenues. Years Ended December 31, 2007 2006 (In thousands) Revenues ................................................................................................. 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. - 56 - 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, 2007, we had $95.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan 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 $170.6 million to a high of $239.4 million. As of December 31, 2007, we had $99.9 million available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility. Our obligations under the credit facility are secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, marine vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees. We may prepay all amounts outstanding under this facility at any time without penalty. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 1.75%. Effective January 1, 2008, the applicable margin for existing borrowings will increase to 2.00%. As a result of our leverage ratio test as of December 31, 2007, effective April 1, 2008, the applicable margin for existing borrowings will remain at 2.00%. We incur a commitment fee on the unused portions of the credit facility. Effective September 2007, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed rate. The fixed rate cost is 4.605% plus our applicable LIBOR borrowing spread. This interest rate swap which 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. - 65 - 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, 2007, changes in the fair value of our derivative contracts were recorded both in earnings and comprehensive income since we have designated a portion of our derivative instruments as hedges as of December 31, 2007. 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 the commodity risk exposure of Prism Gas. In addition, we are focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the commodity derivative contracts include Shell Energy North America (US), L.P., Morgan Stanley Capital Group Inc. and Wachovia Bank. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, and have established a maximum credit limit threshold pursuant to our hedging policy and monitor the appropriateness of these limits on an ongoing basis. As a result of the Prism Gas acquisition, we are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales activities. Prism Gas gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (POL) and percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 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, ethane, iso butane, normal butane and natural gasoline. Based on estimated volumes, as of December 31, 2007, Prism Gas had hedged approximately 77%, 24%, and 17% of its commodity risk by volume for 2008, 2009, and 2010, respectively. As of December 31, 2007, commodity derivative assets of $235 were included in other current assets on the balance sheet. Commodity derivative liabilities of $3,261 were included in current liabilities and $2,140 were included in long-term liabilities on the balance sheet. We anticipate entering into additional commodity derivatives on an ongoing basis to manage risk associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that we will be able to do so or that the terms thereof will be similar to our existing hedging arrangements. In addition, we will enter into derivative arrangements that include the specific NGL products as well as natural gas and crude oil. Hedging Arrangements in Place As of December 31, 2007 Commodity Hedged Condensate & Natural Gasoline Year 2008 2008 Natural Gas 2008 Ethane 2008 Natural Gasoline 2008 Iso Butane 2008 Normal Butane 2008 Natural Gasoline 2008 Natural Gasoline 2009 Condensate & Natural Gasoline 2009 Natural Gasoline 2009 Condensate Type of Derivative Crude Oil Swap ($66.20) Volume 5,000 BBL/Month 30,000 MMBTU/Month Natural Gas Swap ($8.12) 5,000 BBL/Month 3,000 BBL/Month 1,000 BBL/Month 2,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 1,000 BBL/Month Basis Reference NYMEX Houston Ship Channel Mt. Belvieu Ethane Swap ($27.30) NYMEX Crude Oil Swap ($70.75) Mt. Belvieu (Non-TET) Iso Butane Swap ($75.90) Mt. Belvieu (Non-TET) Normal Butane Swap ($75.06) Natural Gasoline Swap ($87.31) Mt. Belvieu (Non-TET) Natural Gasoline Swap ($85.10) Mt. Belvieu (Non-TET) Crude Oil Swap ($69.08) Crude Oil Swap ($70.90) Crude Oil Swap ($70.45) NYMEX NYMEX NYMEX - 67 - 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, 2007 and 2006 .............................................................................. 72 Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005 .............................. 73 Consolidated Statements of Changes in Capital for the years ended December 31, 2007, 2006 and 2005 ................. 74 Consolidated Statements of Comprehensive Income for the years ended December 31, 2007 and 2006 ................... 75 Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005 ............................ 76 Notes to the Consolidated Financial Statements ......................................................................................................... 77 - 69 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Marine transportation ................................................................ 23,729 15,319 11,606 Product sales: Natural gas services ............................................................ Sulfur services .................................................................... Terminalling and storage ................................................... Costs and expenses: Cost of products sold: Natural gas services ............................................................ Sulfur services .................................................................... Terminalling and storage .................................................... Expenses: Operating expenses Marine transportation ......................................................... Natural gas services ............................................................ Sulfur services .................................................................... Terminalling and storage .................................................... Selling, general and administrative: Natural gas services ............................................................ Sulfur services .................................................................... Terminalling and storage .................................................... Indirect overhead allocation, net of reimbursement ........... 3,206 4,326 45 7,577 $ 43,122 $ 62,686 13,992 — $ 76,678 $ 20,891 1,538 1,234 5,328 $ 28,991 927 1,770 41 1,351 $ 4,089 (14) FINANCIAL INSTRUMENTS 1,303 24 59 1,386 $ 25,631 $ 52,030 11,913 1 $ 63,944 $ 20,051 1,560 928 3,931 $ 26,470 773 1,714 74 1,305 $ 3,866 44 229 5 278 $ 20,822 $ 15,827 9,843 31 $ 25,701 $ 15,746 1,236 295 3,485 $ 20,762 833 1,444 76 1,120 $ 3,473 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:120) 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:120) 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. (15) COMMODITY CASH FLOW HEDGES The Partnership is exposed to market risks associated with commodity prices, counterparty credit and interest rates. In connection with the acquisition of Prism Gas, the Partnership established a hedging policy and monitors and manages the commodity market risk associated with the commodity risk exposure of the Prism Gas acquisition. 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 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 - 95 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) Based on estimated volumes, as of December 31, 2007, Prism Gas had hedged approximately 77%, 24%, and 17% of its commodity risk by volume for 2008, 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. In addition, the Partnership will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil. Hedging Arrangements in Place As of December 31, 2007 Commodity Hedged Condensate & Natural Gasoline Year 2008 2008 Natural Gas 2008 Ethane 2008 Natural Gasoline 2008 Iso Butane 2008 Normal Butane 2008 Natural Gasoline 2008 Natural Gasoline 2009 Condensate & Natural Gasoline 2009 Natural Gasoline 2009 Condensate 2010 Condensate 2010 Natural Gasoline Type of Derivative Crude Oil Swap ($66.20) Volume 5,000 BBL/Month 30,000 MMBTU/Month Natural Gas Swap ($8.12) 5,000 BBL/Month 3,000 BBL/Month 1,000 BBL/Month 2,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 1,000 BBL/Month 2,000 BBL/Month 3,000 BBL/Month Basis Reference NYMEX Houston Ship Channel Mt. Belvieu Ethane Swap ($27.30) NYMEX Crude Oil Swap ($70.75) Mt. Belvieu (Non-TET) Iso Butane Swap ($75.90) Mt. Belvieu (Non-TET) Normal Butane Swap ($75.06) Natural Gasoline Swap ($87.31) Mt. Belvieu (Non-TET) Natural Gasoline Swap ($85.10) Mt. Belvieu (Non-TET) Crude Oil Swap ($69.08) Crude Oil Swap ($70.90) Crude Oil Swap ($70.45) Crude Oil Swap ($69.15) Crude Oil Swap ($72.25) NYMEX NYMEX 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, 2007 and 2006, net gains and losses on swap hedge contracts decreased crude revenue by $3,374 and increased crude revenue by $76, respectively. As of December 31, 2007 an unrealized derivative fair value loss of $1,880, related to cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). Fair value losses of $949, $190 and $741 are expected to be reclassified into earnings in 2008, 2009 and 2010, respectively. 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 For the years ended December 31, 2007 and 2006, net gains on swap hedge contracts increased gas revenue by $180 and $1,097, respectively. Natural Gas Liquids For the years ended December 31, 2007 and 2006, net losses on swap hedge contracts decreased liquids revenue by $521 and $58, respectively. As of December 31, 2007, an unrealized derivative fair value loss of $839 - 98 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) (17) GAIN ON INVOLUNTARY CONVERSION OF ASSETS During the third quarter of 2005, several of the Partnership’s facilities in the Gulf of Mexico were in the path of two major storms, Hurricane Katrina and Hurricane Rita. Physical damage to the Partnership’s assets caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a deductible. Losses incurred as a result of a single hurricane (an “occurrence”) are limited to a maximum aggregate deductible of $100 for flood damage and the greater of $100 or 2% of total insured value at each location for wind damage. The Partnership’s total flood coverage is $5,000 and total wind coverage is $40,000. The most significant damage to the Partnership’s assets was sustained at the Cameron East location. Property damage also occurred at the Partnership’s Sabine Pass, Venice, Intracoastal City, Port Fourchon, Galveston, Cameron West, Neches and Stanolind locations. Based on an analysis of the damage as performed by the Partnership and its insurance underwriters, the Partnership had estimated its non-cash impairment charge as $1,200 for all the locations which is equal to the net-book value of the damaged assets. A receivable was established for the expected insurance recovery equal to the impairment charge. The Partnership recognized a $700 estimated loss during the last half of 2005, which approximates the Partnership’s hurricane deductibles under its applicable insurance policies, incurred as a result of Hurricanes Katrina and Rita. The loss is included in “operating expenses” in the consolidated statement of operations for the year ended December 31, 2005. Insurance proceeds received as a result of the aforementioned claims 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. (18) 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 $35.4 million as of December 31, 2007. Effective January 1, 2007, the Partnership is 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 $118 for the year ended December 31, 2007. 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 $149 was recorded for the year ended December 31, 2007, and a deferred tax liability of $8,815 related to the basis differences existing at December 31, 2007. 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 current year 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 - 100 - MARTIN MIDSTREAM PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in Thousands) tax of $538 were recorded in current year income tax expense for the year ended December 31, 2007. There was no state income tax expense recorded for the year ended December 31, 2006. 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 year ended December 31, 2007 are as follows: Current: Federal ........................................................................ State ............................................................................ Deferred: Federal ....................................................................... Year Ended December 31, 2007 $ 274 519 $ 793 $ (149) $ 644 (19) COMMITMENTS AND CONTINGENCIES From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership. In addition to the foregoing, 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 of the Partnership’s employees 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. (20) BUSINESS SEGMENTS The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions. The accounting policies of the operating segments are the same as those described in Note 2 of the notes to consolidated financial statements. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense. Operating Revenues Intersegment Eliminations Operating Revenues After Eliminations Depreciation and Amortization Operating Income (Loss) after Eliminations Capital Expenditures Year ended December 31, 2007: Terminalling and storage ............... Natural gas services ....................... $ 59,790 515,992 $ (865) — $ 58,925 515,992 $ 6,358 3,252 $ 10,273 4,492 $ 26,023 4,090 - 101 - 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 5, 2008 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 5th day of March, 2008. Signature Title /s/ Ruben S. Martin Ruben S. Martin /s/ Robert D. Bondurant Robert D. Bondurant /s/ Wesley M. Skelton Wesley M. Skelton /s/ Scott D. Martin Scott D. Martin /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 Director of Martin Midstream GP LLC - 128 - Financial Statement Schedule Pursuant to Item 15(a)(2 Waskom Gas Processing Company Financial Statements as of and for the Years Ended December 31, 2007 and 2006, (with Independent Auditors’ Report Thereon) (cid:817)(cid:3)(cid:883)(cid:885)(cid:884)(cid:3)(cid:817)(cid:3) INDEPENDENT AUDITORS’ REPORT To the Partners of Waskom Gas Processing Company: We have audited the accompanying balance sheets of Waskom Gas Processing Company (the “Partnership”) as of December 31, 2007 and 2006 and the related statements of income, partners’ capital, and cash flows for the years then ended. 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 financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles. March 5, 2008 (cid:817)(cid:3)(cid:883)(cid:885)(cid:885)(cid:3)(cid:817)(cid:3) WASKOM GAS PROCESSING COMPANY BALANCE SHEETS AS OF DECEMBER 31, 2007 and 2006 2007 2006 Current Assets: Assets Cash ............................................................................................................. Accounts receivable..................................................................................... Accounts receivable - partners .................................................................... Inventories ................................................................................................... $ 265,786 613,648 9,775,681 433,273 $ 324,979 326,753 11,227,687 436,419 Total current assets ................................................................................... 11,088,388 12,315,838 Property and Equipment: Gas plant asset and gas gathering equipment .............................................. Other fixed assets ........................................................................................ Accumulated depreciation and amortization ............................................... Property and equipment, net ..................................................................... 67,931,309 584,747 (12,832,563) 55,683,493 51,331,046 564,736 (10,952,030) 40,943,752 $ 66,771,881 $ 53,259,590 Liabilities and Partners’ Capital Current Liabilities: Accounts payable and accrued liabilities ..................................................... Accounts payable–partners .......................................................................... Total current liabilities ............................................................................. $ 6,939,543 2,485,286 9,424,829 $ 5,916,140 1,706,545 7,622,685 Long-Term Liabilities-Asset retirement obligation ............................................ 197,740 186,989 Partners’ capital .................................................................................................. Commitments and contingencies 57,149,312 45,449,916 $ 66,771,881 $ 53,259,590 See accompanying notes to financial statements. (cid:817)(cid:3)(cid:883)(cid:885)(cid:886)(cid:3)(cid:817)(cid:3) WASKOM GAS PROCESSING COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006 2007 2006 Operating Revenues: Natural gas processing and other revenues ................................ Natural gas liquid sales .............................................................. Gain/(loss) on sale of assets ...................................................... Total operating revenues ..................................................... $ 25,462,143 56,494,167 (159,724) 81,796,586 $ 19,715,849 45,884,172 500 65,600,521 Operating Costs and Expenses: Cost of sales – natural gas liquids ............................................. Operating costs .......................................................................... Depreciation and amortization ................................................... Total operating costs and expenses .................................... 53,014,173 4,595,878 1,925,840 59,535,891 42,505,653 4,355,646 1,493,499 48,354,798 Operating income before taxes ........................................... 22,260,695 17,245,723 Income tax expense .......................................................................... 241,864 — Net income ........................................................................................ $ 22,018,831 $ 17,245,723 See accompanying notes to financial statements. (cid:817)(cid:3)(cid:883)(cid:885)(cid:887)(cid:3)(cid:817)(cid:3) WASKOM GAS PROCESSING COMPANY STATEMENTS OF PARTNERS’ CAPITAL FOR THE YEARS ENDED DECEMBER 31, 2007 and 2006 Total Partners’ Capital Balance – December 31, 2005 ................................................................................... $ 22,649,871 Cash contributions for capital expenditures .................................................... 19,980,733 Cash contributions for working capital ........................................................... Cash distributions .......................................................................................... 2,494,939 (300,000) Distributions in-kind ....................................................................................... (16,621,349) Net income ...................................................................................................... 17,245,723 Balance – December 31, 2006 ................................................................................... Cash contributions for capital expenditures .................................................... Cash distributions in excess of working capital .............................................. Cash distributions ........................................................................................... 45,449,916 17,733,619 (4,128,057) (5,250,000) Distributions in-kind ....................................................................................... (18,674,997) Net income ...................................................................................................... 22,018,831 Balance – December 31, 2007 ................................................................................... $ 57,149,312 See accompanying notes to financial statements. (cid:817)(cid:3)(cid:883)(cid:885)(cid:888)(cid:3)(cid:817)(cid:3) WASKOM GAS PROCESSING COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006 Cash flows from operating activities: Net income Adjustments to reconcile net income to net cash provided by (used in) operating activities: 2007 2006 $ 22,018,831 $ 17,245,723 Depreciation and amortization .......................................................................... Distributions in-kind to partners ........................................................................ Loss/(Gain) on sale of assets ............................................................................. Changes in operating assets and liabilities: 1,925,840 (18,674,997) 159,724 1,493,499 (16,621,349) (500) Accounts receivable ................................................................................... Accounts receivable – partners .................................................................. Inventory .................................................................................................... Accounts payable and accrued liabilities ................................................... Accounts payable – partners ...................................................................... (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 ............................. 8,399,799 (2,167,181) Cash flows from investing activities: Additions to gas plant and gathering system assets ................................................. Additions to other fixed assets ................................................................................. Proceeds from sale of assets .................................................................................... (16,809,743) (20,011) 15,200 (20,834,411) — 500 Net cash used in investing activities .................................................... (16,814,554) (20,833,911) Cash flows from financing activities: Contributions from partners ..................................................................................... Distributions to partners ........................................................................................... 17,733,619 (9,378,057) 22,475,672 (300,000) Net cash provided by financing activities ............................................ 8,355,562 22,175,672 Net decrease in cash .................................................................................................... (59,193) (825,420) Cash at beginning of period ............................................................................................ 324,979 1,150,399 Cash at end of period ...................................................................................................... $ 265,786 $ 324,979 Supplement Cash Flow Disclosures: Interest Paid .................................................................................................................... $ — $ — Taxes Paid ....................................................................................................................... $ — $ — See accompanying notes to financial statements. (cid:817)(cid:3)(cid:883)(cid:885)(cid:889)(cid:3)(cid:817)(cid:3) Waskom Gas Processing Company NOTES TO FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006 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, 2007 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 250 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 increasing the capacity from 150 MMcfd to 250 MMcfd. In January 2007 the Waskom fractionator was expanded to a capacity of 12,500 barrels per day from 9,500 barrels per day. In addition, an increase in the processing capacity of the plant to 265 MMcfd is expected to be completed by the end of the second quarter 2008. 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 72% of the 229 MMcfd of natural gas supplied for the year ended December 31, 2007 and 61% of the 183 MMcfd of natural gas supplied 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 NGLs 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 these contracts under profitable conditions. Sales of third party gas and fractionated NGLs are predominately to the partners and occur at the tailgate of the Plant. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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 $1,915,089 in 2007 and $1,483,332 in 2006. Repairs and maintenance are charged to operations as incurred. Renewals and betterments are capitalized. Inventories—Substantially all inventory at December 31, 2007 and 2006 represents pipe used for future projects. Such pipe was valued at acquisition cost. (cid:817)(cid:3)(cid:883)(cid:885)(cid:890)(cid:3)(cid:817)(cid:3) Waskom Gas Processing Company NOTES TO FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006 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 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 asset retirement obligations include purging, plugging and remediation costs. Accretion expense for 2007 and 2006 was $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. No conditional asset retirement obligations associated with the Partnership’s long-lived assets have been identified. 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 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 2007 was $241,864. 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 probably 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. (cid:817)(cid:3)(cid:883)(cid:885)(cid:891)(cid:3)(cid:817)(cid:3) Waskom Gas Processing Company NOTES TO FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006 Recently Issued Accounting Pronouncements— In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. However, on December 14, 2007, the FASB issued proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This proposed FSP partially defers the effective date of Statement 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. Effective for fiscal 2008, we will adopt SFAS 157 except as it applies to those nonfinancial assets and nonfinancial liabilities as noted in proposed FSP FAS 157-b. The partial adoption of SFAS 157 will not have a material impact on our consolidated financial position, results of operations or cash flows. 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. 3. RELATED-PARTY TRANSACTIONS During 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, 2007 and 2006, the Partnership had receivables of approximately $9.8 million and $11.2 million, respectively, and payables of approximately $2.5 million and $1.7 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 $17,733,619 and $19,980,733 for 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 totaled $4,128,057 in 2007. Other cash distributions totaled $5,250,000 and $300,000 for 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 $18,674,997 and $16,621,349 in 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 $53,365,845 and $43,678,571 in 2007 and 2006, respectively, and are included as natural gas liquid sales in the income statement. 4. 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 (cid:2)(cid:3)(cid:4)(cid:5)(cid:6)(cid:3)(cid:2)(cid:3) Waskom Gas Processing Company NOTES TO FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006 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 benefits. 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:4)(cid:5)(cid:4)(cid:3)(cid:2)(cid:3) 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)(cid:3)(cid:4)(cid:5)(cid:7)(cid:3)(cid:2)(cid:3) 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, (No. 333-117023) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our reports dated March 5, 2008, with respect to the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2007 and 2006, 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, 2007, and the effectiveness of internal control over financial reporting as of December 31, 2007, which reports appear in the December 31, 2007 annual report on Form 10-K of Martin Midstream Partners L.P. /s/ KPMG LLP Shreveport, Louisiana March 5, 2008 (cid:2)(cid:3)(cid:4)(cid:5)(cid:8)(cid:3)(cid:2)(cid:3) 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, (No. 333-117023) 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 5, 2008, with respect to the balance sheets of Waskom Gas Processing Company as of December 31, 2007 and 2006, and the related statements of income, partners’ capital, and cash flows for the years then ended which report appears in the December 31, 2007 annual report on Form 10-K of Martin Midstream Partners L.P. /s/ KPMG LLP Shreveport, Louisiana March 5, 2007 (cid:817)(cid:3)(cid:883)(cid:886)(cid:886)(cid:3)(cid:817)(cid:3) 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, (No. 333-117023) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our report dated March 5, 2008, with respect to the balance sheets of Martin Midstream GP LLC as of December 31, 2007 and 2006 which report appears as Exhibit 99.1 to the December 31, 2007 annual report on Form 10-K of Martin Midstream Partners L.P. /s/ KPMG LLP Shreveport, Louisiana March 5, 2008 (cid:817)(cid:3)(cid:883)(cid:886)(cid:887)(cid:3)(cid:817)(cid:3) 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. I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.; 2. 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 5, 2008 /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. (cid:817)(cid:3)(cid:883)(cid:886)(cid:888)(cid:3)(cid:817)(cid:3) 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. I have reviewed this annual report on Form 10-K of Martin Midstream Partners L.P.; 2. 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 5, 2008 /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. (cid:817)(cid:3)(cid:883)(cid:886)(cid:889)(cid:3)(cid:817)(cid:3) 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, 2007 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 5, 2008 *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.” (cid:817)(cid:3)(cid:883)(cid:886)(cid:890)(cid:3)(cid:817)(cid:3) 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, 2007 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 5, 2008 *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.” (cid:817)(cid:3)(cid:883)(cid:886)(cid:891)(cid:3)(cid:817)(cid:3) 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, 2007 and 2006. 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, 2007 and 2006, in conformity with U.S. generally accepted accounting principles. /s/ KPMG LLP Shreveport, Louisiana March 5, 2008 (cid:817)(cid:3)(cid:883)(cid:887)(cid:882)(cid:3)(cid:817)(cid:3) MARTIN MIDSTREAM GP LLC CONSOLIDATED BALANCE SHEETS (Dollars in thousands) December 31, 2007 December 31, 2006 Assets Cash ................................................................................................................... Accounts and other receivables, less allowance for doubtful accounts of $207 and $394 ............................................................................................ Product exchange receivables ............................................................................ Inventories ......................................................................................................... Due from affiliates ............................................................................................. Other current assets ........................................................................................... Total current assets ..................................................................................... Property, plant and equipment, at cost ............................................................... Accumulated depreciation ................................................................................. Property, plant and equipment, net ............................................................. Goodwill ............................................................................................................ Investment in unconsolidated entities ................................................................ 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 ......................................................................................... Other accrued liabilities ..................................................................................... Total current liabilities ............................................................................... Long-term debt .................................................................................................. Deferred income taxes ....................................................................................... Other long-term obligations ............................................................................... Total liabilities ............................................................................................ Minority interests ............................................................................................... Members’ equity ................................................................................................ Commitments and contingencies ....................................................................... $ 4,113 $ 3,303 88,039 10,912 51,798 2,325 819 158,006 441,117 (98,080) 343,037 56,712 7,076 33,019 1,330 2,049 103,489 323,967 (76,122) 247,845 37,405 75,690 9,439 $ 623,577 27,600 70,651 7,884 $ 457,469 $ 21 104,598 24,554 9,323 974 13,941 153,441 225,000 9,244 2,666 390,321 231,737 1,519 233,256 $ 74 53,450 14,737 12,612 — 3,876 84,749 174,021 — 2,626 261,396 195,354 719 196,073 $ 623,577 $ 457,469 See accompanying notes to the consolidated balance sheets. 1 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (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 Company 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. On November 10, 2005, the Company acquired 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”), the Matagorda Offshore Gathering System (“Matagorda”), and the Panther Interstate Pipeline Energy LLC (“Panther”) 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, 2007 and December 31, 2006. (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. 2 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (c) Inventories Inventories are stated at the lower of cost or market. Cost is determined by using the first-in, first-out 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 dividends. 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. (g) Goodwill and Other Intangible Assets Goodwill represents the excess of costs over fair value of net 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, Goodwill and Other Intangible Assets. 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 FASB Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible assets primarily 3 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS consists of covenants not-to-compete obtained through business combinations and are being amortized over the life of the respective agreements. (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 $4,324 and $3,091 at December 31, 2007 and 2006, respectively. The unamortized balance of debt issuance costs, classified as other assets amounted to $3,188 and $4,169 at December 31, 2007 and 2006, 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 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. Goodwill is tested annually for impairment, and is tested for impairment more frequently if events and circumstances indicate that the asset might be impaired. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value. This determination is made at the reporting unit level and consists of two steps. First, the Company determines the fair value of a reporting unit and compares it to its carrying amount. Second, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation, in accordance with FASB Statement No. 141, Business Combinations. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. The Company performed its annual test in the third quarters of 2007 and 2006 with no indication of impairment. (j) Asset Retirement Obligation Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143”), an Asset Retirement Obligation (“ARO”) which consists of costs associated with legal obligations to retire tangible, long-lived assets is recorded 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. Financial Accounting Standards Board 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. The Company’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment. The transportation equipment includes pipeline systems. 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 our pipeline systems, primarily in Texas and Louisiana to the fractionation facility of our 50% owned joint venture. The Company is obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, the Company is not able to 4 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS reasonably determine the fair value of the asset retirement obligations for our trunk and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate. In order to determine a removal date of our 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 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 our gathering assets will occur. With regard to our trunk pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, the Company can evaluate its 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 the Company to reasonably estimate the settlement dates of the retirement obligations. (k) Derivative Instruments and Hedging Activities Derivative Instruments and Hedging Activities—SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established accounting and reporting standards for derivative instruments and hedging activities. It requires that all derivatives be included on the balance sheet as an asset or liability measured at fair value and that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If such hedge accounting criteria are met, the change is deferred in shareholders’ equity as a component of accumulated other comprehensive income. The deferred items are recognized in the period the derivative contract is settled. As of December 31, 2007 and December 31, 2006, the Company has designated a portion of its derivative instruments as qualifying cash flow hedges. (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 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, 2007 and 2006, the General Partner 5 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS 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 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 $9,254 ($10 of which is included in accrued liabilities) and $419 ($12 of which is included in other accrued liabilities) at December 31, 2007 and December 31, 2006, 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, 2007, the Company has recorded a liability attributable to the Texas Margin tax of $538. 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, 6 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS 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. (2) ACQUISITIONS (a) 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. (b) 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 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. (c) 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. 7 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS 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 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. (d) 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. (e) 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. (f) 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. 8 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS Partnership to transport NGL for third parties as well as its own account, spans approximately 200 miles, running from Kilgore to Beaumont in Texas. The acquisition was financed through the Partnership’s credit facility (see Note 11). (4) INVENTORIES Components of inventories at December 31, 2007 and 2006 were as follows: Natural gas liquids ........................................................................................ Sulfur ............................................................................................................ Sulfur-based fertilizer products ..................................................................... Lubricants ..................................................................................................... Other ............................................................................................................. 2007 $31,283 7,490 6,626 5,345 1,054 $51,798 2006 $17,061 4,425 7,191 2,592 1,750 $33,019 (5) PROPERTY, PLANT AND EQUIPMENT At December 31, 2007 and 2006, property, plant, and equipment consisted of the following: Depreciable Lives 2007 2006 Land ................................................................. Improvements to land and buildings ............... Transportation equipment ................................ Storage equipment ........................................... Marine vessels ................................................. Operating equipment ....................................... Furniture, fixtures and other equipment ........... Construction in progress .................................. — 10-39 years 3- 7 years 5-20 years 4-30 years 3-30 years 3-20 years $ 14,515 34,585 616 38,652 147,627 172,282 1,542 31,298 $441,117 $ 12,559 26,868 531 22,343 124,323 103,929 1,450 31,964 $323,967 (6) GOODWILL AND OTHER INTANGIBLE ASSETS The following information relates to goodwill balances as of the periods presented: Carrying amount of goodwill: Terminalling and storage ................................................................. Natural gas services ......................................................................... Marine transportation ....................................................................... Sulfur services ................................................................................. December 31, December 31, 2007 2006 $ 1,020 29,010 2,026 5,349 $37,405 $ --- 20,225 2,026 5,349 $27,600 The following information relates to covenants not-to-compete as of the periods presented: 9 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS Covenants not-to-compete: Terminalling and storage ..................................................................... Natural gas services ............................................................................. Sulfur services ..................................................................................... Less accumulated amortization ............................................................ December 31, December 31, 2007 2006 $ 1,928 640 790 3,358 1,610 $ 1,748 $ 1,561 600 790 2,951 877 $ 2,074 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. (7) RELATED PARTY TRANSACTIONS Amounts due to and due from affiliates in the consolidated balance sheets as of December 31, 2007 (unaudited) and December 31, 2006, 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. (8) INVESTMENT IN UNCONSOLIDATED COMPANIES AND JOINT VENTURES The Company, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom, Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). Each of these interests is accounted for under the equity method of accounting. On June 30, 2006, the Company, through its Prism Gas subsidiary, acquired a 20% ownership interest in a Company for approximately $196, which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). BCP is an approximate 67 mile pipeline located in the Barnett Shale extension. The pipeline traverses four counties with the most concentrated drilling occurring in Bosque County. BCP is operated by Panther Pipeline Ltd. who is the 42.5% interest owner. This interest is accounted for under the equity method of accounting. In accounting for the acquisition of the interests in Waskom, Matagorda and Fishhook, 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. The remaining unamortized excess investment relating to property and equipment was $10,685 and $11,279 at December 31, 2007 and 2006, 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 2007 or 2006. As a partner in Waskom, the Company receives distributions in kind of natural gas liquids that are retained according to Waskom’s contracts with certain producers. The natural gas liquids 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. 10 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS Activity related to these investment accounts is as follows: Waskom PIPE Matagorda BCP Total Investment in unconsolidated entities, December 31, 2005 54,087 1,723 4,069 — 59,879 Acquisition of interests ........................................................ Distributions in kind ............................................................. Cash contributions ................................................................ Cash distributions ................................................................. Equity in earnings: Equity in earnings from operations ................................. Amortization of excess investment ................................. — (8,311) 11,238 (150) — — — (214) — — — (610) 196 — 76 — 196 (8,311) 11,314 (974) 8,623 (550) 224 (15) 356 (29) (62) — 9,141 (594) Investment in unconsolidated entities, December 31, 2006 $ 64,937 $ 1,718 $ 3,786 $ 210 $ 70,651 Distributions in kind ............................................................. Cash contributions ................................................................ Cash distributions ................................................................. Equity in earnings: Equity in earnings from operations ................................. Amortization of excess investment ................................. (9,337) 6,803 (2,625) — — (635) — — (215) — 107 — (9,337) 6,910 (3,475) 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 Select financial information for significant unconsolidated equity method investees is as follows: 2007 Waskom ................................................................................... $ 66,772 $ — $ 57,149 $ 81,797 $ 22,019 Total Assets Long- Term Debt Partner’s Capital Revenues Net Income (Loss) 2006 Waskom ................................................................................... $ 53,260 $ — $ 45,450 $ 65,600 $ 17,246 2005 Waskom (November 10 – December 31) ............................... CF Martin (January 1 – July 15) ............................................. $ 28,369 — $ 28,369 $ — $ 22,650 $ 9,165 $ 2,559 — — 33,900 (120) $ — $ 22,650 $ 43,065 $ 2,439 As of December 31, 2007 and 2006, the Company’s interest in cash of the unconsolidated equity method investees is $1,018 and $767, respectively. (9) LONG-TERM DEBT At December 31, 2007 and December 31, 2006, long-term debt consisted of the following: **$195,000 Revolving loan facility at variable interest rate (6.57%* weighted average at December 31, 2007), 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 .................................. $ 95,000 $ 44,000 December 31, 2007 December 31, 2006 11 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS ***$130,000 Term loan facility at variable interest rate (6.99%* at December 31, 2007), 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 .................................................................................. 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 21 225,021 21 $225,000 95 174,095 74 $174,021 *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 borrowings is 1.75%. Effective January 1, 2008, the applicable margin for existing borrowings will increase to 2.00%. As a result of our leverage ratio test as of December 31, 2007, effective April 1, 2008, the applicable margin for existing borrowings will remain at 2.00%. The Company incurs a commitment fee on the unused portions of the credit facility. ** 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 August 18, 2006, the Company purchased certain terminalling assets and assumed associated long term debt of $113 with a fixed rate cost of 7.25%. 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, 2007, the Company had $95,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of December 31, 2007, the Company had $99,880 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. 12 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS 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 (x) 5.5 to 1.0 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter thereafter. The Company was in compliance with the debt covenants contained in credit facility for the years ended December 31, 2007 and 2006. 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, 2007. 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 $170,600 to a high of $239,400. As of December 31, 2007, the Company had $99,880 available for working capital, internal expansion and acquisition activities under the Company’s credit facility. On July 15, 2005, the Company assumed $9,400 of U.S. Government Guaranteed Ship Financing Bonds, maturing in 2021, relating to the acquisition of CF Martin Sulphur L.P. (“CF Martin Sulphur”). The outstanding balance as of December 31, 2005 was $9,104. These bonds were payable in equal semi-annual installments of $291, and were secured by certain marine vessels owned by CF Martin Sulphur. Pursuant to the terms of an amendment to the Company’s credit facility that it entered into in connection with the acquisition of CF Martin Sulphur, the Company was obligated to repay these bonds by March 31, 2006. The Company redeemed these bonds on March 6, 2006 with available cash and borrowings from its credit facility. Also, at redemption, a pre-payment premium was paid in the amount of $1,160. 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. 13 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS In connection with the Company’s Woodlawn acquisition on May 2, 2007, the Company borrowed approximately $33,000 under its revolving credit facility. (10) INTEREST RATE CASH FLOW HEDGES In September 2007, the Company entered into a cash flow hedge agreement with a notional amount of $25,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate term loan credit facility. This interest rate swap matures in September 2010. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 4.605% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is 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 the hedge, the swap was 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 the swap remain equal. This condition results in a 100% effective swap. In April, 2006, the Company entered into a cash flow hedge agreement with a notional amount of $75,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate term loan credit facility. This interest rate swap matures in November 2010. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 5.25% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is 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 the hedge, the swap was 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 the swap remain equal. This condition results in a 100% effective swap. In December 2006, the Company entered into a cash flow hedge agreement with a notional amount of $40,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facility. This interest rate swap matures in December 2009. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 4.82% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is 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 the hedge, the swap was 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 the swap remain equal. This condition results in a 100% effective swap. 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, 2006 with an offset to current operations. The total fair value of the interest rate swaps agreement was a liability of approximately $4,677 at December 31, 2007. The fair value of derivative liabilities is as follows: Fair value of derivative liabilities — current ........................................ Fair value of derivative liabilities — long term ................................... Net fair value of derivatives ................................................................. December 31, 2007 $ (1,241) (3,436) $ (4,677) 14 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS (11) COMMODITY CASH FLOW HEDGES The Company is exposed to market risks associated with commodity prices, counterparty credit and interest rates. However, in connection with the acquisition of Prism Gas, the Company has established a hedging policy and monitors and manages the commodity market risk associated with the commodity risk exposure of the Prism Gas acquisition. 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. 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 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 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 other comprehensive income until such time as the hedged item is recognized in earnings. In early 2006, the Company 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, 2007, 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, 2007 2006 $ 235 — (3,261) (2,140) $ (5,166) $ 882 221 — (74) $1,029 Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2007 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of December 31, 2007, 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, 2007, changes in the fair value of the Company’s derivative contracts were recorded in both earnings and in 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, 2007. Transaction Type Total Volume Per Month Mark to Market Derivatives:: December 31, 2007 Pricing Terms Remaining Terms of Contracts Fair Value Natural Gas swap Fixed price of $8.12 settled against 30,000 MMBTU Houston Ship Channel first of the month 15 January 2008 to December 2008 235 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS Crude Oil Swap 3,000 BBL Fixed price of $70.75 settled against WTI NYMEX average monthly closings 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 Total swaps not designated as cash flow hedges Cash Flow Hedges: Crude Oil Swap 5,000 BBL Fixed price of $66.20 settled against WTI NYMEX average monthly closings Ethane Swap 5,000 BBL Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings January 2008 to December 2008 January 2009 to December 2009 January 2009 to December 2009 January 2008 to December 2008 January 2008 to December 2008 Iso butane Swap 1,000 BBL Fixed price of $75.90 settled against Mt. Belvieu Non-TET Iso butane average monthly postings January 2008 to March 2008 Normal Butane Swap 2,000 BBL Fixed price of $75.06 settled against Mt. Belvieu Non-TET normal butane average monthly postings January 2008 to March 2008 Natural Gasoline Swap 3,000 BBL Fixed price of $87.31 (Jan-Mar) and $85.10 (Apr-June) settled against Mt. Belvieu Non-TET natural gasoline average monthly postings. January 2008 to June 2008 Crude Oil Swap 1,000 BBL Fixed price of $70.45 settled against WTI NYMEX average monthly closings Crude Oil Swap 2,000 BBL Fixed price of $69.15 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 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 (810) (628) (569) $ (1,772) (1,612) (773) (9) (19) (38) (194) (337) (412) $ (3,394) $ (5,166) 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. As a result of the Prism Gas acquisition, 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. Prism Gas gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (POL) and percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 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, ethane, iso butane, normal butane and natural gasoline. 16 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS Based on estimated volumes, as of December 31, 2007, Prism Gas had hedged approximately 77%, 24%, and 17% of its commodity risk by volume for 2008, 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. In addition, the Company will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil. Hedging Arrangements in Place As of December 31, 2007 Commodity Hedged Condensate & Natural Gasoline Year 2008 2008 Natural Gas 2008 Ethane 2008 Natural Gasoline 2008 Iso Butane 2008 Normal Butane 2008 Natural Gasoline 2008 Natural Gasoline 2009 Condensate & Natural Gasoline 2009 Natural Gasoline 2009 Condensate 2010 Condensate 2010 Natural Gasoline Type of Derivative Crude Oil Swap ($66.20) Volume 5,000 BBL/Month 30,000 MMBTU/Month Natural Gas Swap ($8.12) 5,000 BBL/Month 3,000 BBL/Month 1,000 BBL/Month 2,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 3,000 BBL/Month 1,000 BBL/Month 2,000 BBL/Month 3,000 BBL/Month Basis Reference NYMEX Houston Ship Channel Mt. Belvieu Ethane Swap ($27.30) NYMEX Crude Oil Swap ($70.75) Mt. Belvieu (Non-TET) Iso Butane Swap ($75.90) Mt. Belvieu (Non-TET) Normal Butane Swap ($75.06) Natural Gasoline Swap ($87.31) Mt. Belvieu (Non-TET) Natural Gasoline Swap ($85.10) Mt. Belvieu (Non-TET) Crude Oil Swap ($69.08) Crude Oil Swap ($70.90) Crude Oil Swap ($70.45) Crude Oil Swap ($69.15) Crude Oil Swap ($72.25) NYMEX NYMEX 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 continuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Company. (12) 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 17 MARTIN MIDSTREAM GP LLC NOTES TO CONSOLIDATED BALANCE SHEETS 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 (13) COMMITMENTS AND CONTINGENCIES 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. 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. 18 Adjusted EBITDA Reconciliation (in thousands) 2003 2004 2005 2006 2007 Net income $ 11,981 $ 12,326 $ 13,880 $ 22,243 $ 24,939 Adjustments to reconcile net income to adjusted EBITDA: Interest expense Debt prepayment premium Equity in earnings of unconsolidated entities Depreciation and amortization EBITDA Distributions in-kind from equity investments Distributions from unconsolidated entities Return of investments from unconsolidated entities Non-cash derivatives (gain) loss (Gain) Loss on disposition or sale of property, plant and equipment 2,001 3,326 6,909 12,466 14,533 — (2,801) 4,765 — — 1,160 — (912) (1,591) (8,547) (10,941) 8,766 12,642 17,597 23,442 $ 15,946 $ 23,506 $ 31,840 $ 44,919 $ 51,973 — 3,564 — — (3) — — 1,980 — 48 — 1,115 8,311 231 466 (555) (37) — 541 433 (389) (231) (3,125) 9,337 1,523 1,952 3,904 (703) — (Gain) Loss on involuntary conversion of property, plant and equipment (589) Adjusted EBITDA $ 18,918 $ 25,534 $ 33,060 $ 50,459 $ 67,986 Distributable Cash Flow Reconciliation (in thousands) Net income $ 11,981 $ 12,326 $ 13,880 $ 22,243 $ 24,939 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 4,765 8,766 12,642 17,597 23,442 486 — 886 — 3,564 1,980 — — 600 — 1,812 (322) 1,040 — 9,285 767 1,233 (149) 12,812 1,338 Equity in earnings of unconsolidated entities (2,801) (912) (1,591) (8,547) (10,941) Non-cash derivatives (gain) loss — — (555) (389) 3,904 Maintenance capital expenditures, excluding hurricane-related items (2,773) (5,182) (5,100) (7,732) (10,342) (Gain) Loss on disposition or sale of property, plant and equipment — (Gain) Loss on involuntary conversion of property, plant and equipment (589) — — — — — 162 — — (291) — — 58 — (703) (3,125) — 1,160 — (159) — — — — 46 — — 744 — $ 15,377 $ 18,026 $ 21,133 $ 32,140 $ 45,579 Repayment of debt Debt prepayment premium Insurance proceeds Other Distributable Cash Flow Principal Officers Martin Midstream GP LLC Board of Directors Martin Midstream GP LLC Corporate Offices Martin Midstream GP LLC Ruben S. Martin President Chief Executive Officer Robert D. Bondurant Executive Vice President Chief Financial Officer Donald R. Neumeyer Executive Vice President Chief Operating Officer Wesley M. Skelton Executive Vice President Chief Administrative Officer Scott D. Martin Executive Vice President 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 Ruben S. Martin President Chief Executive Officer Martin Midstream GP LLC Scott D. Martin Executive Vice President Martin Midstream GP LLC John R. Gaylord President Jacintoport Terminal Company Howard R. Hackney Director Texas Bank & Trust Federal Home Loan Bank of Dallas C. Scott Massey CPA C. Scott Massey, CPA LLC Manager Sandstone Ventures LLC 4200 Stone Road Kilgore, Texas 75662 (903) 983-6200 Transfer Agent BNY Mellon Shareowner Services 480 Washington Boulevard Jersey City, New Jersey 07310 (800) 301-0911 www.bnymellon.com/shareowner/isd Auditors KPMG LLP 333 Texas Street Suite 1900 Shreveport, Louisiana 71101 Units Traded NASDAQ Global Select Market Symbol: MMLP Investor Information Updated investor information on the Company is available on our website www.martinmidstream.com. Inquiries can also be sent to info@martinmidstream.com. 4200 Stone Road Kilgore, Texas 75662 903-983-6200 www.martinmidstream.com

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