10-Q

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 June 30, 2008

OR

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

For the transition period from ______to ______

Commission File Number
000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)

Delaware	05-0527861
(State or other jurisdiction of incorporation or organization)	(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. (Check one):

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

     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 August 5, 2008 was 12,837,480. The number of the registrant’s subordinated units outstanding at August 5, 2008 was 1,701,346

	Page
PART I – FINANCIAL INFORMATION		1
Item 1. Financial Statements		1
Consolidated and Condensed Balance Sheets as of June 30, 2008 (unaudited) and December 31, 2007 (audited)		1
Consolidated and Condensed Statements of Operations for the Three and Six Months Ended June 30, 2008 and 2007 (unaudited)		2
Consolidated and Condensed Statements of Capital for the Three and Six Months Ended June 30, 2008 and 2007 (unaudited)		3
Consolidated and Condensed Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2008 and 2007 (unaudited)		4
Consolidated and Condensed Statements of Cash Flows for the Six Months Ended June 30, 2008 and 2007 (unaudited)		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
Item 3. Quantitative and Qualitative Disclosures about Market Risk		45
Item 4. Controls and Procedures		46
PART II. OTHER INFORMATION		47
Item 1.    Legal Proceedings		47
Item 1A. Risk Factors		47
Item 5.    Other Information		47
Item 6.    Exhibits		47
SIGNATURE
CERTIFICATIONS
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Balance Sheets

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	June 30,			December 31,
	2008			2007
	(Unaudited)			(Audited)
Assets
Cash	$	11,273		$	4,113
Accounts and other receivables, less allowance for doubtful accounts of $350 and $211, respectively		110,998			88,039
Product exchange receivables		42,148			10,912
Inventories		101,832			51,798
Due from affiliates		8,336			2,325
Fair value of derivatives		—			235
Other current assets		7,093			584
Total current assets		281,680			158,006
Property, plant and equipment, at cost		497,323			441,117
Accumulated depreciation		(110,332	)		(98,080	)
Property, plant and equipment, net		386,991			343,037
Goodwill		37,405			37,405
Investment in unconsolidated entities		77,276			75,690
Fair value of derivatives		42			—
Other assets, net		8,493			9,439
	$	791,887		$	623,577
Liabilities and Partners’ Capital
Current installments of long-term debt	$	—		$	21
Trade and other accounts payable		169,144			104,598
Product exchange payables		70,856			24,554
Due to affiliates		10,138			7,543
Income taxes payable		671			602
Fair value of derivatives		13,083			4,502
Other accrued liabilities		4,717			4,752
Total current liabilities		268,609			146,572
Long-term debt		285,000			225,000
Deferred income taxes		8,660			8,815
Fair value of derivatives		11,535			5,576
Other long-term obligations		1,586			1,766
Total liabilities		575,390			387,729
Partners’ capital		232,798			242,610
Accumulated other comprehensive income (loss)		(16,301	)		(6,762	)
Total partners’ capital		216,497			235,848
Commitments and contingencies	$	791,887		$	623,577

     See accompanying notes to consolidated and condensed financial statements.

1

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Revenues:
Terminalling and storage	$	9,900		$	7,037		$	17,820		$	13,988
Marine transportation		19,309			15,154			35,712			29,038
Product sales:
Natural gas services		182,025			105,321			389,117			207,109
Sulfur services		86,027			30,353			156,252			59,733
Terminalling and storage		10,882			4,449			22,258			8,242
		278,934			140,123			567,627			275,084
Total revenues		308,143			162,314			621,159			318,110
Costs and expenses:
Cost of products sold:
Natural gas services		180,324			100,939			383,174			197,711
Sulfur services		75,964			22,416			132,304			44,217
Terminalling and storage		10,270			3,917			20,191			6,932
		266,558			127,272			535,669			248,860
Expenses:
Operating expenses		26,195			20,663			50,412			39,656
Selling, general and administrative		3,467			2,744			6,946			5,465
Depreciation and amortization		7,614			5,468			14,954			10,362
Total costs and expenses		303,834			156,147			607,981			304,343
Other operating income (loss)		(14	)		—			126			—
Operating income		4,295			6,167			13,304			13,767
Other income (expense):
Equity in earnings of unconsolidated entities		4,372			2,418			7,882			4,468
Interest expense		(3,895	)		(2,739	)		(8,638	)		(6,316	)
Other, net		67			72			247			151
Total other income (expense)		544			(249	)		(509	)		(1,697	)
Net income before taxes		4,839			5,918			12,795			12,070
Income tax benefit (expense)		(522	)		9			(461	)		(340	)
Net income	$	4,317		$	5,927		$	12,334		$	11,730
General partner’s interest in net income	$	665		$	354		$	1,316		$	629
Limited partners’ interest in net income	$	3,652		$	5,573		$	11,018		$	11,101
Net income per limited partner unit — basic and diluted	$	0.25		$	0.41		$	0.76		$	0.82
Weighted average limited partner units — basic		14,532,826			13,638,101			14,532,826			13,478,271
Weighted average limited partner units — diluted		14,535,779			13,642,950			14,535,564			13,483,246

     See accompanying notes to consolidated and condensed financial statements.

2

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		—		9,254			—		1,847			629			—			11,730
Follow-on public offering		1,380,000		55,934			—		—			—			—			55,934
General partner contribution		—		—			—		—			1,192			—			1,192
Unit-based compensation		3,000		26			—		—			—			—			26
Cash distributions		—		(13,361	)		—		(3,216	)		(697	)		—			(17,274	)
Adjustment in fair value of derivatives		—		—			—		—			—			193			193
Balances – June 30, 2007		11,986,808	$	253,240			2,552,018	$	(7,606	)	$	4,377		$	315		$	250,326
Balances – January 1, 2008		12,837,480	$	244,520			1,701,346	$	(6,022	)	$	4,112		$	(6,762	)	$	235,848
Net income		—		9,958			—		1,060			1,316			—			12,334
Cash distributions		—		(18,229	)		—		(2,416	)		(1,535	)		—			(22,180	)
Unit-based compensation		—		34			—		—			—			—			34
Adjustment in fair value of derivatives		—		—			—		—			—			(9,539	)		(9,539	)
Balances – June 30, 2008		12,837,480	$	236,283			1,701,346	$	(7,378	)	$	3,893		$	(16,301	)	$	216,497

     See accompanying notes to consolidated and condensed financial statements.

3

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Net income	$	4,317		$	5,927		$	12,334		$	11,730
Changes in fair values of commodity cash flow hedges		(8,700	)		(193	)		(8,487	)		(357	)
Cash flow hedging gains (losses) reclassified to earnings		41			40			(625	)		(270	)
Changes in fair value of interest rate cash flow hedges		4,112			1,457			(427	)		820
Comprehensive income	$	(230	)	$	7,231		$	2,795		$	11,923

     See accompanying notes to consolidated and condensed financial statements.

4

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Six Months Ended
	June 30,
	2008			2007
Cash flows from operating activities:
Net income	$	12,334		$	11,730
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		14,954			10,362
Amortization of deferred debt issuance costs		559			540
Deferred taxes		(155	)		(68	)
Gain on sale of property, plant and equipment		(126	)		—
Equity in earnings of unconsolidated entities		(7,882	)		(4,468	)
Distributions from unconsolidated entities		—			200
Distributions in-kind from equity investments		5,621			4,541
Non-cash mark-to-market on derivatives		5,195			854
Other		34			26
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		(22,959	)		6,769
Product exchange receivables		(31,236	)		4,170
Inventories		(50,034	)		702
Due from affiliates		(6,011	)		(1,145	)
Other current assets		(6,509	)		148
Trade and other accounts payable		64,546			6,059
Product exchange payables		46,302			(7,401	)
Due to affiliates		2,595			(4,694	)
Income taxes payable		69			277
Other accrued liabilities		(34	)		(892	)
Change in other non-current assets and liabilities		(224	)		47
Net cash provided by operating activities		27,039			27,757
Cash flows from investing activities:
Payments for property, plant and equipment		(52,756	)		(36,772	)
Acquisitions, net of cash acquired		(5,983	)		(37,344	)
Proceeds from sale of property, plant and equipment		404			—
Return of investments from unconsolidated entities		600			2,970
Distributions from (contributions to) unconsolidated entities for operations		75			(5,777	)
Net cash used in investing activities		(57,660	)		(76,923	)
Cash flows from financing activities:
Payments of long-term debt		(100,791	)		(97,287	)
Proceeds from long-term debt		160,770			103,250
Net proceeds from follow on public offering		—			55,934
General partner contribution		—			1,192
Payments of debt issuance costs		(18	)		—
Cash distributions paid		(22,180	)		(17,274	)
Net cash provided by financing activities		37,781			45,815
Net increase (decrease) in cash		7,160			(3,351	)
Cash at beginning of period		4,113			3,675
Cash at end of period	$	11,273		$	324

     See accompanying notes to consolidated and condensed financial statements.

5

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 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. 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 $17 and $15 for the three months ended June 30, 2008 and 2007, respectively, and $34 and $26 for the six months ended June 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.

6

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 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 June 30, 2008 and 2007 the general partner received $590 and $240, respectively, in incentive distributions. For the six months ended June 30, 2008 and 2007, the general partner received and $1,091 and $402, 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 13,638,101 for the three months ended June 30, 2008 and 2007, respectively, and 14,532,826 and 13,478,271 for the six months ended June 30, 2008 and 2007, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 2,953 and 4,849 for the three months ended June 30, 2008 and 2007, respectively, and 2,738 and 4,975 for the six months ended June 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 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

7

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

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 September 2006, the Financial Accounting Standards Board (“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 Partnership’s consolidated financial statements. See Note 3 for expanded disclosures about fair value measurements.

     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 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 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 March 2008, the 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

8

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

interim periods beginning after November 15, 2008. The Partnership is evaluating the additional disclosures required by SFAS No. 161 beginning January 1, 2009.

(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 are 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 $24,576 and $ 9,843 at June 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.

     (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.

     (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

9

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

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	)
Total	$	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:

10

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 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	)
Total	$	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 June 30, 2008 and December 31, 2007 were as follows:

	June 30,		December 31,
	2008		2007
Natural gas liquids	$	26,715	$	31,283
Sulfur		50,977		7,490
Sulfur Based Products		14,303		6,626
Lubricants		7,402		5,345
Other		2,435		1,054
	$	101,832	$	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 $297 for the three and six months June 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 $10,388 and $10,685 at June 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 six months of 2008 or the year ended December 31, 2007.

11

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

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

     Activity related to these investment accounts is as follows:

	Waskom			PIPE			Matagorda			BCP			Total
Investment in unconsolidated entities, December 31, 2007	$	70,237		$	1,582		$	3,693		$	178		$	75,690
Acquisitions of interests		—			—			—			—			—
Distributions in kind from equity investments		(5,621	)		—			—			—			(5,621	)
Return on investments from unconsolidated entities		—			—			—			—			—
Contributions to (distributions from) unconsolidated entities:
Cash contributions		500			—			—			80			580
Distributions from (contributions to) unconsolidated entities for operations		(655	)		—			—			—			(655	)
Return of investments from unconsolidated entities		(300	)		(105	)		(195	)		—			(600	)
Equity in earnings:
Equity in earnings from operations		7,875			84			302			(82	)		8,179
Amortization of excess investment		(275	)		(8	)		(14	)		—			(297	)
Investment in unconsolidated entities, June 30, 2008	$	71,761		$	1,553		$	3,786		$	176		$	77,276

	Waskom			PIPE			Matagorda			BCP			Total
Investment in unconsolidated entities, December 31, 2006	$	64,937		$	1,718		$	3,786		$	210		$	70,651
Acquisitions of interests		—			—			—			—			—
Distributions in kind from equity investments		(4,541	)		—			—			—			(4,541	)
Return on investments from unconsolidated entities		—			(200	)		—			—			(200	)
Contributions to (distributions from) unconsolidated entities:
Cash contributions		—			—			—			—			—
Distributions from (contributions to) unconsolidated entities for operations		5,670			—			—			107			5,777
Return of investments from unconsolidated entities		(2,625	)		(270	)		(75	)		—			(2,970	)
Equity in earnings:
Equity in earnings from operations		4,301			419			110			(65	)		4,765
Amortization of excess investment		(275	)		(8	)		(14	)		—			(297	)
Investment in unconsolidated entities, June 30, 2007	$	67,467		$	1,659		$	3,807		$	252		$	73,185

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

					Three Months Ended				Six Months Ended
	As of June 30,				June 30,				June 30,
	Total		Partner’s				Net				Net
	Assets		Capital		Revenues		Income		Revenues		Income
2008
Waskom	$	75,929	$	60,745	$	35,807	$	8,468	$	62,540	$	15,748

2007	As of December 31,
Waskom	$	66,772	$	57,149	$	18,374	$	4,873	$	33,173	$	8,602

12

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

(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.

     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 June 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						Six Months
	Ended						Ended
	June 30						June 30
	2008			2007			2008			2007
Change in fair value of derivatives that do not qualify for hedge accounting and settlements of maturing hedges	$	(5,964	)	$	(509	)	$	(8,146	)	$	(793	)
Ineffective portion of derivatives qualifying for hedge accounting		(85	)		(35	)		37			89
Change in fair value of derivatives in the Consolidated Statement of Operations	$	(6,049	)	$	(544	)	$	(8,109	)	$	(704	)

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

	June 30,			December 31,
	2008			2007
Fair value of derivative assets — current	$	—		$	235
Fair value of derivative assets — long term		—			—
Fair value of derivative liabilities — current		(9,799	)		(3,261	)
Fair value of derivative liabilities — long term		(9,591	)		(2,140	)
Net fair value of derivatives	$	(19,390	)	$	(5,166	)

     Set forth below is the summarized notional amount and terms of all instruments held for price risk

13

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

management purposes at June 30, 2008 (all gas quantities are expressed in British Thermal Units, crude oil and NGLs are expressed in barrels). As of June 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 June 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 June 30, 2008.

June 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	July 2008 to December 2008	$	(904	)
Crude Oil Swap	3,000 BBL	Fixed price of $70.75 settled against WTI NYMEX average monthly closings	July 2008 to December 2008		(1,240	)
Crude Oil Swap	3,000 BBL	Fixed price of $69.08 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(2,418	)
Crude Oil Swap	3,000 BBL	Fixed price of $70.90 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(2,357	)
Total swaps not designated as cash flow hedges				$	(6,919	)
Cash Flow Hedges:
Crude Oil Swap	5,000 BBL	Fixed price of $66.20 settled against WTI NYMEX average monthly closings	July 2008 to December 2008	$	(2,201	)
Ethane Swap	5,000 BBL	Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings	July 2008 to December 2008		(720	)
Natural Gasoline Swap	3,000 BBL	Fixed price of $86.52 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.	July 2008 to September 2008		(369	)
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		(377	)
Natural Gas swap	30,000 MMBTU	Fixed price of $9.025 settled against Inside Ferc Columbia Gulf daily average	January 2009 to December 2009		(1,144	)
Crude Oil Swap	1,000 BBL	Fixed price of $70.45 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(791	)
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		(929	)

14

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

June 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 $69.15 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(1,461	)
Crude Oil Swap	3,000 BBL	Fixed price of $72.25 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(2,093	)
Crude Oil Swap	1,000 BBL	Fixed price of $104.80 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(355	)
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		(335	)
Crude Oil Swap	2,000 BBL	Fixed price of $99.15 settled against WTI NYMEX average monthly closings	January 2011 to December 2011		(744	)
Crude Oil Swap	1,000 BBL	Fixed price of $103.80 settled against WTI NYMEX average monthly closings	January 2011 to December 2011		(326	)
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		(626	)
Total swaps designated as cash flow hedges				$	(12,471	)
Total net fair value of derivatives				$	(19,390	)

     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 June 30, 2008, Prism Gas had hedged approximately 67%, 47%, 22% 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 June 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

15

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

Year	Commodity Hedged	Volume	Type of Derivative	Basis Reference
2008	Natural Gasoline	3,000 BBL/Month	Natural Gasoline Swap ($86.52)	Mt. Belvieu (Non-TET)
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	Natural Gasoline	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

     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 June 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased crude revenue by $4,946 and $494, respectively. For the six month periods ending June 30, 2008 and 2007 net gains and losses on swap hedge contracts decreased crude revenue by $6,037 and $351, respectively. As of June 30, 2008 an unrealized derivative fair value loss of $7,332, 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 June 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased gas revenue by $626 and increased gas revenue $130, respectively. For the six month periods ended June 30, 2008 and 2007, net losses and gains on swap hedge contracts decreased gas revenue by $1,326 and $243, respectively. As of June 30, 2008 an unrealized derivative fair value loss of $1,144, 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 June 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased liquids revenue by $477 and $180, respectively. For the six month periods ended June 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased liquids revenue by $746 and $110, respectively. As of June 30, 2008 an unrealized derivative fair value loss of $3,355, 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. 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.

16

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

(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 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 June 30, 2008 with an offset to current operations.

     The Partnership recognized increases in interest expense of $193 and $966 for the three and six months ended June 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.

     The Partnership recognized decreases in interest expense of $403 and $431 for the three and six months ended June 30, 2007, 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.

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

	June 30,			December 31,
	2008			2007
Fair value of derivative assets — long-term	$	42		$	—
Fair value of derivative liabilities — current		(3,190	)		(1,241	)
Fair value of derivative liabilities — long term		(2,038	)		(3,436	)
Net fair value of derivatives	$	(5,186	)	$	(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:

17

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Revenues:
Terminalling and storage	$	4,454	$	2,683	$	8,232	$	5,268
Marine transportation		6,219		6,133		12,443		12,687
Product sales:
Natural gas services		875		641		2,074		641
Sulfur services		4,410		91		8,921		99
Terminalling and storage		—		7		18		10
		5,285		739		11,013		750
	$	15,958	$	9,555	$	31,688	$	18,705
Costs and expenses:
Cost of products sold:
Natural gas services	$	28,578	$	13,646	$	48,982	$	25,856
Sulfur services		3,398		3,311		6,716		7,289
Terminalling and storage		19		—		297		—
	$	31,995	$	16,957	$	55,995	$	33,145
Expenses:
Operating expenses
Marine transportation	$	5,732	$	5,123	$	12,956	$	9,285
Natural gas services		389		378		773		763
Sulfur services		565		329		1,114		606
Terminalling and storage		2,298		1,138		4,568		2,175
	$	8,984	$	6,968	$	19,411	$	12,829
Selling, general and administrative:
Natural gas services	$	185	$	174	$	385	$	341
Sulfur services		467		397		908		784
Terminalling and storage		—		14		—		28
Indirect overhead allocation, net of reimbursement		674		326		1,347		652
	$	1,326	$	911	$	2,640	$	1,805

(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				Operating
			Intersegment			Revenues		Depreciation		Income (loss)
	Operating		Revenues			after		and		after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Three months ended June 30, 2008
Terminalling and storage	$	21,795	$	(1,013	)	$	20,782	$	2,301	$	2,156		$	5,375
Natural gas services		182,025		—			182,025		961		(2,667	)		2,590
Marine transportation		20,308		(999	)		19,309		2,948		1,993			10,417
Sulfur services		86,445		(418	)		86,027		1,404		4,128			774
Indirect selling, general and administrative		—		—			—		—		(1,315	)		—
Total	$	310,573	$	(2,430	)	$	308,143	$	7,614	$	4,295		$	19,156
Three months ended June 30, 2007
Terminalling and storage	$	11,622	$	(137	)	$	11,485	$	1,466	$	2,563		$	6,278
Natural gas services		105,321		—			105,321		871		464			890
Marine transportation		15,897		(742	)		15,155		1,963		1,385			10,541
Sulfur services		30,373		(20	)		30,353		1,168		2,605			3,300
Indirect selling, general and administrative		—		—			—		—		(850	)		—
Total	$	163,213	$	(899	)	$	162,314	$	5,468	$	6,167		$	21,009

18

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

						Operating				Operating
						Revenues		Depreciation		Income (loss)
	Operating		Intersegment			after		and		after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Six months ended June 30, 2008
Terminalling and storage	$	42,157		(2,079	)	$	40,078	$	4,442	$	3,332		$	9,826
Natural gas services		389,117		—			389,117		1,938		(2,625	)		3,759
Marine transportation		37,289		(1,577	)		35,712		5,742		2,785			36,543
Sulfur services		156,686		(434	)		156,252		2,832		12,454			2,628
Indirect selling, general and administrative		—		—			—		—		(2,642	)		—
Total	$	625,249	$	(4,090	)	$	621,159	$	14,954	$	13,304		$	52,756
Six months ended June 30, 2007
Terminalling and storage	$	22,463	$	(234	)	$	22,229	$	2,806	$	5,540		$	11,283
Natural gas services		207,109		—			207,109		1,302		2,408			1,594
Marine transportation		30,773		(1,734	)		29,039		3,902		2,403			15,643
Sulfur services		59,903		(170	)		59,733		2,352		5,022			8,252
Indirect selling, general and administrative		—		—			—		—		(1,606	)		—
Total	$	320,248	$	(2,138	)	$	318,110	$	10,362	$	13,767		$	36,772

     The following table reconciles operating income to net income:

	Three Months Ended						Six Months Ended
	June 30						June 30
	2008			2007			2008			2007
Operating income	$	4,295		$	6,167		$	13,304		$	13,767
Equity in earnings of unconsolidated entities		4,372			2,418			7,882			4,468
Interest expense		(3,895	)		(2,739	)		(8,638	)		(6,316	)
Other, net		67			72			247			151
Income taxes		(522	)		9			(461	)		(340	)
Net income	$	4,317		$	5,927		$	12,334		$	11,730

     Total assets by segment are as follows:

	June 30,		December 31,
	2008		2007
Total assets:
Terminalling and storage	$	146,563	$	126,575
Natural gas services		310,100		268,230
Marine transportation		141,148		107,081
Sulfur services		194,076		121,691
Total assets	$	791,887	$	623,577

19

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

(11) Public Equity Offerings

     In May 2007, the Partnership completed a public offering of 1,380,000 common units at a price of $42.25 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,380,000 common units, net of underwriters’ discounts, commissions and offering expenses were $55,933. The Partnership’s general partner contributed $1,190 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital.

     A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows (all amounts are in thousands):

Proceeds received:
Sale of common units	$	58,305
General partner contribution		1,190
Total proceeds received	$	59,495
Use of Proceeds:
Underwriter’s fees	$	2,107
Professional fees and other costs		265
Repayment of debt under revolving credit facility		55,850
Working capital		1,273
Total use of proceeds	$	59,495

(12) Long-term Debt

     At June 30, 2008 and December 31, 2007, long-term debt consisted of the following:

	June 30,		December 31,
	2008		2007
**$195,000 Revolving loan facility at variable interest rate (5.97%* weighted average at June 30, 2008), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees	$	155,000	$	95,000
***$130,000 Term loan facility at variable interest rate (6.99%* at June 30, 2008), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries		130,000		130,000
Other secured debt maturing in 2008, 7.25%		—		21
Total long-term debt		285,000		225,021
Less current installments		—		21
Long-term debt, net of current installments	$	285,000	$	225,000

* Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are

20

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

	base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. Effective July 1, 2008, the applicable margin for existing borrowings will remain 2.00%. As a result of our leverage ratio test as of June 30, 2008, effective October 1, 2008, the applicable margin for existing borrowings will increase to 2.50%. The Partnership incurs a commitment fee on the unused portions of the credit facility.
**	Effective January, 2008, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 3.400% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in January, 2010.
**	Effective September, 2007, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in September, 2010.
**	Effective November, 2006, the Partnership entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 4.82% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in December, 2009.
***	The $130,000 term loan has $105,000 hedged. Effective March, 2006, the Partnership entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010. Effective November 2006, the Partnership entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This cash flow hedge matures in March, 2010.

     On November 10, 2005, the Partnership entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the Partnership increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. Effective December 28, 2007, the Partnership increased its revolving credit facility $75,000 resulting in a committed $195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of June 30, 2008, the Partnership had $155,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of June 30, 2008, the Partnership had $39,880 available under its revolving credit facility.

     On July 14, 2005, the Partnership issued a $120 irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program.

     The Partnership’s obligations under the credit facility are secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time without penalty.

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

     The credit facility also contains covenants, which, among other things, require the Partnership to

21

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

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 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. The Partnership was in compliance with the debt covenants contained in credit facility for the year ended December 31, 2007 and as of June 30, 2008.

     On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made or required under the term loan through June 30, 2008. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Partnership must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

     Draws made under the Partnership’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Partnership’s credit facility have ranged from a low of $225,000 to a high of $296,400. As of June 30, 2008, the Partnership had $39,880 available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility.

     In connection with the Partnership’s Stanolind asset acquisition on January 22, 2008, the Partnership borrowed approximately $6,000 under its revolving credit facility.

     In connection with the Partnership’s Monarch acquisition on October 2, 2007, the Partnership borrowed approximately $3,900 under its revolving credit facility.

     In connection with the Partnership’s Mega Lubricants acquisition on June 13, 2007, the Partnership borrowed approximately $4,600 under its revolving credit facility.

     In connection with the Partnership’s Woodlawn acquisition on May 2, 2007, the Partnership borrowed approximately $33,000 under its revolving credit facility.

     The Partnership paid cash interest in the amount of $4,107 and $2,342 for the three months ended June 30, 2008 and 2007, respectively, and $7,927 and $5,945 for the six months ended June 30, 2008 and 2007, respectively. Capitalized interest was $361 and $806 for the three months ended June 30, 2008 and 2007, respectively and $813 and $1,345 for the six months ended June 30, 2008 and 2007, respectively.

(13) 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. 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. A current federal income tax expense of $411 and $247 and state income tax expense of $13 and $19 related to the operation of the subsidiary was recorded for the three and six months ended June 30, 2008, respectively. In connection with the Woodlawn acquisition, the Partnership also established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment.

22

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

     A deferred tax benefit related to these basis differences of $75 and $68 was recorded for the three months ended June 30, 2008 and 2007, respectively, and $155 and $68 was recorded for the six months ended June 30, 2008 and 2007, respectively. A deferred tax liability of $8,660 and $8,815 related to the basis differences existing at June 30, 2008 and at December 31, 2007, respectively.

     The final liquidation of the Prism Gas corporate entity was completed on November 15, 2006. Additional federal and state income taxes of $173 resulting from the liquidation were recorded in income tax expense for the six months ended June 30, 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. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $186 and $369 were recorded in current income tax expense for the three and six months ended June 30, 2008 and $135 and $269 for the three and six months ended June 30, 2007, respectively.

     In June 2006, the 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, nor is there any impact in the current financial statements.

     The components of income tax expense (benefit) from operations recorded for the three and six months ended June 30, 2008 and 2007 are as follows:

	Three Months Ended						Six Months Ended
	June 30						June 30
	2008			2007			2008			2007
Current:
Federal	$	411		$	(40	)	$	247		$	157
State		186			99			369			251
		597			59			616			408
Deferred:
Federal		(75	)		(68	)		(155	)		(68	)
	$	522		$	(9	)	$	461		$	340

(14) Consolidated Financial Statements

       In connection with the Partnership’s filing of a shelf registration statement on Form S-3 with the Securities and Exchange Commission (the “Registration Statement”), Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, may issue unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time under the registration statement. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities under the Registration Statement which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. The Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has no independent assets or operations, the guarantees are full and unconditional and the other subsidiary of the Partnership is minor. There are no significant restrictions on the ability of the Partnership or the Operating Partnership to obtain funds from any of their respective subsidiaries by dividend or loan.

23

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

(15) 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 employees of Martin Resource Management who provide services to the Partnership were served with grand jury subpoenas during the fourth quarter of 2007. The Partnership is cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against the Partnership.

24

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     References in this quarterly report to “Martin Resource Management” refers to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires. You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated and condensed financial statements and the notes thereto included elsewhere in this quarterly report.

Forward-Looking Statements

     This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this quarterly report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

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

     Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2008.

Overview

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

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

• Natural gas services;

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

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

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

     We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of hydrocarbon products and by-products and other bulk liquids. Martin Resource Management owns an approximate 34.9% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest and incentive distribution rights in us.

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

25

Critical Accounting Policies

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

     You should also read Note 1, “General” in Notes to Consolidated and Condensed Financial Statements contained in this quarterly report and the “Significant Accounting Policies” note in the consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008 in conjunction with this Management’s Discussion and Analysis of Financial Condition and Results of Operations. Some of the more significant estimates in these financial statements include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units under Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”).

     Derivatives

     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 liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. Our hedging policy allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges or hedges that become ineffective are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of June 30, 2008, we have designated a portion of our derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity.

     Product Exchanges

     We enter into product exchange agreements with third parties whereby we agree to exchange natural gas liquids (“NGLs”) and sulfur with third parties. We record the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method.

     Revenue Recognition

     Revenue for our four operating segments is recognized as follows:

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

26

storage, or by pipeline, we recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.

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

     Sulfur services – 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.

     Equity Method Investments

     We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under the provisions of SFAS No. 142, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. No portion of the net income from these entities is included in our operating income.

     We own an unconsolidated 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.

     Goodwill

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

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

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

     Environmental Liabilities

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

     Allowance for Doubtful Accounts

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

27

     Asset Retirement Obligation

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

Our Relationship with Martin Resource Management

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

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

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

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

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

• operating a lube oil processing facility in Smackover, Arkansas;

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

• developing an underground natural gas storage facility in Arcadia, Louisiana;

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

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

• operating, solely for our account, an NGL truck loading and unloading and pipeline distribution terminal in Mont Belvieu, Texas; and

• operating, solely for our account, the asphalt facilities in Omaha, Nebraska.

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

     Ownership

     Martin Resource Management owns an approximate 34.9% limited partnership interest and a 2% general partnership interest in us and all of our incentive distribution rights.

     Management

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

     Related Party Agreements

     We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $16.3 million of direct costs and expenses for the three months ended June 30, 2008 compared to $12.4 million for the three months ended June 30, 2007. We reimbursed Martin Resource Management for $33.9 million of direct costs and expenses for the six months ended June 30, 2008 compared to $25.2 million for the six months ended June 30, 2007. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

     In addition to the direct expenses, under the omnibus agreement, the reimbursement amount that we are required to pay to Martin Resource Management with respect to indirect general and administrative and

28

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. We reimbursed Martin Resource Management for $0.7 and $0.3 million of indirect expenses for the three months ended June 30, 2008 and 2007, respectively. We reimbursed Martin Resource Management for $1.3 and $0.7 million of indirect expenses for the six months ended June 30, 2008 and 2007, respectively. These indirect expenses covered a portion of the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The omnibus agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the omnibus agreement.

     In addition to the omnibus agreement, we and Martin Resource Management have entered into various other agreements that are not the result of arm’s-length negotiations and consequently may not be as favorable to us as they might have been if we had negotiated them with unaffiliated third parties. The agreements include, but are not limited to, a motor carrier agreement, a terminal services agreement, a marine transportation agreement, a product storage agreement, a product supply agreement, a throughput agreement, and a Purchaser Use Easement, Ingress-Egress Easement and Utility Facilities Easement. Pursuant to the terms of the omnibus agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the conflicts committee of our general partner’s board of directors.

     For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions – Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008.

     Commercial

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

     We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.0 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

     In the aggregate, our purchases of land transportation services, NGL storage services, sulfuric acid and lube oil product purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 12% and 13% of our total cost of products sold during the three months ended June 30, 2008 and 2007, respectively; and approximately 10% and 13% of our total cost of products sold during the six months ended June 30, 2008 and 2007, 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 5% and 6% of our total revenues for the three months ended June 30, 2008 and 2007, respectively. Our sales to Martin Resource Management accounted for approximately 5% and 6% of our total revenues for the six months ended June 30, 2008 and 2007, respectively. We provide terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel provides terminal services to us by handling lubricants, greases and drilling fluids.

29

     For a more comprehensive discussion concerning the agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions – Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008.

     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.

Results of Operations

     The results of operations for the three and six months ended June 30, 2008 and 2007 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 three months and six months ended June 30, 2008 and 2007. The results of operations for the first six months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

     Effective October 1, 2007, we made changes to the way we report our segments. During the fourth quarter of 2007, we effected a significant internal reorganization of the sulfur and fertilizer businesses and implemented a new financial reporting system which grouped and reported financial results differently to management for sulfur and sulfur-based fertilizer products formerly reported in separate segments in our financial statements. Based on the changes in our financial reporting structure, the previously reported financial information for the sulfur and fertilizer segments have been combined into one segment known as the “Sulfur Services” segment. The prior-period segment data previously reported in the sulfur and fertilizer segments have been combined and restated in the new reporting segment to conform to the current period’s presentation.

						Operating					Operating			Operating
			Revenues			Revenues					Income			Income (loss)
			Intersegment			after		Operating			Intersegment			after
	Operating Revenues		Eliminations			Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)
Three months ended June 30, 2008
Terminalling and storage	$	21,795	$	(1,013	)	$	20,782	$	3,025		$	(869	)	$	2,156
Natural gas services		182,025		—			182,025		(2,907	)		240			(2,667	)
Marine transportation		20,308		(999	)		19,309		2,552			(559	)		1,993
Sulfur services		86,445		(418	)		86,027		2,940			1,188			4,128
Indirect selling, general and administrative		—		—			—		(1,315	)		—			(1,315	)
Total	$	310,573	$	(2,430	)	$	308,143	$	4,295		$	—		$	4,295
Three months ended June 30, 2007
Terminalling and storage	$	11,622	$	(137	)	$	11,485	$	2,611		$	(48	)	$	2,563
Natural gas services		105,321		—			105,321		464			—			464
Marine transportation		15,897		(742	)		15,155		2,080			(695	)		1,385
Sulfur services		30,374		(20	)		30,353		1,862			743			2,605
Indirect selling, general and administrative		—		—			—		(850	)		—			(850	)
Total	$	163,214	$	(899	)	$	162,314	$	6,167		$	—		$	6,167

30

						Operating					Operating			Operating
			Revenues			Revenues					Income			Income (loss)
	Operating		Intersegment			after		Operating			Intersegment			after
	Revenues		Eliminations			Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)
Six months ended June, 2008
Terminalling and storage	$	42,157	$	(2,079	)	$	40,078	$	5,134		$	(1,802	)	$	3,332
Natural gas services		389,117		—			389,117		(3,089	)		464			(2,625	)
Marine transportation		37,289		(1,577	)		35,712		3,852			(1,067	)		2,785
Sulfur services		156,686		(434	)		156,252		10,049			2,405			12,454
Indirect selling, general and administrative		—		—			—		(2,642	)		—			(2,642	)
Total	$	625,249	$	(4,090	)	$	621,159	$	13,304		$	—		$	13,304
Six months ended June, 2007
Terminalling and storage	$	22,463	$	(234	)	$	22,229	$	5,498		$	42		$	5,540
Natural gas services		207,109		—			207,109		2,408			—			2,408
Marine transportation		30,773		(1,734	)		29,039		4,084			(1,681	)		2,403
Sulfur Services		59,903		(170	)		59,733		3,383			1,639			5,022
Indirect selling, general and administrative		—		—			—		(1,606	)		—			(1,606	)
Total	$	320,248	$	(2,138	)	$	318,110	$	13,767		$	—		$	13,767

     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.

Three Months Ended June 30, 2008 Compared to the Three Months Ended June 30, 2007

     Our total revenues before eliminations were $310.6 million for the three months ended June 30, 2008 compared to $163.2 million for the three months ended June 30, 2007, an increase of $147.4 million, or 90%. Our operating income before eliminations was $4.3 million for the three months ended June 30, 2008 compared to $6.2 million for the three months ended June 30, 2007, a decrease of $1.9 million, or 31%.

     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.

	Three Months Ended
	June 30,
	2008			2007
	(In thousands)
Revenues:
Services	$	9,900		$	7,037
Products		11,895			4,585
Total revenues		21,795			11,622
Cost of products sold		10,269			3,938
Operating expenses		6,173			3,576
Selling, general and administrative expenses		13			31
Depreciation and amortization		2,301			1,466
		3,039			2,611
Other operating income		(14	)		—
Operating income	$	3,025		$	2,611

     Revenues. Our terminalling and storage revenues increased $10.2 million, or 88%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. Service revenue accounted for $2.9 million of this increase. The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service during the end of 2007 and the beginning of 2008, and increased business activity at our shore based terminals. Product revenue increased $7.3 million primarily due to our acquisition of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) in June 2007.

31

     Cost of products sold. Our cost of products sold increased $6.3 million, or 161%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This was primarily a result of the Mega Lubricants acquisition.

     Operating expenses. Operating expenses increased $2.6 million, or 73%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This increase was result of our recent acquisitions and capital projects being placed into service during the end of 2007 and beginning of 2008. The increase was also a result of increased salaries and related burden, repairs and maintenance and product hauling costs related to increased activity at our existing terminals.

     Selling, general and administrative expenses. Selling, general and administrative expenses were consistent for both three month periods.

     Depreciation and amortization. Depreciation and amortization expenses increased $0.8 million, or 57%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This increase was primarily a result of our recent acquisitions and capital expenditures.

     In summary, our terminalling operating income increased $0.4 million, or 16%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007.

Natural Gas Services Segment

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

	Three Months Ended
	June 30,
	2008			2007
	(In thousands)
Revenues:
NGLs	$	167,181		$	94,786
Natural gas		19,808			10,342
Non-cash mark-to-market adjustment of commodity derivatives		(3,995	)		(580	)
Gain (loss) on cash settlements of commodity derivatives		(2,053	)		35
Other operating fees		1,084			738
Total revenues		182,025			105,321
Cost of products sold:
NGLs		161,355			91,092
Natural gas		19,210			9,847
Total cost of products sold		180,565			100,939
Operating expenses		2,218			1,812
Selling, general and administrative expenses		1,187			1,236
Depreciation and amortization		962			870
		(2,907	)		464
Other operating income		—			—
Operating income (loss)	$	(2,907	)	$	464
NGLs Volumes (Bbls)		1,781			1,742
Natural Gas Volumes (Mmbtu)		1,902			1,412
Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments.
Equity in Earnings of Unconsolidated Entities	$	4,372		$	2,418
Waskom:
Plant Inlet Volumes (Mmcf/d)		272			180
Frac Volumes (Bbls/d)		10,943			7,260

32

     Revenues. Our natural gas services revenues increased $76.7 million, or 73% for the three months ended June 30, 2008 compared to the three months ended June 30, 2007 due to higher commodity prices and increased natural gas volumes.

     For the three months ended June 30, 2008, NGL revenues increased $72.4 million, or 76% and natural gas revenues increased $9.5 million, or 92%. NGL sales volumes for the three months of 2008 remained relatively flat and natural gas volumes increased 35% compared to the same period of 2007. The increase in NGL revenues is primarily due from escalating commodity prices as our NGL average sales price per barrel increased $39.46 or 73% and our natural gas average sales price per Mmbtu increased $3.09, or 42% compared to the same period of 2007. The increase in natural gas volumes is primarily due to the Woodlawn acquisition contributing for the entire second quarter of 2008 as compared to only a portion of 2007.

     Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the three months ended June 30, 2008, 55% of our total natural gas volumes and 72% of our total NGL volumes were hedged as compared to 46% and 53%, respectively in 2007. The impact of price risk management and marketing activities decreased total natural gas and NGL revenues $6.1 million for the second quarter of 2008 compared to a decrease of $0.6 million in the same period of 2007. Of the $6.1 million decrease, $4.0 was attributable to a non-cash mark-to-market adjustments made to our derivative contracts and $2.1 million is related to losses recognized on cash settlements of our derivative contracts.

     Costs of product sold. Our cost of products sold increased $79.6 million, or 79%, for the three months ended June 30, 2008 compared to the same period of 2007. Of the increase, $70.3 million relates to NGLs and $9.4 million relates to natural gas. The increase in NGL cost of products sold is less than our increase in NGL revenues as we were able to expand our NGL margins by $1.15 per barrel, or 54%. The percentage increase relating to natural gas cost of products sold is slightly higher than the percentage increase in natural gas revenues which caused our Mmbtu margins to decrease by 10%. This is primarily a result of the terms of Woodlawn’s producer contracts compared to the terms of our historical producer contracts.

     Operating expenses. Operating expenses increased $0.4 million, or 22%, for the three months ended June 30, 2008 compared to the same period of 2007. This increase was primarily a result of Woodlawn being in operation for the entire second quarter of 2008 as compared to 2007.

     Selling, general and administrative expenses. Selling, general and administrative expenses remained relatively consistent for the three months ended June 30, 2008 and 2007.

     Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 11%, for the three months ended June 30, 2008 compared to the same period of 2007. This increase was primarily a result of Woodlawn being in operation for the entire second quarter of 2008 as compared to 2007.

     In summary, our natural gas services operating income decreased $3.4 million, or 727%, for the three months ended June 30, 2008 compared to the same period of 2007.

     Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $4.4 million and $2.4 million for the three months ended June 30, 2008 and 2007, respectively, an increase of 81%. This increase is primarily a result of completing the expansions to the Waskom plant and the Waskom fractionator during the second quarter of 2007. As a result, our inlet volumes and fractionation volumes increased 51% during the second quarter of 2008 as compared to 2007.

Marine Transportation Segment

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

33

	Three Months Ended
	June 30,
	2008		2007
	(In thousands)
Revenues	$	20,308	$	15,897
Operating expenses		14,542		11,836
Selling, general and administrative expenses		266		17
Depreciation and amortization		2,948		1,964
Operating income	$	2,552	$	2,080

     Revenues. Our marine transportation revenues increased $4.4 million, or 28%, for the three months ended June 30, 2008, compared to the three months ended June 30, 2007. Our inland marine operations generated an additional $5.5 million in revenue from expansion of our fleet and increased contract rates. Our offshore revenues decreased $1.1 million due to downtime associated with capital expenditures on offshore vessels.

     Operating expenses. Operating expenses increased $2.7 million, or 23%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This was primarily a result of increases in operating costs from fuel expense, and wage and burden costs due to expansion of our fleet and increased fuel costs.

     Selling, general, and administrative expenses. Selling, general and administrative expenses increased $0.2 million for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This was primarily a result of increases in selling, general and administrative costs to support our fleet expansion.

     Depreciation and Amortization. Depreciation and amortization increased $1.0 million, or 50%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This increase was primarily a result of capital expenditures made in the last twelve months.

     In summary, our marine transportation operating income increased $0.5 million, or 23%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007.

Sulfur Services Segment

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

	Three Months Ended
	June 30,
	2008		2007
	(In thousands)
Revenues	$	86,445	$	30,374
Cost of products sold		76,690		22,790
Operating expenses		4,727		3,943
Selling, general and administrative expenses		685		612
Depreciation and amortization		1,403		1,168
Operating income	$	2,940	$	1,861
Sulfur Volumes (long tons)		289.8		355.2

     Revenues. Our sulfur services revenues increased $56.1 million, or 185%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This increase was primarily a result of a 249% increase in our average sales price. The sales price increase was due primarily to increased market prices for our sulfur products, primarily driven by higher costs of sulfur and raw materials for sulfur-based products.

     Cost of products sold. Our cost of products sold increased $53.9 million, or 237%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. Our margin per ton increased 58% which was driven by a strong international demand in the prilled sulfur markets and our ability to spread our margin to our sulfur-based product customers.

     Operating expenses. Our operating expenses increased $0.8 million, or 20%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This increase was a result of increased marine transportation expenses.

34

     Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased $0.1 million, or 12%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007.

     Depreciation and amortization. Depreciation and amortization expense increased $0.2 million, or 20%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. This is a result of our sulfuric acid plant becoming operational in late September 2007.

     In summary, our sulfur operating income increased $1.9 million, or 36%, for the three months ended June 30, 2008 compared to the three months ended June 30, 2007.

Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

     Our total revenues before eliminations were $625.3 million for the six months ended June 30, 2008 compared to $320.2 million for the six months ended June 30, 2007, an increase of $305.1 million, or 95%. Our operating income before eliminations was $13.3 million for the six months ended June 30, 2008 compared to $13.8 million for the six months ended June 30, 2007, a decrease of $0.5 million, or 4%.

     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.

	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
Revenues:
Services	$	18,832		$	13,988
Products		23,325			8,475
Total revenues		42,157			22,463
Cost of products sold		20,191			7,103
Operating expenses		12,342			6,996
Selling, general and administrative expenses		34			60
Depreciation and amortization		4,442			2,806
		5,148			5,498
Other operating income		(14	)		—
Operating income	$	5,134		$	5,498

     Revenues. Our terminalling and storage revenues increased $19.7 million, or 88%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. Service revenue accounted for $4.8 million of this increase. The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service during the last twelve months, and increased business activity at our shore based terminals. Product revenue increased $14.9 million primarily due the Mega Lubricants acquisition and an additional 9% increase in historical sales volumes and a 1% increase in product cost that was able to be passed along to our customers.

     Cost of products sold. Our cost of products increased $13.1 million, or 184%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This was primarily a result of the Mega Lubricants acquisition and an additional 9% increase in historical sales volumes and a 1% increase in product cost that was able to be passed along to our customers.

     Operating expenses. Operating expenses increased $5.3 million, or 76%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This increase was result of our recent acquisitions and capital projects placed into service during the last twelve months. The increase was also a

35

result of increased salaries and related burden, repairs and maintenance, and product hauling costs related to increased activity at our existing terminals.

     Selling, general and administrative expenses. Selling, general and administrative expenses were consistent for both six month periods.

     Depreciation and amortization. Depreciation and amortization increased $1.6 million, or 58% for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This increase was primarily a result of our recent acquisitions and capital expenditures.

     In summary, terminalling and storage operating income decreased $0.4 million, or 6%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007.

     Natural Gas Services Segment

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

	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
Revenues:
NGLs	$	361,790		$	193,018
Natural gas		33,620			13,487
Non-cash mark-to-market adjustment of commodity derivatives		(5,112	)		(1,076	)
Gain (loss) on cash settlements of commodity derivatives		(2,997	)		372
Other operating fees		1,816			1,308
Total revenues		389,117			207,109
Cost of products sold:
NGLs		350,501			184,979
Natural gas		33,137			12,732
Total cost of products sold		383,638			197,711
Operating expenses		4,217			3,135
Selling, general and administrative expenses		2,413			2,554
Depreciation and amortization		1,939			1,301
		(3,090	)		2,408
Other operating income		1			—
Operating income (loss)	$	(3,089	)	$	2,408
NGLs Volumes (Bbls)		4,578			3,872
Natural Gas Volumes (Mmbtu)		3,699			1,895
Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments.
Equity in Earnings of Unconsolidated Entities	$	7,882		$	4,469
Waskom:
Plant Inlet Volumes (Mmcf/d)		265			208
Frac Volumes (Bbls/d)		10,494			7,737

     Revenues. Our natural gas services revenues increased $182.0 million, or 88% for the six months ended June 30, 2008 compared to the six months ended June 30, 2007 due to higher commodity prices and increased natural gas and NGL volumes.

     For the six months ended June 30, 2008, NGL revenues increased $168.8 million, or 87% and natural gas revenues increased $20.1 million, or 149%. NGL sales volumes for the six months of 2008 increased by

36

18% and natural gas volumes increased 95% compared to the same period of 2007. The increase in NGL revenues is primarily due from escalating commodity prices as our NGL average sales price per barrel increased $29.18 or 59% and our natural gas average sales price per Mmbtu increased $1.97, or 28% compared to the same period of 2007. The increase in natural gas volumes is primarily due to receiving a full six months benefit of the Woodlawn acquisition in 2008 and increased volumes from the Waskom expansion.

     Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the six months ended June 30, 2008, 55% of our total natural gas volumes and 72% of our total NGL volumes were hedged as compared to 46% and 53%, respectively in 2007. The impact of price risk management and marketing activities decreased total natural gas and NGL revenues $8.1 million for 2008 compared to a decrease of $0.7 million in the same period of 2007. Of the $8.1 million decrease, $5.1 was attributable to a non-cash mark-to-market adjustments made to our derivative contracts and $3.0 million is related to losses recognized on cash settlements of our derivative contracts.

     Costs of product sold. Our cost of products sold increased $185.9 million, or 94%, for the six months ended June 30, 2008 compared to the same period of 2007. Of the increase, $165.5 million relates to NGLs and $20.4 million relates to natural gas. The increase in NGL cost of products sold is less than our increase in NGL revenues as we were able to expand our NGL margins by $0.39 per barrel, or 19%. The percentage increase relating to natural gas cost of products sold was higher than the percentage increase in natural gas revenues which caused our Mmbtu margins to decrease by 67%. This is primarily a result of the terms of Woodlawn’s producer contracts compared to the terms of our historical producer contracts.

     Operating expenses. Operating expenses increased $1.1 million, or 35%, for the six months ended June 30, 2008 compared to the same period of 2007. This increase was primarily a result of Woodlawn being in operation for the entire six months of 2008 as compared to 2007.

     Selling, general and administrative expenses. Selling, general and administrative expenses remained consistent for the six months ended June 30, 2008 and 2007.

     Depreciation and amortization. Depreciation and amortization increased $0.6 million, or 49%, for the six months ended June 30, 2008 compared to the same period of 2007. This increase was primarily a result of Woodlawn being in operation for the first six months of 2008 as compared to 2007.

     In summary, our natural gas services operating income decreased $5.5 million, or 228%, for the six months ended June 30, 2008 compared to the same period of 2007.

     Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $7.9 million and $4.5 million for the six months ended June 30, 2008 and 2007, respectively, an increase of 76%. This increase is primarily a result of receiving full benefit of the expansion to the Waskom plant and the Waskom fractionator for the six months of 2008 as the plant was shut down for a portion of the first half of 2007. As a result, our inlet volumes and fractionation volumes increased 28% during the six months ending June 30, 2008 as compared to the same period in 2007.

Marine Transportation Segment

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

	Six Months Ended
	June 30,
	2008		2007
	(In thousands)
Revenues	$	37,289	$	30,773
Operating expenses		27,317		22,703
Selling, general and administrative expenses		517		83
Depreciation and amortization		5,742		3,903
		3,713		4,084
Other operating income		139		—
Operating income	$	3,852	$	4,084

37

     Revenues. Our marine transportation revenues increased $6.5 million, or 21%, for the six months ended June 30, 2008, compared to the six months ended June 30, 2007. Our inland marine operations generated an additional $7.2 million in revenue from expansion of our fleet and increased contract rates. Our offshore revenues decreased $0.8 million primarily from downtime associated with capital expenditures on offshore vessels.

     Operating expenses. Operating expenses increased $4.6 million, or 20%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This was primarily a result of increases in operating costs from fuel expense, wages and burden costs, and repairs and maintenance due to expansion of our fleet and increased fuel costs.

     Selling, general, and administrative expenses. Selling, general and administrative expenses increased $0.4 million for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This was primarily a result of increases in selling, general and administrative costs to support our fleet expansion.

     Depreciation and Amortization. Depreciation and amortization increased $1.8 million, or 47%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This increase was primarily a result of capital expenditures made in the last twelve months.

     In summary, our marine transportation operating income decreased $0.2 million, or 6%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007.

Sulfur Services Segment

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

	Six Months Ended
	June 30,
	2008		2007
	(In thousands)
Revenues	$	156,686	$	59,903
Cost of products sold		133,907		44,803
Operating expenses		8,559		8,203
Selling, general and administrative expenses		1,340		1,163
Depreciation and amortization		2,831		2,352
Operating income	$	10,049	$	3,382
Sulfur Volumes (long tons)		467.2		720.8

     Revenues. Our sulfur services revenues increased $96.8 million, or 162%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This increase was primarily a result of a 304% increase in our average sales price. The sales price increase was due primarily to increased market prices for our sulfur products, primarily driven by higher costs of sulfur and raw materials for sulfur-based products.

     Cost of products sold. Our cost of products sold increased $89.1 million, or 199%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. Our margin per ton increased 54% which was driven by a strong international demand in the prilled sulfur markets and being able to spread our margin to our sulfur-based product customers.

     Operating expenses. Our operating expenses increased $0.4 million, or 4%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This increase was a result of increased marine transportation expenses.

     Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased $0.2 million, or 15%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007.

38

     Depreciation and amortization. Depreciation and amortization expense increased $0.5 million, or 20%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. This is a result of our sulfuric acid plant becoming operational in late September 2007.

     In summary, our sulfur operating income increased $6.3 million, or 185%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007.

Statement of Operations Items as a Percentage of Revenues

     Our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization as a percentage of revenues for the three months and six months ended June 30, 2008 and 2007 are as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Revenues		100	%		100	%		100	%		100	%
Cost of products sold		87	%		78	%		86	%		78	%
Operating expenses		9	%		13	%		8	%		13	%
Selling, general and administrative expenses		1	%		2	%		1	%		2	%
Depreciation and amortization		2	%		3	%		2	%		3	%

Equity in Earnings of Unconsolidated Entities

     For the three and six months ended June 30, 2008 and 2007 equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom, Matagorda, PIPE and BCP.

     Equity in earnings of unconsolidated entities was $4.4 million for the three months ended June 30, 2008 compared to $2.4 million for the three months ended June 30, 2007, an increase of $2.0 million. This increase is related to earnings received from Waskom, Matagorda, PIPE and BCP.

     Equity in earnings of unconsolidated entities was $7.9 million for the six months ended June 30, 2008 compared to $4.5 million for the six months ended June 30, 2007, an increase of $3.4 million. This increase is related to earnings received from Waskom, Matagorda, PIPE and BCP.

Interest Expense

     Our interest expense for all operations was $3.9 million for the three months ended June 30, 2008, compared to the $2.7 million for the three months ended June 30, 2007, an increase of $1.2 million, or 44%. This increase was primarily due to recognized increases in interest expense of $0.6 million, related to the difference between the fixed rate and the floating rate of interest on the mark-to-market interest rate swap and an increase in average debt outstanding.

     Our interest expense for all operations was $8.6 million for the six months ended June 30, 2008, compared to the $6.3 million for the six months ended June 30, 2007, an increase of $2.3 million, or 37%. This increase was primarily due to recognized increases in interest expense of $1.4 million, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and an increase in average debt outstanding.

Indirect Selling, General and Administrative Expenses

     Indirect selling, general and administrative expenses were $1.3 million for the three months ended June 30, 2008 compared to $0.8 million for the three months ended June 30, 2007, an increase of $0.5 million, or 55%.

     Indirect selling, general and administrative expenses were $2.6 million for the six months ended June 30, 2008 compared to $1.6 million for the six months ended June 30, 2007, an increase of $1.0 million, or 65%.

39

     Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income. Under the omnibus agreement, the reimbursement amount 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. Martin Resource Management allocated indirect selling, general and administrative expenses of $0.6 million and $0.4 million for the three months ended June 30, 2008 and 2007, respectively, and $1.3 million and $0.8 million for the six months ended June 30, 2008 and 2007, respectively.

Liquidity and Capital Resources

     Cash Flows and Capital Expenditures

     For the six months ended June 30, 2008 cash increased $7.2 million as a result of $27.0 million provided by operating activities, $57.7 million used in investing activities and $37.8 million provided by financing activities. For the six months ended June 30, 2007, cash decreased $3.4 million as a result of $28.0 million provided by operating activities, $76.9 million used in investing activities and $45.8 million provided by financing activities.

     For the six months ended June 30, 2008 our investing activities of $57.7 million consisted of capital expenditures, acquisitions, proceeds from sale of property, plant and equipment, return of investments from unconsolidated entities and investments in and distributions from unconsolidated entities. For the six months ended June 30, 2007 our investing activities of $76.9 million consisted of capital expenditures, acquisitions, return of investments from unconsolidated entities, and investments in and distributions from unconsolidated partnerships.

     Generally, our capital expenditure requirements have consisted, and we expect that our capital requirements will continue to consist, of:

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

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

     For the six months ended June 30, 2008 and 2007, our capital expenditures for property and equipment were $58.7 million and $68.9 million, respectively.

     As to each period:

• For the six months ended June 30, 2008, we spent $53.7 million for expansion and $5.0 million for maintenance. Our expansion capital expenditures were made in connection with assets acquired in the Stanolind acquisition, marine vessel purchases and conversions and construction projects associated with our terminalling business. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements.

40

• For the six months ended June 30, 2007, we spent $64.9 million for expansion and $4.0 million for maintenance. Our expansion capital expenditures were made in connection with assets acquired in the Woodlawn and Mega Lubricants acquisitions, marine vessel purchases and conversions, construction projects associated with our terminalling business, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and include $0.1 million spent in connection with restoration of assets destroyed in Hurricanes Rita and Katrina.

     For the six months ended June 30, 2008, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $22.2 million, payments of long term debt to financial lenders of $100.8 million and borrowings of long-term debt under our credit facility of $160.8 million.

     For the six months ended June 30, 2007, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $17.3 million, net proceeds from a follow on equity offering of $55.9 million, payments of long term debt to financial lenders of $97.3 million, borrowings of long-term debt under our credit facility of $103.3 million and contributions of $1.2 million from our general partner.

     We made net investments in (received distributions from) unconsolidated entities of $(0.1) million and $5.8 million during the six months ended June 30, 2008 and 2007, respectively.  The net investment in unconsolidated entities includes $1.9 million and $6.1 million of expansion capital expenditures in the six months ended June 30, 2008 and 2007, respectively.

     Capital Resources

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

     As of June 30, 2008, we had $285.0 million of outstanding indebtedness, consisting of outstanding borrowings of $155.0 million under our revolving credit facility and $130.0 million under our term loan facility.

     On January 22, 2008, we financed the Stanolind asset acquisition through approximately $6.0 million in borrowings under our revolving credit facility.

     On October 2, 2007, we financed the Monarch acquisition through approximately $3.9 million in borrowings under our revolving credit facility.

     On June 13, 2007, we financed the Mega Lubricants acquisition through approximately $4.6 million in borrowings under our revolving credit facility.

     On May 2, 2007, we financed the Woodlawn acquisition through approximately $33.0 million in borrowings under our revolving credit facility.

     In May 2007, we completed a follow-on public offering of 1,380,000 common units, resulting in proceeds of $56.0 million, after payment of underwriters’ discounts, commissions, and offering expenses. Our general partner contributed $1.2 million in cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. The net proceeds were used to pay down revolving debt under our credit facility and to provide working capital.

     We believe that cash generated from operations, and our borrowing capacity under our credit facility, will be sufficient to meet our working capital requirements, anticipated capital expenditures and scheduled debt payments in 2008. However, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors — Risks Related to Our Business” in our Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008 for a discussion of such risks.

41

     Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of June 30, 2008 is as follows (dollars in thousands):

	Payment due by period
	Total		Less than		1-3		3-5		Due
Type of Obligation	Obligation		One Year		Years		Years		Thereafter
Long-Term Debt
Revolving credit facility	$	155,000	$	—	$	155,000	$	—	$	—
Term loan facility		130,000		—		130,000		—		—
Other		—		—		—		—		—
Non-competition agreements		600		250		200		100		50
Operating leases		27,031		3,813		9,610		4,998		8,610
Interest expense (1)
Revolving Credit Facility		21,927		9,254		12,673		—		—
Term loan facility		21,519		9,082		12,437		—		—
Other		—		—		—		—		—
Total contractual cash obligations	$	356,077	$	22,399	$	319,920	$	5,098	$	8,660

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

     Letter of Credit At June 30, 2008, we had an outstanding irrevocable letter of credit in the amount of $0.1 million which was issued under our revolving credit facility. This letter of credit was issued to the Texas Commission on Environmental Quality to provide financial assurance for our used oil handling program.

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

     Description of Our Credit Facility

     On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of credit sub-limit. Our credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25.0 million resulting in a committed $120.0 million revolving credit facility. Effective December 28, 2007, we increased our revolving credit facility $75.0 million resulting in a committed $195.0 million revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of June 30, 2008, we had $155.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of June 30, 2008, we had $39.9 million available under our revolving credit facility.

     On July 14, 2005, we issued a $0.1 million irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program.

     Draws made under our credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on our credit facilities have ranged from a low of $225.0 million to a high of $296.4 million. As of June 30, 2008, we had $39.9 million available for working capital, internal expansion and acquisition activities under our credit facility.

     Our obligations under the credit facility are secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, marine vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees. We may prepay all amounts outstanding under this facility at any time without penalty.

     Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans

42

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 2.00%. Effective July 1, 2008, the applicable margin for existing borrowings will remain 2.00%. As a result of our leverage ratio test, effective October 1, 2008, the applicable margin for existing borrowings will increase to 2.50%. We incur a commitment fee on the unused portions of the credit facility.

     Effective January 2008, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed rate. The fixed rate cost is 3.400% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in January, 2010 is accounted for using hedge accounting.

     Effective September 2007, we entered into 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.

     The credit facility also contains covenants, which, among other things, require us to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter there. We are in compliance with the debt covenants contained in the credit facility.

     On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. No prepayments under the term loan were required to be made through June 30, 2008. If we receive greater than $15.0 million from the incurrence of indebtedness other than under the credit facility, we must prepay indebtedness under the credit facility with all such proceeds in excess of $15.0 million. Any such prepayments are first applied to the term loans under the credit facility. We must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. We must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

     As of August 4, 2008, our outstanding indebtedness includes $297.6 million under our credit facility.

43

Seasonality

     A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season. The demand for fertilizers is strongest during the early spring planting season. However, our terminalling and storage and marine transportation businesses and the molten sulfur business are typically not impacted by seasonal fluctuations. We expect to derive a majority of our net income from our terminalling and storage, marine transportation and sulfur businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our terminalling and storage and marine transportation businesses. For example, Hurricanes Katrina and Rita in the third quarter of 2005 adversely impacted operating expenses and the four hurricanes that impacted the Gulf of Mexico and Florida in the third quarter of 2004 adversely impacted our terminalling and storage and marine transportation business’s revenues.

Impact of Inflation

     Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2008 and 2007. However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot assure you that we will be able to pass along increased costs to our customers.

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

Environmental Matters

     Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the six months ended June 30, 2008 or 2007.

44

Item 3. Quantitative and Qualitative Disclosures about Market Risk

     Commodity Price 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. 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. For the period ended June 30, 2008, 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 June 30, 2008.

     We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the commodity derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc., Wachovia Bank and Wells Fargo 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, 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 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 June 30, 2008, Prism Gas had hedged approximately 67%, 47%, 22% and 16% of its commodity risk by volume for 2008, 2009, 2010 and 2011, respectively. We anticipate entering into additional commodity derivatives on an ongoing basis to manage our risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that we will be able to do so or that the terms thereof will be similar to the our existing hedging arrangements. In addition, we will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil.

Hedging Arrangements in Place
As of June 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 ($86.52)	Mt. Belvieu (Non-TET)
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	Natural Gasoline	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

45

     Our 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 our natural gas and NGL sales are made at market-based prices. Our 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 us.

     Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 6.44% as of June 30, 2008. We had a total of $285.0 million of indebtedness outstanding under our credit facility as of the date hereof of which $90.0 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on June 30, 2008, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $0.9 million annually.

Item 4. Controls and Procedures

     Evaluation of disclosure controls and procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report, to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

     In response to the material weakness disclosed in our annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008, we have implemented new internal control procedures to improve the effectiveness of our review of identified reconciling items on product exchange reconciliations. These remedial actions include additional review by our internal accounting staff and enhanced documentation related to such review.

     Changes in internal controls. Except as described above, there were no other changes in our internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

46

PART II. OTHER INFORMATION

Item 1. 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 an 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 employees of Martin Resource Management who provide services to us were served with grand jury subpoenas during the fourth quarter of 2007. We are cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against us.

Item 1A. Risk Factors

     There have been no material changes in our risk factors from those disclosed in “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008. Please see “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008.

Item 5. Other Information.

     On May 2, 2008, we received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management Corporation (“Martin Resource Management”), the parent company of Martin Midstream GP, LLC (“Martin Midstream GP”), our general partner. The Plaintiff and the Defendant are directors and executive officers of both Martin Resource Management and Martin Midstream GP. The lawsuit alleges that the Defendant breached a settlement agreement with the Plaintiff concerning certain Martin Resource Management matters and that the Defendant breached fiduciary duties allegedly owed to the Plaintiff in connection with their respective ownership and other positions with Martin Resource Management. We are not a party to the lawsuit and the lawsuit does not assert any claims (i) against us, (ii) concerning the our governance or operations or (iii) against the Defendant with respect to his service as an officer or director of Martin Midstream GP. The lawsuit is not expected to affect the financial condition or operation of us or Martin Midstream GP.

Item 6. Exhibits

     The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.

47

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

	Martin Midstream Partners L.P.
	By:	Martin Midstream GP LLC Its General Partner
Date: August 5, 2008		By:	/s/ Ruben S. Martin
			Ruben S. Martin
			President and Chief Executive Officer

48

INDEX TO EXHIBITS

Exhibit
Number	Exhibit Name
3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.2	First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 6, 2002 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
3.3	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 2, 2007, and incorporated herein by reference).
3.4	Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated effective January 1, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed April 7, 2008, and incorporated herein by reference).
3.5	Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.6	Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
3.7	Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.8	Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 33-91706), filed July 1, 2002, and incorporated herein by reference).
3.9	Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.10	Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
4.1	Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
4.2	Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
99.1*	Balance Sheets as of June 30, 2008 (unaudited) and December 31, 2007 (audited) of the General Partner.

* Filed or furnished herewith

49

EX-31.1

Exhibit 31.1

CERTIFICATION
PURSUANT TO AND IN CONNECTION WITH THE
REPORTS
TO BE FILED UNDER SECTION 13 AND 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934, AS AMENDED

I, Ruben S. Martin, certify that:

     1. I have reviewed this quarterly report on Form 10-Q 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 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: August 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.

EX-31.2

Exhibit 31.2

CERTIFICATION
PURSUANT TO AND IN CONNECTION WITH THE
REPORTS
TO BE FILED UNDER SECTIONS 13 AND 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934, AS AMENDED

     I, Robert D. Bondurant, certify that:

          1. I have reviewed this quarterly report on Form 10-Q 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 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: August 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.

EX-32.1

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 Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ending June 30, 2008 as filed with the Securities and Exchange Commission (the “Report”), I, Ruben S. Martin, 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 results of operations of the Partnership.

/s/ Ruben S. Martin Ruben S. Martin,

Chief Executive Officer of Martin Midstream GP LLC,

General Partner of Martin Midstream Partners L.P.

August 5, 2008

* A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

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 Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ending June 30, 2008 as filed with the Securities and Exchange Commission (the “Report”), I, Robert D. Bondurant, 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 results of operations of the Partnership.

/s/ Robert D. Bondurant Robert D. Bondurant,

Chief Financial Officer of Martin Midstream GP LLC,
General Partner of Martin Midstream Partners L.P.

August 5, 2008

* A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

MARTIN MIDSTREAM GP LLC
CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands)

	June 30,			December 31,
	2008			2007
	(Unaudited)			(Audited)
Assets
Cash	$	11,273		$	4,113
Accounts and other receivables, less allowance for doubtful accounts of $350 and $211, respectively		110,998			88,039
Product exchange receivables		42,148			10,912
Inventories		101,832			51,798
Due from affiliates		8,336			2,325
Fair value of derivatives		—			235
Other current assets		7,093			584
Total current assets		281,680			158,006
Property, plant and equipment, at cost		497,323			441,117
Accumulated depreciation		(110,332	)		(98,080	)
Property, plant and equipment, net		386,991			343,037
Goodwill		37,405			37,405
Investment in unconsolidated entities		77,276			75,690
Fair value of derivatives		42			—
Other assets, net		8,493			9,439
	$	791,887		$	623,577
Liabilities and Members’ Equity
Current installments of long-term debt	$	—		$	21
Trade and other accounts payable		169,144			104,598
Product exchange payables		70,856			24,554
Due to affiliates		10,948			9,323
Income taxes payable		957			974
Fair value of derivatives		13,083			4,502
Other accrued liabilities		4,717			4,762
Total current liabilities		269,705			48,734
Long-term debt		285,000			225,000
Deferred income taxes		9,204			9,244
Fair value of derivatives		11,535			5,575
Other long-term obligations		1,586			1,768
Total liabilities		577,030			390,321
Minority interests		212,613			231,737
Members’ equity		2,244			1,519
		214,857			233,256
Commitments and contingencies	$	791,887		$	623,577

See accompanying notes to the consolidated and condensed balance sheets.

1

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

(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 (“Martin Resource Management”).

     In September 2005 the FASB ratified EITF Issue 04-5, a framework for addressing when a limited company should be consolidated by its general partner. The framework presumes that a sole general partner in a limited company controls the limited company, and therefore should consolidate the limited company. The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited company or (b) substantive participating rights. The EITF reached a conclusion on the circumstances in which either kick-out rights or participating rights would be considered substantive and preclude consolidation by the general partner. Based on the guidance in the EITF, the General Partner concluded that the Company should be consolidated. As such, the accompanying balance sheets have been consolidated to include the General Partner and the Company.

     The Company is a publicly traded limited partnership which provides terminalling and storage services for petroleum products and by-products, natural gas services, marine transportation services for petroleum products and by-products, and sulfur and sulfur based products processing, manufacturing, marketing and distribution.

     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 (“PIPE”) each accounted for under the equity method of accounting.

     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.

(2) SIGNIFICANT ACCOUNTING POLICIES

     (a) Principles of Presentation and Consolidation

     The consolidated and condensed balance sheets include the financial position of the General Partner and the Company and its wholly-owned subsidiaries. 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 and condensed balance sheets in accordance with FIN 46(R). No such variable interest entities exist as of June 30, 2008 and December 31, 2007.

     (b) 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 and condensed balance sheets in conformity with U.S. generally accepted accounting principles. Actual results could differ from those estimates.

2

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

     (c) 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 2008. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.

     The Company issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in May 2007. These units vest in 25% increments beginning in January 2008 and will be fully vested in January 2011.

     The Company issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in January 2006. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010.

     The Company accounts for the transaction under Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based payment transactions was $17 and $15 for the three months ended June 30, 2008 and 2007, respectively, and $34 and $26 for the six months ended June 30, 2008 and 2007, respectively. The General Partner contributed cash of $2 in January 2006 and $3 in May 2007 to the Company in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Company. The 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 Company.

     (d) 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 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 June 30, 2008 and 2007 the General Partner received $590 and $240, respectively, in incentive distributions. For the six months ended June 30, 2008 and 2007, the General Partner received $1,091 and $402, respectively, in incentive distributions.

     (e) Reclassification

     The Company 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.

     (f) Income Taxes

     The Company is a disregarded entity for federal income tax purposes. Its activity is included in the consolidated federal income tax return of Martin Resource Management; 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 Company 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.

3

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

     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 $9,204 and $9,254 ($10 of which is included in other accrued liabilities) at June 30, 2008 and December 31, 2007, respectively.

     The operations of the Company are generally not subject to income taxes and as a result, the Company’s income is taxed directly to its owners, except for the Texas Margin Tax as described below and the taxes associated with Woodlawn as previously discussed.

     On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component.  Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax.  In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date.   Therefore, the Company has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change and subsequent changes in deferred tax assets and liabilities are immaterial. At June 30, 2008 and December 31, 2007, the Company has recorded a liability attributable to the Texas Margin tax of $426 and $538, respectively.

     In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Company adopted FIN 48 effective January 1, 2007. There was no impact to the Company’s financial statements as a result of adopting FIN 48.

(3) NEW ACCOUNTING PRONOUNCEMENTS

     In 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 Company adopted the portion of SFAS No. 157 that was not delayed, and since the Company’s existing fair value measurements are consistent with the guidance of SFAS No. 157, the partial adoption of SFAS No. 157 did not have a material impact on the Company’s consolidated and condensed financial statements. The adoption of the deferred portion of SFAS No. 157 on January 1, 2009 is not expected to have a material impact on the Company’s consolidated and condensed financial statements. See Note 4 for expanded disclosures about fair value measurements.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value

4

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. 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 Company currently has no plans to apply SFAS No. 159.

     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 Company will apply the guidance of SFAS No. 141 to business combinations completed on or after 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 Company is currently evaluating the impact of adopting SFAS No. 160 on January 1, 2009.

     In March 2008, the 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 Company is evaluating the additional disclosures required by SFAS No. 161 beginning January 1, 2009.

(4) FAIR VALUE MEASUREMENTS

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

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

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

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

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

     The Company’s derivative instruments which consist of commodity and interest rate swaps are required to be measured at fair value on a recurring basis. The fair value of the Company’s derivative instruments are 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 Company’s derivative instruments and hedging activities.

     As prescribed by the FAS 157 levels listed above, the Company considers the Company’s derivative assets and liabilities as Level 2. The net fair value of the Company’s assets and liabilities measured on a recurring basis was a liability of $24,576 and $9,843 at June 30, 2008 and December 31, 2007, respectively.

(5) ACQUISITIONS

     (a) Stanolind Assets. In January 2008, The Company acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management for $5,983

5

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

which was allocated to property, plant and equipment. The Company entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks.

     (b) Asphalt Terminal. In October 2007, the Company 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 and condensed balance sheets beginning October 2, 2007. The assets are located in Omaha, Nebraska. The Company 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.

     (c) Lubricants Terminal In June 2007, the Company 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 and condensed balance sheet 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 Company’s access to capital and existing infrastructure. This will enhance the Company’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	)
Total	$	4,738

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

     (d) Woodlawn Pipeline Co., Inc. On May 2, 2007, the Company, through its subsidiary Prism Gas, acquired 100% of the outstanding stock of Woodlawn. The results of Woodlawn’s operations have been included in the consolidated and condensed balance sheets 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 Company’s access to capital and existing infrastructure. This will enhance the Company’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.

6

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

     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 Company’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	$	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	)
Total	$	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 Company borrowed approximately $33,000 under its credit facility.

(6) INVENTORIES

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

	June 30,		December 31,
	2008		2007
Natural gas liquids	$	26,715	$	31,283
Sulfur		50,977		7,490
Sulfur Based Products		14,303		6,626
Lubricants		7,402		5,345
Other		2,435		1,054
	$	101,832	$	51,798

(7) PROPERTY, PLANT AND EQUIPMENT

     At June 30, 2008 and December 31, 2007, property, plant, and equipment consisted of the following:

			June 30,		December 31,
			2008		2007
	Depreciable Lives		(Unaudited)		(Audited)
Land		—	$	15,647	$	14,515
Improvements to land and buildings	10-39 years			40,202		34,585
Transportation equipment	3- 7 years			1,855		616
Storage equipment	5-20 years			43,304		38,652
Marine vessels	4-30 years			180,025		147,627
Operating equipment	3-30 years			181,298		172,282
Furniture, fixtures and other equipment	3-20 years			1,611		1,542
Construction in progress				33,381		31,298
			$	497,323	$	441,117

7

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

(8) RELATED PARTY TRANSACTIONS

     Amounts due to and due from affiliates in the consolidated balance sheets as of June 30, 2008 (unaudited) and December 31, 2007, are primarily with Martin Resource Management and its affiliates and 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, fertilizer products; land and marine transportation services; terminalling and storage services, and other purchases of products and services representing operating expenses.

(9) INVESTMENT IN UNCONSOLIDATED COMPANIES AND JOINT VENTURES

     The Company, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom, Matagorda, 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 $297 for the three and six months June 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 $10,388 and $10,685 at June 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 six months of 2008 or the year ended December 31, 2007.

     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.

     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
Acquisitions of interests		—			—		—		—		—
Distributions in kind from equity investments		(5,621	)		—		—		—		(5,621	)
Return on investments from unconsolidated entities		—			—		—		—		—

8

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

	Waskom			PIPE			Matagorda			BCP			Total
Contributions to (distributions from) unconsolidated entities:
Cash contributions		500			—			—			80			580
Distributions from (contributions to) unconsolidated entities for operations		(655	)		—			—			—			(655	)
Return of investments from unconsolidated entities		(300	)		(105	)		(195	)		—			(600	)
Equity in earnings:
Equity in earnings from operations		7,875			84			302			(82	)		8,179
Amortization of excess investment		(275	)		(8	)		(14	)		—			(297	)
Investment in unconsolidated entities, June 30, 2008	$	71,761		$	1,553		$	3,786		$	176		$	77,276

	Waskom			PIPE			Matagorda			BCP			Total
Investment in unconsolidated entities, December 31, 2006	$	64,937		$	1,718		$	3,786		$	210		$	70,651
Acquisitions of interests		—						— —			—			—
Distributions in kind from equity investments		(4,541	)		—			—			—			(4,541	)
Return on investments from unconsolidated entities		—			(200	)		—			—			(200	)
Contributions to (distributions from) unconsolidated entities:
Cash contributions		—			—			—			—			—
Distributions from (contributions to) unconsolidated entities for operations		5,670			—			—			107			5,777
Return of investments from unconsolidated entities		(2,625	)		(270	)		(75	)		—			(2,970	)
Equity in earnings:
Equity in earnings from operations		4,301			419			110			(65	)		4,765
Amortization of excess investment		(275	)		(8	)		(14	)		—			(297	)
Investment in unconsolidated entities, June 30, 2007	$	67,467		$	1,659		$	3,807		$	252		$	73,185

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

	As of June 30,
	Total		Partner’s
2008	Assets		Capital
Waskom	$	75,929	$	60,745

2007	As of December 31,
Waskom	$	66,772	$	57,149

(10) LONG-TERM DEBT

     At June 30, 2008 and December 31, 2007, long-term debt consisted of the following:

	June 30,		December 31,
	2008		2007
**$195,000 Revolving loan facility at variable interest rate (5.97%* weighted average at June 30, 2008), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees	$	155,000	$	95,000

9

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

	June 30,		December 31,
	2008		2007
***$130,000 Term loan facility at variable interest rate (6.99%* at June 30, 2008), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries		130,000		130,000
Other secured debt maturing in 2008, 7.25%		—		21
Total long-term debt		285,000		225,021
Less current installments		—		21
Long-term debt, net of current installments	$	285,000	$	225,000

*	Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. Effective July 1, 2008, the applicable margin for existing borrowings will remain 2.00%. As a result of our leverage ratio test as of June 30, 2008, effective October 1, 2008, the applicable margin for existing borrowings will increase to 2.50%. The Company incurs a commitment fee on the unused portions of the credit facility.
**	Effective January, 2008, the Company entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 3.400% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in January, 2010.
**	Effective September, 2007, the Company entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in September, 2010.
**	Effective November, 2006, the Company entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 4.82% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in December, 2009.
***	The $130,000 term loan has $105,000 hedged. Effective March, 2006, the Company entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010. Effective November 2006, the Company entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This cash flow hedge matures in March, 2010.

     On November 10, 2005, the Company entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the Company increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. Effective December 28, 2007, the Company increased its revolving credit facility $75,000 resulting in a committed $195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general Company purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of June 30, 2008, the Company had $155,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of June 30, 2008, the Company had $39,880 available under its revolving credit facility.

10

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

     On July 14, 2005, the Company issued a $120 irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program.

     The Company’s obligations under the credit facility are secured by substantially all of the Company’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Company may prepay all amounts outstanding under this facility at any time without penalty.

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

     The credit facility also contains covenants, which, among other things, require the Company to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to EBITDA of not more than 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 year ended December 31, 2007 and as of June 30, 2008.

     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 June 30, 2008. If the Company receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Company must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Company must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

     Draws made under the Company’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Company’s credit facility have ranged from a low of $225,000 to a high of $296,400. As of June 30, 2008, the Company had $39,880 available for working capital, internal expansion and acquisition activities under the Company’s credit facility.

     In connection with the Company’s Stanolind asset acquisition on January 22, 2008, the Company borrowed approximately $6,000 under its revolving credit facility.

     In connection with the Company’s Monarch acquisition on October 2, 2007, the Company borrowed approximately $3,900 under its revolving credit facility.

     In connection with the Company’s Mega Lubricants acquisition on June 13, 2007, the Company borrowed approximately $4,600 under its revolving credit facility.

     In connection with the Company’s Woodlawn acquisition on May 2, 2007, the Company borrowed approximately $33,000 under its revolving credit facility.

11

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

(11) INTEREST RATE CASH FLOW HEDGES 

     The Company 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 Company designated these swap agreements as cash flow hedges. Under these swap agreements, the Company pays a fixed rate of interest and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because these swaps are designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of these hedges, these swaps were identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and these swaps remain equal. This condition results in a 100% effective swap for the following hedges:

Date of Hedge	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 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 June 30, 2008 with an offset to current operations.

     The Company recognized increases in interest expense of $193 and $966 for the three and six months ended June 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.

     The Company recognized decreases in interest expense of $403 and $431 for the three and six months ended June 30, 2007, 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.

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

	June 30,			December 31,
	2008			2007
Fair value of derivative assets — long-term		42		$	—
Fair value of derivative liabilities — current		(3,190	)		(1,241	)
Fair value of derivative liabilities — long term		(2,038	)		(3,436	)
Net fair value of derivatives	$	(5,186	)	$	(4,677	)

(12) COMMODITY CASH FLOW HEDGES

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

     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.

12

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

     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. The Company has adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges.

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

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

	June 30,			December 31,
	2008			2007
Fair value of derivative assets — current	$	—		$	235
Fair value of derivative assets — long term		—			—
Fair value of derivative liabilities — current		(9,799	)		(3,261	)
Fair value of derivative liabilities — long term		(9,591	)		(2,140	)
Net fair value of derivatives	$	(19,390	)	$	(5,166	)

     Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2008 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of June 30, 2008, the remaining term of the contracts extend no later than December 2011, 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., Wachovia Bank and Wells Fargo Bank. For the period ended June 30, 2008, 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 June 30, 2008.

June 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	July 2008 to December 2008		(904	)
Crude Oil Swap	3,000 BBL	Fixed price of $70.75 settled against WTI NYMEX average monthly closings	July 2008 to December 2008		(1,240	)
Crude Oil Swap	3,000 BBL	Fixed price of $69.08 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(2,418	)
Crude Oil Swap	3,000 BBL	Fixed price of $70.90 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(2,357	)
Total swaps not designated as cash flow hedges				$	(6,919	)

13

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

June 30, 2008
	Total
	Volume		Remaining Terms
Transaction Type	Per Month	Pricing Terms	of Contracts	Fair Value
Cash Flow Hedges:
Crude Oil Swap	5,000 BBL	Fixed price of $66.20 settled against WTI NYMEX average monthly closings	July 2008 to December 2008		(2,201	)
Ethane Swap	5,000 BBL	Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings	July 2008 to December 2008		(720	)
Natural Gasoline Swap	3,000 BBL	Fixed price of $86.52 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.	July 2008 to September 2008		(369	)
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		(377	)
Natural Gas swap	30,000 MMBTU	Fixed price of $9.025 settled against Inside Ferc Columbia Gulf daily average	January 2009 to December 2009		(1,144	)
Crude Oil Swap	1,000 BBL	Fixed price of $70.45 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(791	)
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		(929	)
Crude Oil Swap	2,000 BBL	Fixed price of $69.15 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(1,461	)
Crude Oil Swap	3,000 BBL	Fixed price of $72.25 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(2,093	)
Crude Oil Swap	1,000 BBL	Fixed price of $104.80 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(355	)
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		(335	)
Crude Oil Swap	2,000 BBL	Fixed price of $99.15 settled against WTI NYMEX average monthly closings	January 2011 to December 2011		(744	)
Crude Oil Swap	1,000 BBL	Fixed price of $103.80 settled against WTI NYMEX average monthly closings	January 2011 to December 2011		(326	)
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		(626	)
Total swaps designated as cash flow hedges				$	(12,471	)
Total net fair value of derivatives				$	(19,390	)

     On all transactions where the Company is exposed to counterparty risk, the Company analyzes the

14

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

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 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, 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 June 30, 2008, Prism Gas had hedged approximately 67%, 47%, 22% and 16% of its commodity risk by volume for 2008, 2009, 2010, and 2011, 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.

Hedging Arrangements in Place
As of June 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 ($86.52)	Mt. Belvieu (Non-TET)
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	Natural Gasoline	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

     The Company’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 Company’s natural gas and NGL sales are made at market-based prices. The Company’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Company.

(13) 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

15

MARTIN MIDSTREAM GP LLC
NOTES TO CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands, except where otherwise indicated)
June 30, 2008
(Unaudited)

in dollars, not thousands). Following this offering, the common units represented an 82.4% 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	$	58,305
General partner contribution		1,190
Total proceeds received	$	59,495
Use of Proceeds:
Underwriter’s fees	$	2,107
Professional fees and other costs		265
Repayment of debt under revolving credit facility		55,850
Working capital		1,273
Total use of proceeds	$	59,495

(14) 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 the Company’s tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, the Company has been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two employees of Martin Resource Management who provide services to the Company were served with grand jury subpoenas during the fourth quarter of 2007. The Company is cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against the Company.

16