UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

o		TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)

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

4200 Stone Road
Kilgore, Texas 75662
(Address of principal executive offices, zip code)

Registrant’s telephone number, including area code: (903) 983-6200

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

Yes þ     No o

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

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

Yes o     No þ

          The number of the registrant’s Common Units outstanding at November 6, 2008 was 12,837,480. The number of the registrant’s subordinated units outstanding at November 6, 2008 was 1,701,346.

 

 

				Page
PART I — FINANCIAL INFORMATION					1
Item 1.		Financial Statements			1
		Consolidated and Condensed Balance Sheets as of September 30, 2008 (unaudited) and December 31, 2007 (audited)			1
		Consolidated and Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2008 and 2007 (unaudited)			2
		Consolidated and Condensed Statements of Capital for the Three and Nine Months Ended September 30, 2008 and 2007 (unaudited)			3
		Consolidated and Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2008 and 2007 (unaudited)			4
		Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007 (unaudited)			5
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Item 3.		Quantitative and Qualitative Disclosures about Market Risk			46
Item 4.		Controls and Procedures			47
PART II. OTHER INFORMATION					48
Item 1.		Legal Procedings			48
Item 1A.		Risk Factors			48
Item 5.		Other Information			48
Item 6.		Exhibits			48
SIGNATURE CERTIFICATIONS
EX-10.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands)

		September 30,				December 31,
		2008				2007
		(Unaudited)				(Audited)
Assets
Cash		$	7,019			$	4,113
Accounts and other receivables, less allowance for doubtful accounts of $392 and $211, respectively			105,334				88,039
Product exchange receivables			32,323				10,912
Inventories			78,002				51,798
Due from affiliates			7,929				2,325
Fair value of derivatives			354				235
Other current assets			2,132				584
Total current assets			233,093				158,006
Property, plant and equipment, at cost			516,420				441,117
Accumulated depreciation			(117,752	)			(98,080	)
Property, plant and equipment, net			398,668				343,037
Goodwill			37,405				37,405
Investment in unconsolidated entities			79,687				75,690
Fair value of derivatives			159				—
Other assets, net			8,006				9,439
		$	757,018			$	623,577
Liabilities and Partners’ Capital
Current installments of long-term debt		$	—			$	21
Trade and other accounts payable			158,904				104,598
Product exchange payables			47,298				24,554
Due to affiliates			17,500				7,543
Income taxes payable			398				602
Fair value of derivatives			5,657				4,502
Other accrued liabilities			5,711				4,752
Total current liabilities			235,468				146,572
Long-term debt			280,000				225,000
Deferred income taxes			8,593				8,815
Fair value of derivatives			4,933				5,576
Other long-term obligations			1,716				1,766
Total liabilities			530,710				387,729
Partners’ capital			234,803				242,610
Accumulated other comprehensive income (loss)			(8,495	)			(6,762	)
Total partners’ capital			226,308				235,848
Commitments and contingencies
		$	757,018			$	623,577

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars in thousands, except per unit amounts)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Revenues:
Terminalling and storage		$	8,527			$	7,570			$	26,347			$	21,558
Marine transportation			20,116				15,469				55,828				44,507
Product sales:
Natural gas services			188,200				120,994				577,317				328,103
Sulfur services			133,276				29,866				289,528				89,599
Terminalling and storage			14,267				10,951				36,525				19,193
			335,743				161,811				903,370				436,895
Total revenues			364,386				184,850				985,545				502,960
Costs and expenses:
Cost of products sold:
Natural gas services			178,996				115,112				562,170				312,823
Sulfur services			121,158				22,515				253,462				66,732
Terminalling and storage			11,031				10,004				31,222				16,936
			311,185				147,631				846,854				396,491
Expenses:
Operating expenses			26,093				21,528				76,505				61,184
Selling, general and administrative			3,726				2,890				10,672				8,355
Depreciation and amortization			7,979				6,236				22,933				16,598
Total costs and expenses			348,983				178,285				956,964				482,628
Other operating income (loss)			17				—				143				—
Operating income			15,420				6,565				28,724				20,332
Other income (expense):
Equity in earnings of unconsolidated entities			3,503				2,736				11,385				7,204
Interest expense			(4,971	)			(3,640	)			(13,609	)			(9,956	)
Other, net			87				54				334				205
Total other income (expense)			(1,381	)			(850	)			(1,890	)			(2,547	)
Net income before taxes			14,039				5,715				26,834				17,785
Income tax benefit (expense)			(292	)			(212	)			(753	)			(552	)
Net income		$	13,747			$	5,503			$	26,081			$	17,233
General partner’s interest in net income		$	941			$	465			$	2,257			$	1,094
Limited partners’ interest in net income		$	12,806			$	5,038			$	23,824			$	16,139
Net income per limited partner unit — basic and diluted		$	0.88			$	0.35			$	1.64			$	1.17
Weighted average limited partner units — basic			14,532,826				14,532,826				14,532,826				13,845,573
Weighted average limited partner units — diluted			14,534,972				14,536,939				14,535,025				13,849,749

     See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL
(Unaudited)
(Dollars in thousands)

		Partners’ Capital
																						Accumulated
																						Other
																		General				Comprehensive
		Common								Subordinated								Partner				Income
		Units				Amount				Units				Amount				Amount				Amount				Total
Balances — January 1, 2007			10,603,808			$	201,387				2,552,018			$	(6,237	)		$	3,253			$	122			$	198,525
Net Income			—				13,454				—				2,685				1,094				—				17,233
Follow-on public offering			1,380,000				55,933				—				—				—				—				55,933
General partner contribution			—				—				—				—				1,192				—				1,192
Cash distributions			—				(21,272	)			—				(4,900	)			(1,223	)			—				(27,395	)
Unit-based compensation			3,000				34				—				—				—				—				34
Adjustment in fair value of derivatives			—				—				—				—				—				( 2,172	)			(2,172	)
Balances — September 30, 2007			11,986,808			$	249,536				2,552,018			$	(8,452	)		$	4,316			$	(2,050	)		$	243,350
Balances — January 1, 2008			12,837,480			$	244,520				1,701,346			$	(6,022	)		$	4,112			$	(6,762	)		$	235,848
Net income			—				21,532				—				2,292				2,257				—				26,081
Cash distributions			—				(27,729	)			—				(3,675	)			(2,448	)			—				(33,852	)
Unit-based compensation			—				57				—				—				—				—				57
Purchase of treasury units			—				(93	)			—				—				—				—				(93	)
Adjustment in fair value of derivatives			—				—				—				—				—				(1,733	)			(1,733	)
Balances —September 30, 2008			12,837,480			$	238,287				1,701,346			$	(7,405	)		$	3,921			$	(8,495	)		$	226,308

     See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(Dollars in thousands)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Net income		$	13,747			$	5,503			$	26,081			$	17,233
Changes in fair values of commodity cash flow hedges			6,834				(543	)			(1,654	)			(900	)
Cash flow hedging gains (losses) reclassified to earnings			1,097				234				473				(198	)
Changes in fair value of interest rate cash flow hedges			(124	)			(2,056	)			(552	)			(1,074	)
Comprehensive income		$	21,554			$	3,138			$	24,348			$	15,061

     See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Dollars in thousands)

		Nine Months Ended
		September 30,
		2008				2007
Cash flows from operating activities:
Net income		$	26,081			$	17,233
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			22,933				16,598
Amortization of deferred debt issuance costs			840				810
Deferred taxes			(222	)			(111	)
Gain on sale of property, plant and equipment			(143	)			—
Equity in earnings of unconsolidated entities			(11,385	)			(7,204	)
Distributions from unconsolidated entities			—				673
Distributions in-kind from equity investments			8,392				6,628
Non-cash mark-to-market on derivatives			(1,499	)			2,036
Other			57				45
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables			(17,295	)			(4,899	)
Product exchange receivables			(21,411	)			(4,067	)
Inventories			(26,204	)			(6,346	)
Due from affiliates			(5,604	)			(1,787	)
Other current assets			(1,548	)			(167	)
Trade and other accounts payable			54,306				22,429
Product exchange payables			22,744				(2,388	)
Due to affiliates			9,957				(5,055	)
Income taxes payable			(204	)			365
Other accrued liabilities			959				903
Change in other non-current assets and liabilities			(111	)			(94	)
Net cash provided by operating activities			60,643				35,602
Cash flows from investing activities:
Payments for property, plant and equipment			(72,185	)			(57,524	)
Acquisitions, net of cash acquired			(5,983	)			(37,344	)
Proceeds from sale of property, plant and equipment			419				4
Return of investments from unconsolidated entities			995				2,642
Distributions from (contributions to) unconsolidated entities for operations			(1,999	)			(6,130	)
Net cash used in investing activities			(78,753	)			(98,352	)
Cash flows from financing activities:
Payments of long-term debt			(180,391	)			(125,105	)
Proceeds from long-term debt			235,370				161,050
Purchase of treasury units			(93	)			—
Net proceeds from follow on public offering			—				55,933
General partner contribution			—				1,192
Payments of debt issuance costs			(18	)			—
Cash distributions paid			(33,852	)			(27,395	)
Net cash provided by financing activities			21,016				65,675
Net increase in cash			2,906				2,925
Cash at beginning of period			4,113				3,675
Cash at end of period		$	7,019			$	6,600

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

(1)

General

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

          The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and U.S. generally accepted accounting principles for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by generally accepted accounting principles for annual audited financial statements of the type contained in the Partnership’s annual reports on Form 10-K. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for such interim periods are not necessarily indicative of the results of operations for the full year. These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2008.

(a)

Use of Estimates

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

(b)

Unit Grants

          The Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in May 2008 from treasury shares purchased by the Partnership in the open market for $93. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.

          The Partnership 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 Partnership 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 Partnership accounts for the transactions under Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based payment transactions was $24 and $8 for the three months ended September 30, 2008 and 2007, respectively, and $58 and $34 for the nine months ended September 30, 2008 and 2007, respectively. The Partnership’s general partner contributed cash of $2 in January 2006 and $3 in May 2007 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership. The Partnership’s general partner did not make a contribution attributable to the restricted units issued to its three independent, non-employee directors in May 2008, as such units were purchased in the open market by the Partnership for $93.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

(c)

Incentive Distribution Rights

          The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights in the Partnership. Incentive distribution rights represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the partnership agreement. The target distribution levels entitle the general partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months ended September 30, 2008 and 2007 the general partner received $680 and $362, respectively, in incentive distributions. For the nine months ended September 30, 2008 and 2007, the general partner received and $1,771 and $764, respectively, in incentive distributions.

(d)

Net Income per Unit

          Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest (including its incentive distribution in excess of its 2% interest) by the weighted average number of outstanding limited partner units during the period. Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06’’), “Participating Securities and the Two-Class Method under FASB Statement No. 128,’’ as discussed below, Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership.

          EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period where the Partnership’s aggregate net income exceeds the Partnership’s aggregate distribution for such period, the Partnership is required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF 03-06 does not impact the Partnership’s overall net income or other financial results; however, for periods in which aggregate net income exceeds the Partnership’s aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of the Partnership’s aggregate earnings is allocated to the incentive distribution rights held by the Partnership’s general partner, as if distributed, even though the Partnership makes cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed the Partnership’s aggregate distributions for such period, EITF 03-06 does not have any impact on the Partnership’s earnings per unit calculation.

          The weighted average units outstanding for basic net income per unit were 14,532,826 and 14,532,826 for the three months ended September 30, 2008 and 2007, respectively, and 14,532,826 and 13,845,573 for the nine months ended September 30, 2008 and 2007, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 2,146 and 4,113 for the three months ended September 30, 2008 and 2007, respectively, and 2,199 and 4,176 for the nine months ended September 30, 2008 and 2007, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(e)

Income taxes

          With respect to our taxable subsidiary (Woodlawn Pipeline Co., Inc.), income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

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.

(f)

Reclassification

          The Partnership made a reclassification to the consolidated balance sheet for the year ended December 31, 2007 to properly classify current and long-term derivative liabilities. This reclassification had no impact on the total liabilities reported in consolidated balance sheet for the year ended December 31, 2007.

(2)

New Accounting Pronouncements

          In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133” (SFAS No. 161). SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Partnership is evaluating the additional disclosures required by SFAS No. 161 beginning January 1, 2009.

          In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 is effective on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Partnership is currently evaluating the impact of adopting SFAS No. 160 on January 1, 2009.

          In December 2007, the FASB revised SFAS No. 141, “Business Combinations” (SFAS No. 141), to establish revised principles and requirements for how entities will recognize and measure assets and liabilities acquired in a business combination. SFAS No. 141 is effective for business combinations completed on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Partnership will apply the guidance of SFAS No. 141 to business combinations completed on or after January 1, 2009.

          In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Partnership to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Partnership would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Partnership currently has no plans to apply SFAS No. 159.

          In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) FAS 157-2, which delayed the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statement on a recurring basis, to fiscal years beginning after November 15, 2008. On January 1, 2008, the Partnership adopted the portion of SFAS No. 157 that was not delayed, and since the Partnership’s existing fair value measurements are consistent with the guidance of SFAS No. 157, the partial adoption of SFAS No. 157 did not have a material impact on the Partnership’s consolidated financial statements. The adoption of the deferred portion of SFAS No. 157 on January 1, 2009 is not expected to have a material impact on the

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

Partnership’s consolidated financial statements. See Note 3 for expanded disclosures about fair value measurements.

(3)

Fair Value Measurements

          During the first quarter of 2008, the Partnership adopted FASB Statement No. 157, Fair Value Measurements (FAS 157). FAS 157 established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of FAS 157 had no impact on the Partnership’s financial position or results of operations.

          FAS 157 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that each asset and liability carried at fair value be classified into one of the following categories:

     Level 1: Quoted market prices in active markets for identical assets or liabilities.

     Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

     Level 3: Unobservable inputs that are not corroborated by market data.

          The Partnership’s derivative instruments which consist of commodity and interest rate swaps are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Refer to Notes 7 and 8 for further information on the Partnership’s derivative instruments and hedging activities.

          As prescribed by the FAS 157 levels listed above, the Partnership considers the Partnership’s derivative assets and liabilities as Level 2. The net fair value of the Partnership’s assets and liabilities measured on a recurring basis was a liability of $10,077 and $9,843 at September 30, 2008 and December 31, 2007, respectively.

(4)

Acquisitions

(a)

Stanolind Assets

               In January 2008, The Partnership acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management Corporation (“Martin Resource Management”) for $5,983 which was allocated to property, plant and equipment. The Partnership entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks. In connection with the acquisition, the Partnership borrowed approximately $6,000 under its credit facility.

(b)

Asphalt Terminal

               In October 2007, the Partnership acquired the asphalt assets of Monarch Oil, Inc. and related companies (“Monarch Oil”) for $3,927 which was allocated to property, plant and equipment. The results of Monarch Oil’s operations have been included in the consolidated financial statements beginning October 2, 2007. The assets are located in Omaha, Nebraska. The Partnership entered into an agreement with Martin Resource Management, whereby Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will bear all additional expenses to operate the facility. In connection with the acquisition, the Partnership borrowed approximately $3,900 under its credit facility.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

(c)

Lubricants Terminal

          In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) located in Channelview, Texas. The results of Mega Lubricant’s operations have been included in the consolidated financial statements beginning June 13, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the 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		$	446
Property, plant and equipment, net			3,042
Goodwill			1,020
Other assets			530
Other liabilities			(300	)
		$	4,738

          In connection with the acquisition, the Partnership borrowed approximately $4,600 under its credit facility.

(d)

Woodlawn Pipeline Co., Inc.

          On May 2, 2007, the Partnership, through its subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), acquired 100% of the outstanding stock of Woodlawn Pipeline Co., Inc. (“Woodlawn”). The results of Woodlawn’s operations have been included in the consolidated financial statements beginning May 2, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $8,785 was recorded as goodwill. The goodwill was a result of Woodlawn’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional gathering services to customers through internal growth projects including natural gas processing, fractionation and pipeline expansions as well as new pipeline construction. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment.

          Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 Mcf/day processing plant. Prism Gas also acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from Woodlawn to the Texas Eastern Transmission pipeline system.

          The selling parties in this transaction were Lantern Resources, L.P., David P. Deison, and Peak Gas Gathering L.P. The final purchase price, after final adjustments for working capital, was $32,606 and was funded by borrowings under the Partnership’s credit facility.

          The purchase price of $32,606, including four two-year non-competition agreements and other intangibles reflected as other assets, was allocated as follows:

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

Current assets		$	4,297
Property, plant and equipment, net			29,101
Goodwill			8,785
Other assets			3,339
Current liabilities			(3,889	)
Deferred income taxes			(8,964	)
Other long-term obligations			(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.

(5)

Inventories

          Components of inventories at September 30, 2008 and December 31, 2007 were as follows:

		September 30,				December 31,
		2008				2007
Natural gas liquids		$	15,664			$	31,283
Sulfur			34,101				7,490
Sulfur Based Products			17,096				6,626
Lubricants			8,699				5,345
Other			2,442				1,054
		$	78,002			$	51,798

(6)

Investment in Unconsolidated Partnerships and Joint Ventures

          The Partnership, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”) and a 20% ownership interest in a partnership which owns the lease rights to Bosque County Pipeline (“BCP”). Each of these interests is accounted for under the equity method of accounting.

          In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $148 and $444 for the three and nine months September 30, 2008 and 2007, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $10,240 and $10,685 at September 30, 2008 and December 31, 2007, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in the first nine months of 2008 or the year ended December 31, 2007.

          As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids (“NGLs”) that are retained according to Waskom’s contracts with certain producers. The NGLs are valued at prevailing market prices. In addition, cash distributions are received and cash contributions are made to fund operating and capital requirements of Waskom.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

          Activity related to these investment accounts is as follows:

		Waskom				PIPE				Matagorda				BCP				Total
Investment in unconsolidated entities, December 31, 2007		$	70,237			$	1,582			$	3,693			$	178			$	75,690
Distributions in kind from equity investments			(8,392	)			—				—				—				(8,392	)
Return on investments from unconsolidated entities			—				—				—				—				—
Contributions to (distributions from) unconsolidated entities:
Cash contributions			1,250				—				—				80				1,330
Distributions from (contributions to) unconsolidated entities for operations			669				—				—				—				669
Return of investments from unconsolidated entities			(300	)			(180	)			(515	)			—				(995	)
Equity in earnings:
Equity in earnings from operations			11,451				17				485				(124	)			11,829
Amortization of excess investment			(412	)			(11	)			(21	)			—				(444	)
Investment in unconsolidated entities, September 30, 2008		$	74,503			$	1,408			$	3,642			$	134			$	79,687

		Waskom				PIPE				Matagorda				BCP				Total
Investment in unconsolidated entities, December 31, 2006		$	64,937			$	1,718			$	3,786			$	210			$	70,651
Distributions in kind from equity investments			(6,628	)			—				—				—				(6,628	)
Return on investments from unconsolidated entities			—				(200	)			—				—				(200	)
Contributions to (distributions from) unconsolidated entities:
Cash contributions			—				—				—				—				—
Distributions from (contributions to) unconsolidated entities for operations			6,023				—				—				107				6,130
Return of investments from unconsolidated entities			(2,625	)			(365	)			(125	)			—				(3,115	)
Equity in earnings:
Equity in earnings from operations			7,205				464				78				(99	)			7,648
Amortization of excess investment			(412	)			(11	)			(21	)			—				(444	)
Investment in unconsolidated entities, September 30, 2007		$	68,500			$	1,606			$	3,718			$	218			$	74,042

          Select financial information for significant unconsolidated equity method investees is as follows:

										Three Months Ended								Nine Months Ended
		As of September 30,								September 30,								September 30,
		Total				Partner’s								Net								Net
		Assets				Capital				Revenues				Income				Revenues				Income
2008
Waskom		$	87,618			$	66,506			$	34,113			$	7,154			$	96,653			$	22,902
		As of December 31,
2007
Waskom		$	66,772			$	57,149			$	21,293			$	5,808			$	54,466			$	14,410

(7)

Commodity Cash Flow Hedges

          The Partnership is exposed to market risks associated with commodity prices, counterparty credit and interest rates. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. In addition, the Partnership is focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

          The Partnership uses derivatives to manage the risk of commodity price fluctuations. Additionally, the Partnership manages interest rate exposure by targeting a ratio of fixed and floating interest rates it deems prudent and using hedges to attain that ratio.

          In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. The Partnership has adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges.

          Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of September 30, 2008, the Partnership has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity.

          The components of gain (loss) on derivatives qualifying for hedge accounting and those that do not qualify for hedge accounting are included in the revenue of the hedged item in the Consolidated Statements of Operations as follows:

		Three Months Ended								Nine Months Ended
		September 30								September 30
		2008				2007				2008				2007
Change in fair value of derivatives that do not qualify for hedge accounting and settlements of maturing hedges		$	2,718			$	(572	)		$	(5,428	)		$	(1,365	)
Ineffective portion of derivatives qualifying for hedge accounting			2,091				(199	)			2,128				(109	)
Change in fair value of derivatives in the Consolidated Statement of Operations		$	4,809			$	(771	)		$	(3,300	)		$	(1,474	)

     The fair value of derivative assets and liabilities are as follows:

		September 30,				December 31,
		2008				2007
Fair value of derivative assets — current		$	354			$	235
Fair value of derivative assets — long term			159				—
Fair value of derivative liabilities — current			(2,738	)			(3,261	)
Fair value of derivative liabilities — long term			(2,606	)			(2,140	)
Net fair value of derivatives		$	(4,831	)		$	(5,166	)

          Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2008 (all gas quantities are expressed in British Thermal Units, crude oil and NGLs are expressed in barrels). As of September 30, 2008, the remaining term of the contracts extend no later than December 2011, with no single contract longer than one year. The Partnership’s counterparties to the derivative contracts include Shell Energy North America (US) L.P., Morgan Stanley Capital Group Inc., Wachovia Bank and Wells Fargo Bank. For the period ended September 30, 2008, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in other comprehensive income as a component of equity since the Partnership has designated a portion of its derivative instruments as hedges as of September 30, 2008.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

September 30, 2008
		Total
		Volume				Remaining Terms
Transaction Type		Per Month		Pricing Terms		of Contracts		Fair Value
Mark-to-Market Derivatives:
Natural Gas swap		30,000 MMBTU		Fixed price of $8.12 settled against Houston Ship Channel first of the month		October 2008 to December 2008		$	74
Crude Oil Swap		3,000 BBL		Fixed price of $70.75 settled against WTI NYMEX average monthly closings		October 2008 to December 2008			(259	)
Crude Oil Swap		3,000 BBL		Fixed price of $69.08 settled against WTI NYMEX average monthly closings		January 2009 to December 2009			(1,130	)
Crude Oil Swap		3,000 BBL		Fixed price of $70.90 settled against WTI NYMEX average monthly closings		January 2009 to December 2009			(1,068	)
Total swaps not designated as cash flow hedges								$	(2,383	)
Cash Flow Hedges:
Crude Oil Swap		5,000 BBL		Fixed price of $66.20 settled against WTI NYMEX average monthly closings		October 2008 to December 2008		$	(499	)
Ethane Swap		5,000 BBL		Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings		October 2008 to December 2008			(22	)
Natural Gasoline Swap		3,000 BBL		Fixed price of $85.79 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.		October 2008 to December 2008			(6	)
Natural Gas swap		30,000 MMBTU		Fixed price of $9.025 settled against Inside Ferc Columbia Gulf daily average		January 2009 to December 2009			321
Crude Oil Swap		1,000 BBL		Fixed price of $70.45 settled against WTI NYMEX average monthly closings		January 2009 to December 2009			(361	)
Natural Gasoline Swap		2,000 BBL		Fixed price of $86.42 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.		January 2009 to December 2009			(61	)
Crude Oil Swap		2,000 BBL		Fixed price of $69.15 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			(759	)
Crude Oil Swap		3,000 BBL		Fixed price of $72.25 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			(1,039	)
Crude Oil Swap		1,000 BBL		Fixed price of $104.80 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			2
Natural Gasoline Swap		1,000 BBL		Fixed price of $94.14 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings		January 2010 to December 2010			47

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

September 30, 2008
		Total
		Volume				Remaining Terms
Transaction Type		Per Month		Pricing Terms		of Contracts		Fair Value
Crude Oil Swap		2,000 BBL		Fixed price of $99.15 settled against WTI NYMEX average monthly closings		January 2011 to December 2011			(124	)
Crude Oil Swap		1,000 BBL		Fixed price of $103.80 settled against WTI NYMEX average monthly closings		January 2011 to December 2011			(15	)
Natural Gasoline Swap		2,000 BBL		Fixed price of $93.18 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings		January 2011 to December 2011			68
Total swaps designated as cash flow hedges								$	(2,448	)
Total net fair value of derivatives								$	(4,831	)

          On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Partnership has incurred no losses associated with the counterparty non-performance on derivative contracts.

          As a result of the Prism Gas acquisition, the Partnership is 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 2011 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, and natural gasoline.

          Based on estimated volumes, as of September 30, 2008, Prism Gas had hedged approximately 67%, 47%, 21% and 16% of its commodity risk by volume for 2008, 2009, 2010, and 2011, 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.

Hedging Arrangements in Place
As of September 30, 2008

Year		Commodity Hedged		Volume		Type of Derivative		Basis Reference
2008		Condensate & Natural Gasoline		5,000 BBL/Month		Crude Oil Swap ($66.20)		NYMEX
2008		Natural Gas		30,000 MMBTU/Month		Natural Gas Swap ($8.12)		Houston Ship Channel
2008		Ethane		5,000 BBL/Month		Ethane Swap ($27.30)		Mt. Belvieu
2008		Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($70.75)		NYMEX
2008		Natural Gasoline		3,000 BBL/Month		Natural Gasoline Swap ($85.79)		Mt. Belvieu (Non-TET)
2009		Natural Gas		30,000 MMBTU/Month		Natural Gas Swap ($9.025)		Columbia Gulf
2009		Condensate & Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($69.08)		NYMEX
2009		Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($70.90)		NYMEX
2009		Condensate		1,000 BBL/Month		Crude Oil Swap ($70.45)		NYMEX
2009		Natural Gasoline		2,000 BBL/Month		Natural Gasoline Swap ($86.42)		Mt. Belvieu (Non-TET)
2010		Condensate		2,000 BBL/Month		Crude Oil Swap ($69.15)		NYMEX
2010		Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($72.25)		NYMEX
2010		Condensate		1,000 BBL/Month		Crude Oil Swap ($104.80)		NYMEX
2010		Natural Gasoline		1,000 BBL/Month		Natural Gasoline Swap ($94.14)		Mt. Belvieu (Non-TET)
2011		Condensate		2,000 BBL/Month		Crude Oil Swap ($99.15)		NYMEX
2011		Condensate		1,000 BBL/Month		Crude Oil Swap ($103.80)		NYMEX
2011		Natural Gasoline		2,000 BBL/Month		Natural Gasoline Swap ($93.18)		NYMEX

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

          The Partnership’s principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing servicers, 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 three month periods ended September 30, 2008 and 2007, net gains and losses on swap hedge contracts increased crude revenue by $4,079 and decreased crude revenue by $653, respectively. For the nine month periods ending September 30, 2008 and 2007 net gains and losses on swap hedge contracts decreased crude revenue by $1,958 and $1,004, respectively. As of September 30, 2008 an unrealized derivative fair value loss of $4,251, related to cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2008, 2009, 2010 and 2011. 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 amount is not reflected above.

Natural Gas

          For the three month periods ended September 30, 2008 and 2007, net gains and losses on swap hedge contracts increased gas revenue by $811 and $146, respectively. For the nine month periods ended September 30, 2008 and 2007, net losses and gains on swap hedge contracts decreased gas revenue by $515 and $96, respectively. As of September 30, 2008 an unrealized derivative fair value gain of $321, related to cash flow hedges of natural gas price risk, was recorded in other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

Natural Gas Liquids

          For the three month periods ended September 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased liquids revenue by $81 and $264, respectively. For the nine month periods ended September 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased liquids revenue by $827 and $374, respectively. As of September 30, 2008 an unrealized derivative fair value gain of $30, related to cash flow hedges of NGLs price risk, was recorded in other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2008, 2009, 2010, and 2011. 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 amount is not reflected above.

(8)

Interest Rate Cash Flow Hedge

          The Partnership has entered into several cash flow hedge agreements with an aggregate notional amount of $195,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. The Partnership designated these swap agreements as cash flow hedges. Under these swap agreements, the Partnership pays a fixed rate of interest and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because these swaps are designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of these hedges, these swaps were identical to the hypothetical swap as of the trade date, and will continue to be

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

identical as long as the accrual periods and rate resetting dates for the debt and these swaps remain equal. This condition results in a 100% effective swap for the following hedges:

Date of Hedge		Notional Amount				Fixed Rate				Maturity Date
January 2008		$	25,000				3.400	%		January 2010
September 2007		$	25,000				4.605	%		September 2010
November 2006		$	40,000				4.820	%		December 2009
March 2006		$	75,000				5.250	%		November 2010

          In November 2006, the Partnership entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006; therefore, hedge accounting was not utilized. The swap has been recorded at fair value at September 30, 2008 with an offset to current operations.

          The Partnership recognized increases in interest expense of $916 and $1,882 for the three and nine months ended September 30, 2008, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate hedges.

          For the three months ended September 30, 2007, the Partnership recognized an increase in interest expense of $387 and for the nine months ended September 30, 2007, the Partnership recognized a decrease in interest expense of $44, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate hedges.

          The fair value of derivative assets and liabilities are as follows:

		September 30,				December 31,
		2008				2007
Fair value of derivative liabilities — current		$	(2,919	)		$	(1,241	)
Fair value of derivative liabilities — long term			(2,327	)			(3,436	)
Net fair value of derivatives		$	(5,246	)		$	(4,677	)

(9)

Related Party Transactions

          Included in the consolidated and condensed financial statements are various related party transactions and balances primarily with Martin Resource Management and affiliates. Related party transactions include sales and purchases of products and services between the Partnership and these related entities as well as payroll and associated costs and allocation of overhead.

          The impact of these related party transactions is reflected in the consolidated and condensed financial statements as follows:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Revenues:
Terminalling and storage		$	5,142			$	3,092			$	13,374			$	8,360
Marine transportation			6,383				5,409				18,826				18,096
Product sales:
Natural gas services			1,876				1,483				3,950				2,124
Sulfur services			8,867				593				17,788				692
Terminalling and storage			26				14				44				24
			10,769				2,090				21,782				2,840
		$	22,294			$	10,591			$	53,982			$	29,296

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2008
(Unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Costs and expenses:
Cost of products sold:
Natural gas services		$	28,051			$	15,857			$	77,033			$	41,713
Sulfur services			3,203				3,165				9,919				10,454
Terminalling and storage			25				—				322				—
		$	31,279			$	19,022			$	87,274			$	52,167
Expenses:
Operating expenses
Marine transportation		$	5,755			$	5,932			$	17,956			$	15,217
Natural gas services			391				365				1,164				1,128
Sulfur services			1,040				334				2,909				940
Terminalling and storage			2,392				1,437				6,960				3,612
		$	9,578			$	8,068			$	28,989			$	20,897
Selling, general and administrative:
Natural gas services		$	176			$	225			$	561			$	566
Sulfur services			479				377				1,387				1,161
Terminalling and storage			—				13				—				41
Indirect overhead allocation, net of reimbursement			674				326				2,021				978
		$	1,329			$	941			$	3,969			$	2,746

(10)

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 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

																		Operating
						Intersegment				Operating				Depreciation				Income
		Operating				Revenues				Revenues after				and				(loss) after				Capital
		Revenues				Eliminations				Eliminations				Amortization				eliminations				Expenditures
Three months ended September 30, 2008
Terminalling and storage		$	23,847			$	(1,053	)		$	22,794			$	2,342			$	1,961			$	7,167
Natural gas services			188,200				—				188,200				1,028				4,928				4,368
Marine transportation			21,129				(1,013	)			20,116				3,159				1,972				7,357
Sulfur services			133,660				(384	)			133,276				1,450				7,973				537
Indirect selling, general and administrative			—				—				—				—				(1,414	)			—
Total		$	366,836			$	(2,450	)		$	364,386			$	7,979			$	15,420			$	19,429
Three months ended September 30, 2007
Terminalling and storage		$	18,788			$	(267	)		$	18,521			$	1,700			$	2,411			$	7,695
Natural gas services			120,994				—				120,994				970				1,676				1,444
Marine transportation			16,459				(990	)			15,469				2,377				944				8,361
Sulfur services			29,949				(83	)			29,866				1,189				2,375				3,252
Indirect selling, general and administrative			—				—				—				—				(841	)			—
Total		$	186,190			$	(1,340	)		$	184,850			$	6,236			$	6,565			$	20,752