e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2008


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

For the transition period from to

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.

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

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

Yes o No þ

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

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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


	September 30,			December 31,
	2008			2007
	(Unaudited)			(Audited)
Assets

Cash	$	7,019		$	4,113
Accounts and other receivables, less allowance for doubtful accounts of $392 and $211, respectively		105,334			88,039
Product exchange receivables		32,323			10,912
Inventories		78,002			51,798
Due from affiliates		7,929			2,325
Fair value of derivatives		354			235
Other current assets		2,132			584

Total current assets		233,093			158,006


Property, plant and equipment, at cost		516,420			441,117
Accumulated depreciation		(117,752	)		(98,080	)

Property, plant and equipment, net		398,668			343,037


Goodwill		37,405			37,405
Investment in unconsolidated entities		79,687			75,690
Fair value of derivatives		159			—
Other assets, net		8,006			9,439

	$	757,018		$	623,577


Liabilities and Partners’ Capital

Current installments of long-term debt	$	—		$	21
Trade and other accounts payable		158,904			104,598
Product exchange payables		47,298			24,554
Due to affiliates		17,500			7,543
Income taxes payable		398			602
Fair value of derivatives		5,657			4,502
Other accrued liabilities		5,711			4,752

Total current liabilities		235,468			146,572

Long-term debt		280,000			225,000
Deferred income taxes		8,593			8,815
Fair value of derivatives		4,933			5,576
Other long-term obligations		1,716			1,766

Total liabilities		530,710			387,729


Partners’ capital		234,803			242,610
Accumulated other comprehensive income (loss)		(8,495	)		(6,762	)

Total partners’ capital		226,308			235,848

Commitments and contingencies

	$	757,018		$	623,577

See accompanying notes to consolidated and condensed financial statements.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Revenues:
Terminalling and storage	$	8,527		$	7,570		$	26,347		$	21,558
Marine transportation		20,116			15,469			55,828			44,507
Product sales:
Natural gas services		188,200			120,994			577,317			328,103
Sulfur services		133,276			29,866			289,528			89,599
Terminalling and storage		14,267			10,951			36,525			19,193

		335,743			161,811			903,370			436,895

Total revenues		364,386			184,850			985,545			502,960


Costs and expenses:
Cost of products sold:
Natural gas services		178,996			115,112			562,170			312,823
Sulfur services		121,158			22,515			253,462			66,732
Terminalling and storage		11,031			10,004			31,222			16,936

		311,185			147,631			846,854			396,491

Expenses:
Operating expenses		26,093			21,528			76,505			61,184
Selling, general and administrative		3,726			2,890			10,672			8,355
Depreciation and amortization		7,979			6,236			22,933			16,598

Total costs and expenses		348,983			178,285			956,964			482,628

Other operating income (loss)		17			—			143			—

Operating income		15,420			6,565			28,724			20,332


Other income (expense):
Equity in earnings of unconsolidated entities		3,503			2,736			11,385			7,204
Interest expense		(4,971	)		(3,640	)		(13,609	)		(9,956	)
Other, net		87			54			334			205

Total other income (expense)		(1,381	)		(850	)		(1,890	)		(2,547	)

Net income before taxes		14,039			5,715			26,834			17,785
Income tax benefit (expense)		(292	)		(212	)		(753	)		(552	)

Net income	$	13,747		$	5,503		$	26,081		$	17,233


General partner’s interest in net income	$	941		$	465		$	2,257		$	1,094
Limited partners’ interest in net income	$	12,806		$	5,038		$	23,824		$	16,139

Net income per limited partner unit — basic and diluted	$	0.88		$	0.35		$	1.64		$	1.17

Weighted average limited partner units — basic		14,532,826			14,532,826			14,532,826			13,845,573
Weighted average limited partner units — diluted		14,534,972			14,536,939			14,535,025			13,849,749

See accompanying notes to consolidated and condensed financial statements.

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


	Partners’ Capital
														Accumulated
														Other
											General			Comprehensive
	Common					Subordinated					Partner			Income
	Units		Amount			Units		Amount			Amount			Amount			Total

Balances — January 1, 2007		10,603,808	$	201,387			2,552,018	$	(6,237	)	$	3,253		$	122		$	198,525
Net Income		—		13,454			—		2,685			1,094			—			17,233
Follow-on public offering		1,380,000		55,933			—		—			—			—			55,933
General partner contribution		—		—			—		—			1,192			—			1,192
Cash distributions		—		(21,272	)		—		(4,900	)		(1,223	)		—			(27,395	)
Unit-based compensation		3,000		34			—		—			—			—			34
Adjustment in fair value of derivatives		—		—			—		—			—			( 2,172	)		(2,172	)

Balances — September 30, 2007		11,986,808	$	249,536			2,552,018	$	(8,452	)	$	4,316		$	(2,050	)	$	243,350


Balances — January 1, 2008		12,837,480	$	244,520			1,701,346	$	(6,022	)	$	4,112		$	(6,762	)	$	235,848
Net income		—		21,532			—		2,292			2,257			—			26,081
Cash distributions		—		(27,729	)		—		(3,675	)		(2,448	)		—			(33,852	)
Unit-based compensation		—		57			—		—			—			—			57
Purchase of treasury units		—		(93	)		—		—			—			—			(93	)
Adjustment in fair value of derivatives		—		—			—		—			—			(1,733	)		(1,733	)

Balances —September 30, 2008		12,837,480	$	238,287			1,701,346	$	(7,405	)	$	3,921		$	(8,495	)	$	226,308

See accompanying notes to consolidated and condensed financial statements.

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


	Nine Months Ended
	September 30,
	2008			2007
Cash flows from operating activities:
Net income	$	26,081		$	17,233

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		22,933			16,598
Amortization of deferred debt issuance costs		840			810
Deferred taxes		(222	)		(111	)
Gain on sale of property, plant and equipment		(143	)		—
Equity in earnings of unconsolidated entities		(11,385	)		(7,204	)
Distributions from unconsolidated entities		—			673
Distributions in-kind from equity investments		8,392			6,628
Non-cash mark-to-market on derivatives		(1,499	)		2,036
Other		57			45
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		(17,295	)		(4,899	)
Product exchange receivables		(21,411	)		(4,067	)
Inventories		(26,204	)		(6,346	)
Due from affiliates		(5,604	)		(1,787	)
Other current assets		(1,548	)		(167	)
Trade and other accounts payable		54,306			22,429
Product exchange payables		22,744			(2,388	)
Due to affiliates		9,957			(5,055	)
Income taxes payable		(204	)		365
Other accrued liabilities		959			903
Change in other non-current assets and liabilities		(111	)		(94	)

Net cash provided by operating activities		60,643			35,602


Cash flows from investing activities:
Payments for property, plant and equipment		(72,185	)		(57,524	)
Acquisitions, net of cash acquired		(5,983	)		(37,344	)
Proceeds from sale of property, plant and equipment		419			4
Return of investments from unconsolidated entities		995			2,642
Distributions from (contributions to) unconsolidated entities for operations		(1,999	)		(6,130	)

Net cash used in investing activities		(78,753	)		(98,352	)


Cash flows from financing activities:
Payments of long-term debt		(180,391	)		(125,105	)
Proceeds from long-term debt		235,370			161,050
Purchase of treasury units		(93	)		—
Net proceeds from follow on public offering		—			55,933
General partner contribution		—			1,192
Payments of debt issuance costs		(18	)		—
Cash distributions paid		(33,852	)		(27,395	)

Net cash provided by financing activities		21,016			65,675


Net increase in cash		2,906			2,925
Cash at beginning of period		4,113			3,675

Cash at end of period	$	7,019		$	6,600

See accompanying notes to consolidated and condensed financial statements.

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

(1)

General

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

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

(a)

Use of Estimates

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

(b)

Unit Grants

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

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

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

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

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

(c)

Incentive Distribution Rights

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

(d)

Net Income per Unit

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

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

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

(e)

Income taxes

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

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

consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(f)

Reclassification

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

(2)

New Accounting Pronouncements

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

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

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

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

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

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

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

(3)

Fair Value Measurements

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

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

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

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

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

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

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

(4)

Acquisitions

(a)

Stanolind Assets

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

(b)

Asphalt Terminal

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

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

(c)

Lubricants Terminal

In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) located in Channelview, Texas. The results of Mega Lubricant’s operations have been included in the consolidated financial statements beginning June 13, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $1,020 was recorded as goodwill. The goodwill was a result of Mega Lubricant’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional lubricant blending and truck loading and unloading services to customers. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment. The terminal is located on 5.6 acres of land, and consists of 38 tanks with a storage capacity of approximately 15,000 Bbls, pump and piping infrastructure for lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an administrative office.

The purchase price of $4,738, including two three-year non-competition agreements totaling $530 and goodwill of $1,020, was allocated as follows:


Current assets	$	446
Property, plant and equipment, net		3,042
Goodwill		1,020
Other assets		530
Other liabilities		(300	)

	$	4,738

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

(d)

Woodlawn Pipeline Co., Inc.

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

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

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

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

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


Current assets	$	4,297
Property, plant and equipment, net		29,101
Goodwill		8,785
Other assets		3,339
Current liabilities		(3,889	)
Deferred income taxes		(8,964	)
Other long-term obligations		(63	)

	$	32,606

The identifiable intangible assets of $3,339 are subject to amortization over a weighted-average useful life of approximately ten years. The intangible assets include four non-competition agreements totaling $40, customer contracts associated with the gathering and processing assets of $3,002, and a transportation contract associated with the residue gas pipeline of $297.

In connection with the acquisition, the Partnership borrowed approximately $33,000 under its credit facility.

(5)

Inventories

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


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

	$	78,002	$	51,798

(6)

Investment in Unconsolidated Partnerships and Joint Ventures

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

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

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

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

Activity related to these investment accounts is as follows:


	Waskom			PIPE			Matagorda			BCP			Total

Investment in unconsolidated entities, December 31, 2007	$	70,237		$	1,582		$	3,693		$	178		$	75,690

Distributions in kind from equity investments		(8,392	)		—			—			—			(8,392	)
Return on investments from unconsolidated entities		—			—			—			—			—
Contributions to (distributions from) unconsolidated entities:
Cash contributions		1,250			—			—			80			1,330
Distributions from (contributions to) unconsolidated entities for operations		669			—			—			—			669
Return of investments from unconsolidated entities		(300	)		(180	)		(515	)		—			(995	)
Equity in earnings:
Equity in earnings from operations		11,451			17			485			(124	)		11,829
Amortization of excess investment		(412	)		(11	)		(21	)		—			(444	)


Investment in unconsolidated entities, September 30, 2008	$	74,503		$	1,408		$	3,642		$	134		$	79,687


	Waskom			PIPE			Matagorda			BCP			Total

Investment in unconsolidated entities, December 31, 2006	$	64,937		$	1,718		$	3,786		$	210		$	70,651

Distributions in kind from equity investments		(6,628	)		—			—			—			(6,628	)
Return on investments from unconsolidated entities		—			(200	)		—			—			(200	)
Contributions to (distributions from) unconsolidated entities:
Cash contributions		—			—			—			—			—
Distributions from (contributions to) unconsolidated entities for operations		6,023			—			—			107			6,130
Return of investments from unconsolidated entities		(2,625	)		(365	)		(125	)		—			(3,115	)
Equity in earnings:
Equity in earnings from operations		7,205			464			78			(99	)		7,648
Amortization of excess investment		(412	)		(11	)		(21	)		—			(444	)


Investment in unconsolidated entities, September 30, 2007	$	68,500		$	1,606		$	3,718		$	218		$	74,042

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


					Three Months Ended				Nine Months Ended
	As of September 30,				September 30,				September 30,
	Total		Partner’s				Net				Net
	Assets		Capital		Revenues		Income		Revenues		Income
2008
Waskom	$	87,618	$	66,506	$	34,113	$	7,154	$	96,653	$	22,902


	As of December 31,

2007
Waskom	$	66,772	$	57,149	$	21,293	$	5,808	$	54,466	$	14,410

(7)

Commodity Cash Flow Hedges

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

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

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

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

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

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


	Three Months Ended					Nine Months Ended
	September 30					September 30
	2008		2007			2008			2007

Change in fair value of derivatives that do not qualify for hedge accounting and settlements of maturing hedges	$	2,718	$	(572	)	$	(5,428	)	$	(1,365	)

Ineffective portion of derivatives qualifying for hedge accounting		2,091		(199	)		2,128			(109	)


Change in fair value of derivatives in the Consolidated Statement of Operations	$	4,809	$	(771	)	$	(3,300	)	$	(1,474	)

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


	September 30,			December 31,
	2008			2007

Fair value of derivative assets — current	$	354		$	235
Fair value of derivative assets — long term		159			—
Fair value of derivative liabilities — current		(2,738	)		(3,261	)
Fair value of derivative liabilities — long term		(2,606	)		(2,140	)

Net fair value of derivatives	$	(4,831	)	$	(5,166	)

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

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


September 30, 2008
	Total
	Volume		Remaining Terms
Transaction Type	Per Month	Pricing Terms	of Contracts	Fair Value


Mark-to-Market Derivatives:

Natural Gas swap	30,000 MMBTU	Fixed price of $8.12 settled against Houston Ship Channel first of the month	October 2008 to December 2008	$	74

Crude Oil Swap	3,000 BBL	Fixed price of $70.75 settled against WTI NYMEX average monthly closings	October 2008 to December 2008		(259	)

Crude Oil Swap	3,000 BBL	Fixed price of $69.08 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(1,130	)

Crude Oil Swap	3,000 BBL	Fixed price of $70.90 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(1,068	)

Total swaps not designated as cash flow hedges				$	(2,383	)


Cash Flow Hedges:

Crude Oil Swap	5,000 BBL	Fixed price of $66.20 settled against WTI NYMEX average monthly closings	October 2008 to December 2008	$	(499	)

Ethane Swap	5,000 BBL	Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings	October 2008 to December 2008		(22	)

Natural Gasoline Swap	3,000 BBL	Fixed price of $85.79 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.	October 2008 to December 2008		(6	)

Natural Gas swap	30,000 MMBTU	Fixed price of $9.025 settled against Inside Ferc Columbia Gulf daily average	January 2009 to December 2009		321

Crude Oil Swap	1,000 BBL	Fixed price of $70.45 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(361	)

Natural Gasoline Swap	2,000 BBL	Fixed price of $86.42 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.	January 2009 to December 2009		(61	)

Crude Oil Swap	2,000 BBL	Fixed price of $69.15 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(759	)

Crude Oil Swap	3,000 BBL	Fixed price of $72.25 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(1,039	)

Crude Oil Swap	1,000 BBL	Fixed price of $104.80 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		2

Natural Gasoline Swap	1,000 BBL	Fixed price of $94.14 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings	January 2010 to December 2010		47

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


September 30, 2008
	Total
	Volume		Remaining Terms
Transaction Type	Per Month	Pricing Terms	of Contracts	Fair Value


Crude Oil Swap	2,000 BBL	Fixed price of $99.15 settled against WTI NYMEX average monthly closings	January 2011 to December 2011		(124	)

Crude Oil Swap	1,000 BBL	Fixed price of $103.80 settled against WTI NYMEX average monthly closings	January 2011 to December 2011		(15	)

Natural Gasoline Swap	2,000 BBL	Fixed price of $93.18 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings	January 2011 to December 2011		68


Total swaps designated as cash flow hedges				$	(2,448	)


Total net fair value of derivatives				$	(4,831	)

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

As a result of the Prism Gas acquisition, the Partnership is exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales activities. Prism Gas gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (POL) and percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 2011 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas, ethane, and natural gasoline.

Based on estimated volumes, as of September 30, 2008, Prism Gas had hedged approximately 67%, 47%, 21% and 16% of its commodity risk by volume for 2008, 2009, 2010, and 2011, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.

Hedging Arrangements in Place
As of September 30, 2008


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

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

The Partnership’s principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing servicers, oil and gas producers and industrial end-users. In addition, substantially all of the Partnership’s natural gas and NGL sales are made at market-based prices. The Partnership’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Partnership.

Impact of Cash Flow Hedges

Crude Oil

For the three month periods ended September 30, 2008 and 2007, net gains and losses on swap hedge contracts increased crude revenue by $4,079 and decreased crude revenue by $653, respectively. For the nine month periods ending September 30, 2008 and 2007 net gains and losses on swap hedge contracts decreased crude revenue by $1,958 and $1,004, respectively. As of September 30, 2008 an unrealized derivative fair value loss of $4,251, related to cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2008, 2009, 2010 and 2011. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

Natural Gas

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

Natural Gas Liquids

For the three month periods ended September 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased liquids revenue by $81 and $264, respectively. For the nine month periods ended September 30, 2008 and 2007, net gains and losses on swap hedge contracts decreased liquids revenue by $827 and $374, respectively. As of September 30, 2008 an unrealized derivative fair value gain of $30, related to cash flow hedges of NGLs price risk, was recorded in other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2008, 2009, 2010, and 2011. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

(8)

Interest Rate Cash Flow Hedge

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

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

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


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

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

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

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

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


	September 30,			December 31,
	2008			2007
Fair value of derivative liabilities — current	$	(2,919	)	$	(1,241	)
Fair value of derivative liabilities — long term		(2,327	)		(3,436	)

Net fair value of derivatives	$	(5,246	)	$	(4,677	)

(9)

Related Party Transactions

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

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


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

		10,769		2,090		21,782		2,840

	$	22,294	$	10,591	$	53,982	$	29,296

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Costs and expenses:
Cost of products sold:
Natural gas services	$	28,051	$	15,857	$	77,033	$	41,713
Sulfur services		3,203		3,165		9,919		10,454
Terminalling and storage		25		—		322		—

	$	31,279	$	19,022	$	87,274	$	52,167

Expenses:
Operating expenses
Marine transportation	$	5,755	$	5,932	$	17,956	$	15,217
Natural gas services		391		365		1,164		1,128
Sulfur services		1,040		334		2,909		940
Terminalling and storage		2,392		1,437		6,960		3,612

	$	9,578	$	8,068	$	28,989	$	20,897

Selling, general and administrative:
Natural gas services	$	176	$	225	$	561	$	566
Sulfur services		479		377		1,387		1,161
Terminalling and storage		—		13		—		41
Indirect overhead allocation, net of reimbursement		674		326		2,021		978

	$	1,329	$	941	$	3,969	$	2,746

(10)

Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

The accounting policies of the operating segments are the same as those described in Note 2 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.


										Operating
			Intersegment			Operating		Depreciation		Income
	Operating		Revenues			Revenues after		and		(loss) after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Three months ended September 30, 2008
Terminalling and storage	$	23,847	$	(1,053	)	$	22,794	$	2,342	$	1,961		$	7,167
Natural gas services		188,200		—			188,200		1,028		4,928			4,368
Marine transportation		21,129		(1,013	)		20,116		3,159		1,972			7,357
Sulfur services		133,660		(384	)		133,276		1,450		7,973			537
Indirect selling, general and administrative		—		—			—		—		(1,414	)		—


Total	$	366,836	$	(2,450	)	$	364,386	$	7,979	$	15,420		$	19,429

Three months ended September 30, 2007
Terminalling and storage	$	18,788	$	(267	)	$	18,521	$	1,700	$	2,411		$	7,695
Natural gas services		120,994		—			120,994		970		1,676			1,444
Marine transportation		16,459		(990	)		15,469		2,377		944			8,361
Sulfur services		29,949		(83	)		29,866		1,189		2,375			3,252
Indirect selling, general and administrative		—		—			—		—		(841	)		—


Total	$	186,190	$	(1,340	)	$	184,850	$	6,236	$	6,565		$	20,752

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


										Operating
						Operating		Depreciation		Income
	Operating		Intersegment			Revenues after		and		(loss) after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Nine months ended September 30, 2008
Terminalling and storage	$	66,004	$	(3,132	)	$	62,872	$	6,784	$	5,293		$	16,993
Natural gas services		577,317		—			577,317		2,966		2,303			8,127
Marine transportation		58,418		(2,590	)		55,828		8,901		4,757			43,901
Sulfur services		290,346		(818	)		289,528		4,282		20,427			3,164
Indirect selling, general and administrative		—		—			—		—		(4,056	)		—


Total	$	992,085	$	(6,540	)	$	985,545	$	22,933	$	28,724		$	72,185


Nine months ended September 30, 2007
Terminalling and storage	$	41,252	$	(501	)	$	40,751	$	4,506	$	7,951		$	18,978
Natural gas services		328,103		—			328,103		2,271		4,084			3,038
Marine transportation		47,231		(2,724	)		44,507		6,280		3,347			24,004
Sulfur services		89,852		(253	)		89,599		3,541		7,397			11,504
Indirect selling, general and administrative		—		—			—		—		(2,447	)		—


Total	$	506,438	$	(3,478	)	$	502,960	$	16,598	$	20,332		$	57,524

The following table reconciles operating income to net income:


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007

Operating income	$	15,420		$	6,565		$	28,724		$	20,332
Equity in earnings of unconsolidated entities		3,503			2,736			11,385			7,204
Interest expense		(4,971	)		(3,640	)		(13,609	)		(9,956	)
Other, net		87			54			334			205
Income taxes		(292	)		(212	)		(753	)		(552	)

Net income	$	13,747		$	5,503		$	26,081		$	17,233

Total assets by segment are as follows:


	September 30,		December 31,
	2008		2007
Total assets:
Terminalling and storage	$	154,410	$	126,575
Natural gas services		282,528		268,230
Marine transportation		146,412		107,081
Sulfur services		173,668		121,691

Total assets	$	757,018	$	623,577

(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.

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

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


	September 30,		December 31,
	2008		2007
*$195,000 Revolving loan facility at variable interest rate (5.82% weighted average at September 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	$	150,000	$	95,000
**$130,000 Term loan facility at variable interest rate (6.99% at September 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		280,000		225,021
Less current installments		—		21

Long-term debt, net of current installments	$	280,000	$	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 October 1, 2008, the applicable margin for existing borrowings will increase to 2.50%. As a result of our leverage ratio test as of September 30, 2008, effective January 1, 2009, the applicable margin for existing borrowings will decrease to 2.00%. 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.

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


**		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 September 30, 2008, the Partnership had $150,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of September 30, 2008, the Partnership had $44,880 available under its revolving credit facility.

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

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

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

The credit facility also contains covenants, which, among other things, require the Partnership to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. The Partnership was in compliance with the debt covenants contained in credit facility for the year ended December 31, 2007 and as of September 30, 2008.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls the Partnership’s general partner, the lenders under the Partnership’s credit facility may declare all amounts outstanding thereunder immediately due and payable.

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

In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under the Partnership’s credit facility if it is deemed to have a material adverse effect on the Partnership. Any event of default and corresponding acceleration of outstanding balances under the Partnership’s credit facility could require the Partnership to refinance such indebtedness on unfavorable terms and would have a material adverse effect on the Partnership’s financial condition and results of operations as well as its ability to make distributions to unitholders.

On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made or required under the term loan through September 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 $315,000. As of September 30, 2008, the Partnership had $44,880 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 $5,335 and $2,777 for the three months ended September 30, 2008 and 2007, respectively, and $13,262 and $8,722 for the nine months ended September 30, 2008 and 2007, respectively. Capitalized interest was $287 and $826 for the three months ended September 30, 2008 and 2007, respectively and $1,100 and $2,171 for the nine months ended September 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 $174 and $421 and state income tax expense of $10 and $30 related to the operation of the subsidiary were recorded for the three and nine months ended September 30, 2008, respectively. In connection with the Woodlawn acquisition, the

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

Partnership also established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment.

A deferred tax benefit related to these basis differences of $67 and $43 was recorded for the three months ended September 30, 2008 and 2007, respectively, and $222 and $111 was recorded for the nine months ended September 30, 2008 and 2007, respectively. A deferred tax liability of $8,593 and $8,815 related to the basis differences existing at September 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 nine months ended September 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 $185 and $554 were recorded in current state income tax expense for the three and nine months ended September 30, 2008 and $143 and $412 for the three and nine months ended September 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 nine months ended September 30, 2008 and 2007 are as follows:


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007
Current:
Federal	$	174		$	80		$	421		$	237
State		185			175			554			426

		359			255			975			663

Deferred:
Federal		(67	)		(43	)		(222	)		(111	)

	$	292		$	212		$	753		$	552

(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

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

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.

(15)

Hurricane Damage

During the third quarter of 2008, several of the Partnership’s facilities in the Gulf of Mexico were in the path of two major storms, Hurricane Gustav and Hurricane Ike. Physical damage to the Partnership’s assets caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a deductible. Losses incurred as a result of a single hurricane (an “occurrence”) are limited to a maximum aggregate deductible of $0.3 million for flood damage and the greater of $1.0 million or 2% of total insured value for locations for wind damage. The Partnership’s total flood coverage is $15 million and total wind coverage is $100 million.

The most significant damage to the Partnership’s assets was sustained at its Neches terminal. Property damage also occurred at the Partnership’s Sabine Pass, Venice, Intracoastal City, Port Fourchon, Galveston, Cameron East, Cameron West, and Stanolind terminals. Insurance proceeds received as a result of the these claims could exceed the net book value of the Partnership’s assets determined to be impaired, which will result in the recognition of a gain equal to the amount of the excess.

The Partnership recognized a $1,614 estimated loss during the third quarter 2008, which approximates the Partnership’s hurricane deductibles under its applicable insurance policies, incurred as a result of Hurricanes Gustav and Ike and are included in “operating expenses” in the consolidated and condensed statements of income for the three month and nine month periods ended September 30, 2008. The actual hurricane cost payments for the three month and nine month periods ended September 30, 2008 was $0.

(16)

Commitments and Contingencies

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

In addition to the foregoing, from time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.

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

On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley Skelton, in their capacities as directors of Martin Resource Management

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

(the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of the general partner of the Partnership. The Partnership is not a party to this lawsuit, and it does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations or (iii) against the MRMC Director Defendants or Other MRMC Defendants with respect to their service to the Partnership.

The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants and the MRMC Employee Stock Ownership Plan, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares.

The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, who are beneficiaries of such trust, and seeks to remove him as the trustee of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached the fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust.

On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s recent activities, which the Board of Directors of Martin Resource Management determined were detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of the general partner of the Partnership. The position on the board of directors of the general partner of the Partnership vacated by the Plaintiff will be filled in accordance with the existing procedures for replacement of a departing director utilizing the Nominations Committee of the board of directors of the general partner of the Partnership.


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.

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 September 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

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.

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 $16.8 million of direct costs and expenses for the three months ended September 30, 2008 compared to $13.6 million for the three months ended September 30, 2007. We reimbursed Martin Resource Management for $50.6 million of direct costs and expenses for the nine months ended September 30, 2008 compared to $38.9 million for the nine months ended September 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

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 September 30, 2008 and 2007, respectively. We reimbursed Martin Resource Management for $2.0 and $1.0 million of indirect expenses for the nine months ended September 30, 2008 and 2007, respectively. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The omnibus agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the omnibus agreement.

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 10% and 13% of our total cost of products sold during the three months ended September 30, 2008 and 2007, respectively; and approximately 10% and 13% of our total cost of products sold during the nine months ended September 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 6% of total revenues for both the three months ended September 30, 2008 and 2007, respectively. Our sales to Martin Resource Management accounted for approximately 5% and 6% of our total revenues for the nine months ended September 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.

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 nine months ended September 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 nine months ended September 30, 2008 and 2007. The results of operations for the first nine 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)
	Operating		Intersegment			after		Operating			Intersegment			after
	Revenues		Eliminations			Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)

Three months ended September 30, 2008
Terminalling and storage	$	23,847	$	(1,053	)	$	22,794	$	2,911		$	(950	)	$	1,961
Natural gas services		188,200		—			188,200		4,685			243			4,928
Marine transportation		21,129		(1,013	)		20,116		2,576			(604	)		1,972
Sulfur Services		133,660		(384	)		133,276		6,662			1,311			7,973
Indirect selling, general and administrative		—		—			—		(1,414	)		—			(1,414	)


Total	$	366,836	$	(2,450	)	$	364,386	$	15,420		$	—		$	15,420


Three months ended September 30, 2007
Terminalling and storage	$	18,788	$	(267	)	$	18,521	$	2,631		$	(220	)	$	2,411
Natural gas services		120,994		—			120,994		1,547			129			1,676
Marine transportation		16,459		(990	)		15,469		1,805			(861	)		944
Sulfur Services		29,949		(83	)		29,866		1,423			952			2,375
Indirect selling, general and administrative		—		—			—		(841	)		—			(841	)


Total	$	186,190	$	(1,340	)	$	184,850	$	6,565		$	—		$	6,565


						Operating					Operating			Operating
			Revenues			Revenues					Income			Income (loss)
	Operating		Intersegment			after		Operating			Intersegment			after
	Revenues		Eliminations			Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)

Nine months ended September, 2008
Terminalling and storage	$	66,004	$	(3,132	)	$	62,872	$	8,045		$	(2,752	)	$	5,293
Natural gas services		577,317		—			577,317		1,596			707			2,303
Marine transportation		58,418		(2,590	)		55,828		6,428			(1,671	)		4,757
Sulfur Services		290,346		(818	)		289,528		16,711			3,716			20,427
Indirect selling, general and administrative		—		—			—		(4,056	)		—			(4,056	)


Total	$	992,085	$	(6,540	)	$	985,545	$	28,724		$	—		$	28,724


Nine months ended September, 2007
Terminalling and storage	$	41,252	$	(501	)	$	40,751	$	8,128		$	(177	)	$	7,951
Natural gas services		328,103		—			328,103		3,955			129			4,084
Marine transportation		47,231		(2,724	)		44,507		5,889			(2,542	)		3,347
Sulfur Services		89,852		(253	)		89,599		4,807			2,590			7,397
Indirect selling, general and administrative		—		—			—		(2,447	)		—			(2,447	)


Total	$	506,438	$	(3,478	)	$	502,960	$	20,332		$	—		$	20,332

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

Our total revenues before eliminations were $366.8 million for the three months ended September 30, 2008 compared to $186.2 million for the three months ended September 30, 2007, an increase of $180.6 million, or 97%. Our operating income before eliminations was $15.4 million for the three months ended September 30, 2008 compared to $6.6 million for the three months ended September 30, 2007, an increase of $8.8 million, or 133%.

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
	September 30,
	2008		2007
	(In thousands)
Revenues:
Services	$	10,546	$	7,570
Products		13,301		11,218

Total revenues		23,847		18,788

Cost of products sold		11,031		10,003
Operating expenses		7,541		4,406
Selling, general and administrative expenses		22		48
Depreciation and amortization		2,342		1,700

		2,911		2,631

Other operating income		—		—

Operating income	$	2,911	$	2,631

Revenues. Our terminalling and storage revenues increased $5.1 million, or 27%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. Service revenue accounted for $3.0 million of this increase. The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service at the end of 2007 and the beginning of 2008, and

increased business activity at our specialty terminals. Product revenue increased $2.1 million primarily due to an increase in product costs at our Mega Lubricants Inc. (“Mega Lubricants”) location that was passed through to our customers.

Cost of products sold. Our cost of products sold increased $1.0 million, or 10%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This was primarily a result of an increase in product costs at our Mega Lubricants location that was passed through to our customers.

Operating expenses. Operating expenses increased $3.1 million, or 71%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This increase was result of $1.5 million in expenses related to Hurricanes Gustav and Ike. The remaining was a result of our recent acquisitions and capital projects being placed into service during the end of 2007 and the beginning of 2008 and increased salaries and related burden and utilities 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 $0.6 million, or 38%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This increase was primarily a result of our recent acquisitions and capital expenditures.

In summary, our terminalling operating income increased $0.3 million, or 11%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007.

Natural Gas Services Segment

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


	Three Months Ended
	September 30,
	2008			2007
	(In thousands)
Revenues:
NGLs	$	166,564		$	109,822
Natural gas		16,470			11,352
Non-cash mark to market adjustment of commodity derivatives		6,629			(653	)
Gain (loss) on cash settlements of commodity derivatives		(1,820	)		(118	)
Other operating fees		357			591

Total revenues		188,200			120,994

Cost of products sold:
NGLs		162,718			104,469
Natural gas		16,519			10,771

Total cost of products sold		179,237			115,240

Operating expenses		2,070			1,968
Selling, general and administrative expenses		1,181			1,269
Depreciation and amortization		1,027			970

Operating income	$	4,685		$	1,547


NGLs Volumes (Bbls)		1,929			1,870

Natural Gas Volumes (Mmbtu)		1,818			1,897


Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments

Equity in Earnings of Unconsolidated Entities	$	3,503		$	2,736


Waskom:
Plant Inlet Volumes (Mmcf/d)		239			252

Frac Volumes (Bbls/d)		9,965			9,301

Revenues. Our natural gas services revenues increased $67.2 million, or 56%, for the three months ended September 30, 2008 compared to this same period of 2007 primarily due to higher commodity prices.

For the three months ended September 30, 2008, NGL revenues increased $56.7 million, or 52%, and natural gas revenues increased $5.1 million, or 45%. NGL sales volumes and natural gas volumes remained relatively the same for the three months of 2008 compared to the same period of 2007. During the third quarter of 2008, our NGL average sales price per barrel increased $27.60 or 47% and our natural gas average sales price per Mmbtu increased $3.07, or 51% compared to the same period 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 third quarter of 2008, 60% of our total natural gas volumes and 68% of our total NGL volumes were hedged as compared to 46% and 53%, respectively in the same quarter of 2007. The impact of price risk management and marketing activities increased total natural gas and NGL revenues $4.8 million during the third quarter of 2008 compared to a net increase of $0.8 million in the same quarter of 2007.

Costs of product sold. Our cost of products increased $64.0 million, or 56%, for the third quarter of 2008 compared to the same period of 2007. Of the increase, $58.3 million relates to NGLs and $5.7 million relates to natural gas. The increase in NGL cost of products sold was slightly larger than our increase in NGL revenues as our NGL margins fell $0.87 per barrel, or 30%. The percentage increase relating to natural gas cost of products sold was higher than the percentage increase in natural gas revenues causing our natural gas margins to decrease by 109%. This is primarily a result of the terms of Woodlawn’s producer contracts compared to our historical producer contracts.

Operating expenses. Operating expenses increased $0.1 million, or 5%, for the third quarter of 2008 compared to the same period of 2007.

Selling, general and administrative expenses. Selling, general and administrative expenses for the third quarter of 2008 compared to the same period of 2007 remained relatively constant.

Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 6%, for the third quarter of 2008 compared to the same period of 2007.

In summary, our natural gas services operating income increased $3.1 million, or 203%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $3.5 million and $2.7 million for the three months ended September 30, 2008 and 2007, respectively, an increase of 28%. Our inlet volumes decreased 5% and our fractionation volumes increased 7% during the three months ending September 30, 2008 as compared to the same period of 2007. The decrease in inlet volumes is primarily related to disruptions in supply caused by Hurricane Ike.

Marine Transportation Segment

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


	Three Months Ended
	September 30,
	2008		2007
	(In thousands)
Revenues	$	21,129	$	16,459
Operating expenses		15,033		12,141
Selling, general and administrative expenses		376		136
Depreciation and amortization		3,159		2,377

		2,561		1,805

Other operating income		15		—

Operating income	$	2,576	$	1,805

Revenues. Our marine transportation revenues increased $4.7 million, or 28%, for the three months ended September 30, 2008, compared to the three months ended September 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 $0.8 million due to downtime associated with capital expenditures on offshore vessels.

Operating expenses. Operating expenses increased $2.9 million, or 24%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This was primarily a result of increases in operating costs from fuel expense, assist tugs 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, or 176%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This was primarily a result of increases in costs to support our fleet expansion.

Depreciation and Amortization. Depreciation and amortization increased $0.8 million, or 33%, for the three months ended September 30, 2008 compared to the three months ended September 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 $0.8 million, or 43%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007.

Sulfur Services Segment

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


	Three Months Ended
	September 30,
	2008		2007
	(In thousands)
Revenues	$	133,660	$	29,949
Cost of products sold		120,267		22,759
Operating expenses		4,547		3,982
Selling, general and administrative expenses		733		596
Depreciation and amortization		1,451		1,189

Operating income	$	6,662	$	1,423


Volumes (long tons)		348.2		321.2

Revenues. Our sulfur services revenues increased $103.7 million, or 346%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This increase was primarily a result of a 312% 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 $97.5 million, or 428%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. Our margin per ton increased 72% which was driven by a strong domestic demand in the molten sulfur markets and our ability to spread our margin to our sulfur-based product customers.

Operating expenses. Our operating expenses increased $0.6 million, or 14%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This increase was a result of increased fuel and utility costs.

Selling, general, and administrative expenses. Selling, general, and administrative expenses increased $0.1 million, or 23%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007.

Depreciation and amortization. Depreciation and amortization expense increased $0.3 million, or 22%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007. This is a result of our sulfuric acid plant becoming operational in late September 2007.

In summary, our sulfur operating income increased $5.2 million, or 368%, for the three months ended September 30, 2008 compared to the three months ended September 30, 2007.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Our total revenues were $992.1 million for the nine months ended September 30, 2008 compared to $506.4 million for the nine months ended September 30, 2007, an increase of $485.7 million, or 96%. Our operating income was $28.7 million for the nine months ended September 30, 2008 compared to $20.3 million for the nine months ended September 30, 2007, an increase of $8.4 million, or 41%.

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.


	Nine Months Ended
	September 30,
	2008			2007
	(In thousands)
Revenues:
Services	$	29,378		$	21,559
Products		36,626			19,693

Total revenues		66,004			41,252

Cost of products sold		31,222			17,107
Operating expenses		19,883			11,403
Selling, general and administrative expenses		56			108
Depreciation and amortization		6,784			4,506

		8,059			8,128

Other operating income		(14	)		—

Operating income	$	8,045		$	8,128

Revenues. Our terminalling and storage revenues increased $24.8 million, or 60%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. Service revenue accounted for $7.8 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 and specialty terminals. Product revenue increased $16.9 million primarily due to the Mega Lubricants acquisition which occurred in June 2007, including an increase in product costs that was passed through to our customers.

Cost of products sold. Our cost of products increased $14.1 million, or 83%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This increase was primarily a result of the Mega Lubricants acquisition which occurred in June 2007.

Operating expenses. Operating expenses increased $8.5 million, or 74%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This increase was a result of $1.5 million in expenses related to Hurricanes Gustav and Ike and our recent acquisitions and capital projects placed into service during the last twelve months. The increase was also a result of increased salaries and related burden, repairs and maintenance, product hauling costs, and utilities related to increased activity at our existing terminals.

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

Depreciation and amortization. Depreciation and amortization increased $2.3 million, or 51% for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This increase was primarily a result of our recent acquisitions and capital expenditures.

In summary, terminalling and storage operating income decreased $0.1 million, or 1%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007.

Natural Gas Services Segment

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


	Nine Months Ended
	September 30,
	2008			2007
	(In thousands)
Revenues:
NGLs	$	528,353		$	302,840
Natural gas		50,090			24,839
Non-cash mark to market adjustment of commodity derivatives		1,517			(1,728	)
Gain (loss) on cash settlements of commodity derivatives		(4,816	)		254
Other operating fees		2,173			1,898

Total revenues		577,317			328,103

Cost of products sold:
NGLs		513,221			289,449
Natural gas		49,656			23,502

Total cost of products sold		562,877			312,951

Operating expenses		6,287			5,103
Selling, general and administrative expenses		3,594			3,823
Depreciation and amortization		2,966			2,271

		1,593			3,955

Other operating income		3			—

Operating income	$	1,596		$	3,955


NGLs Volumes (Bbls)		6,457			5,742

Natural Gas Volumes (Mmbtu)		5,517			3,792


Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments

Equity in Earnings of Unconsolidated Entities	$	11,385		$	7,204


Waskom:
Plant Inlet Volumes (Mmcf/d)		256			222

Frac Volumes (Bbls/d)		10,317			8,258

Revenues. Our natural gas services revenues increased $249.2 million, or 76%, for the nine months ended September 30, 2008 compared to this same period of 2007 primarily due to higher commodity prices and increased volumes.

For the nine months ended September 30, 2008, NGL revenues increased $225.5 million, or 74% and natural gas revenues increased $25.3 million, or 102%. NGL sales volumes for the nine months of 2008 increased 12% and natural gas volumes increased 45% compared to the same period of 2007. During the first nine months of 2008, our NGL average sales price per barrel increased $29.08 or 55% and our natural gas average sales price per Mmbtu increased $2.50, or 39% compared to the same period of 2007. The increase in natural gas volumes is primarily related to the Woodlawn acquisition being in operation for the full first nine months of 2008 compared to 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 first nine months of 2008, 59% of our total natural gas volumes and 68% of our total NGL volumes were hedged as compared to 46% and 53%, respectively in the same quarter of 2007. The impact of price risk management and marketing activities decreased total natural gas and NGL revenues $3.3 million during the first nine months of 2008 compared to a decrease of $1.5 million in the same quarter of 2007.

Costs of product sold. Our cost of products increased $249.9 million, or 80%, for the nine months ended September 30, 2008 compared to the same period of 2007. Of the increase, $223.8 million relates to NGLs and $26.2 million relates to natural gas. The increase of $223.8 million in NGL cost of products sold is less than our increase in NGL revenues as we were able to expand our NGL margins by $0.01 per barrel, or 0.5%. The percentage increase relating to natural gas cost of products sold is greater than the percentage increase in natural gas revenues which caused our natural gas margins to decrease by 78%. This is primarily a result of the terms of Woodlawn’s producer contracts compared to our historical producer contracts.

Operating expenses. Operating expenses increased $1.2 million, or 23%, for the nine months ended September 30, 2008 compared to the same period of 2007. This increase was primarily a result of the Woodlawn assets, which were acquired in the middle of the second quarter of 2007, being in operation for the first nine months of 2008 compared to 2007.

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

Depreciation and amortization. Depreciation and amortization increased $0.7 million, or 31%, for the nine months ended September 30, 2008 compared to the same period of 2007. This increase was primarily a result of the Woodlawn assets being in operation for the first nine months of 2008 compared to 2007.

In summary, our natural gas services operating income decreased $2.4 million, or 60%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $11.4 million and $7.2 million for the nine months ended September 30, 2008 and 2007, respectively, an increase of 58%. This increase is primarily a result of receiving full benefit of the expansion to the Waskom plant and the Waskom fractionator for the nine months of 2008 as the plant was shut down for a portion of the first nine months of 2007. As a result our inlet volumes increased 15% and our fractionation volumes increased 25% during the nine months ending September 30, 2008 as compared to the same period of 2007.

Marine Transportation Segment

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


	Nine Months Ended
	September 30,
	2008		2007
	(In thousands)
Revenues	$	58,418	$	47,231
Operating expenses		42,350		34,843
Selling, general and administrative expenses		893		219
Depreciation and amortization		8,901		6,280

		6,274		5,889

Other operating income		154		—

Operating income	$	6,428	$	5,889

Revenues. Our marine transportation revenues increased $11.2 million, or 24%, for the nine months ended September 30, 2008, compared to the nine months ended September 30, 2007. Our inland marine operations generated an additional $12.9 million in revenue from expansion of our fleet and increased contract rates. Our offshore revenues decreased $1.7 million primarily from downtime associated with capital expenditures on offshore vessels.

Operating expenses. Operating expenses increased $7.5 million, or 22%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This was primarily a result of increases in operating costs from fuel expense, assist tugs and wages and burden costs due to expansion of our fleet and increased fuel costs.

Selling, general, and administrative expenses. Selling, general and administrative expenses increased $0.7 million, or 308%, for the nine months ended September 30, 2008 compared to the nine months ended September 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 $2.6 million, or 42%, for the nine months ended September 30, 2008 compared to the nine months ended September 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 9%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007.

Sulfur Services Segment

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


	Nine Months Ended
	September 30,
	2008		2007
	(In thousands)
Revenues	$	290,346	$	89,852
Cost of products sold		254,173		67,562
Operating expenses		13,107		12,185
Selling, general and administrative expenses		2,073		1,757
Depreciation and amortization		4,282		3,541

Operating income	$	16,711	$	4,807


Volumes (long tons)		1,027.5		1,042.0

Revenues. Our sulfur services revenues increased $200.5 million, or 223%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This increase was primarily a result of a 228% 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 $186.6 million, or 276%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. Our margin per ton increased 65% which was driven by a strong international demand in the prilled sulfur markets, strong domestic demand in the molten sulfur markets and our ability to spread our margin to our sulfur-based product customers.

Operating expenses. Our operating expenses increased $0.9 million, or 8%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This increase was a result of increased fuel, marine transportation and utility costs.

Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased $0.3 million, or 18%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007.

Depreciation and amortization. Depreciation and amortization expense increased $0.7 million, or 21%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This is a result of our sulfuric acid plant becoming operational in late September 2007.

In summary, our sulfur operating income increased $11.9 million, or 248%, for the nine months ended September 30, 2008 compared to the nine months ended September 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 nine months ended September 30, 2008 and 2007 are as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Revenues		100	%		100	%		100	%		100	%
Cost of products sold		85	%		80	%		86	%		79	%
Operating expenses		8	%		12	%		8	%		12	%
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 nine months ended September 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 $3.5 million for the three months ended September 30, 2008 compared to $2.7 million for the three months ended September 30, 2007, an increase of $0.8 million. This increase is related to earnings received from Waskom, Matagorda, PIPE and BCP.

Equity in earnings of unconsolidated entities was $11.4 million for the nine months ended September 30, 2008 compared to $7.2 million for the nine months ended September 30, 2007, an increase of $4.2 million. This increase is related to earnings received from Waskom, Matagorda, PIPE and BCP.

Interest Expense

Our interest expense for all operations was $5.0 million for the three months ended September 30, 2008, compared to the $3.6 million for the three months ended September 30, 2007, an increase of $1.4 million, or 39%. 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 $13.6 million for the nine months ended September 30, 2008, compared to the $10.0 million for the nine months ended September 30, 2007, an increase of $3.6 million, or 36%. 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 $1.4 million for the three months ended September 30, 2008 compared to $0.8 million for the three months ended September 30, 2007, an increase of $0.6 million, or 75%.

Indirect selling, general and administrative expenses were $4.1 million for the nine months ended September 30, 2008 compared to $2.4 million for the nine months ended September 30, 2007, an increase of $1.7 million, or 71%.

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 primarily 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 $0.7 million and $0.3 million for the three months ended September 30, 2008 and 2007, respectively, and $2.0 million and $1.0 million for the nine months ended September 30, 2008 and 2007, respectively.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

For the nine months ended September 30, 2008 cash increased $2.9 million as a result of $60.7 million provided by operating activities, $78.8 million used in investing activities and $21.0 million provided by financing activities. For the nine months ended September 30, 2007, cash increased $2.9 million as a result of $35.6 million provided by operating activities, $98.4 million used in investing activities and $65.7 million provided by financing activities.

For the nine months ended September 30, 2008 our investing activities of $78.8 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 nine months ended September 30, 2007 our investing activities of $98.4 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, 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 nine months ended September 30, 2008 and 2007, our capital expenditures for property and equipment were $78.2 million and $89.7 million, respectively.

As to each period:

	•		For the nine months ended September 30, 2008, we spent $68.2 million for expansion and $10.0 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.

	•		For the nine months ended September 30, 2007, we spent $82.9 million for expansion and $6.8 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 $0.2 million spent in connection with restoration of assets destroyed in Hurricanes Rita and Katrina.

For the nine months ended September 30, 2008, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $33.9 million, payments of long term debt to financial lenders of $180.4 million, borrowings of long-term debt under our credit facility of $235.4 million and purchase of treasury units of $0.1 million.

For the nine months ended September 30, 2007, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $27.4 million, net proceeds from a follow on equity offering of $55.9 million, payments of long term debt to financial lenders of $125.1 million, borrowings of long-term debt under our credit facility of $161.1 million and contributions of $1.2 million from our general partner.

We made net investments in (received distributions from) unconsolidated entities of $2.0 million and $6.1 million during the nine months ended September 30, 2008 and 2007, respectively. The net investment in unconsolidated entities includes $4.3 million and $7.0 million of expansion capital expenditures in the nine months ended September 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 September 30, 2008, we had $280.0 million of outstanding indebtedness, consisting of outstanding borrowings of $150.0 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 and 2009. However, current economic conditions, including wide fluctuations in commodity prices and deteriorating credit markets, have created constraints on liquidity and the ability to obtain credit in the markets. We continue to evaluate our liquidity and capital resources and may consider sales of non-performing or non-core assets for additional liquidity. If there is need to access the credit markets and the credit markets do not improve, we cannot assure you that we would be able to secure additional financing if needed, and, if such funds were available, whether the terms or conditions would be acceptable to us. In addition, 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 — Risk 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.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 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	$	150,000	$	—	$	150,000	$	—	$	—
Term loan facility		130,000		—		130,000		—		—
Other		—		—		—		—		—
Non-competition agreements		550		250		150		100		50
Operating leases		26,026		3,647		9,496		4,844		8,039
Interest expense(1)
Revolving Credit Facility		18,418		8,724		9,694		—		—
Term loan facility		19,173		9,082		10,091		—		—
Other		—		—		—		—		—


Total contractual cash obligations	$	344,167	$	21,703	$	309,431	$	4,944	$	8,089


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

Letter of Credit At September 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 September 30, 2008, we had $150.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of September 30, 2008, we had $44.9 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 $315.0 million. As of September 30, 2008, we had $44.9 million available for working capital, internal expansion and acquisition activities under our credit facility.

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

Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 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 October 1, 2008, the applicable margin for existing borrowings will increase to 2.50%. As a result of our leverage ratio test, effective January 1, 2009, the applicable margin for existing borrowings will decrease to 2.00%. 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. We are in compliance with the debt covenants contained in the credit facility.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us. Any event of default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations as well as our ability to make distributions to unitholders.

On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. No prepayments under the term loan were required to be made through September 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 November 6, 2008, our outstanding indebtedness includes $300 million under our credit facility.

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.

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 nine months ended September 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 nine months ended September 30, 2008 or 2007.

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 September 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 September 30, 2008.

We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the commodity derivative contracts include Shell Energy North America (US), L.P., Morgan Stanley Capital Group Inc., 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 September 30, 2008, Prism Gas had hedged approximately 67%, 47%, 21% and 16% of its commodity risk by volume for 2008, 2009, 2010 and 2011, respectively. 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 September 30, 2008


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

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 6.36% as of September 30, 2008. We had a total of $300 million of indebtedness outstanding under our credit facility as of the date hereof of which $65 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on September 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 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. As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act disclosure controls and procedures are controls and other procedures of the Company that are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Based on this evaluation, and following discussions with our independent registered public accounting firm, KPMG LLP, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that, as of September 30, 2008, due to the material weakness discussed in the subsequent paragraph, our disclosure controls and procedures were not effective as further detailed below. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

On October 24, 2008, we were advised by our independent registered public accounting firm, KPMG LLP, of the discovery of an error in the failure to record in the statement of operations the ineffective portion of certain commodity price swaps in place which did not qualify for hedge accounting at September 30, 2008. This error resulted from our failure to consult with our third party derivatives specialist which is a component of our internal control process. We have corrected this error, which resulted in recording additional earnings of $1.7 million before taxes in the third quarter of 2008. No results of operations for prior periods were affected by this error.

We believe that our control procedures over recording the fair value of outstanding derivatives were not operating effectively at September 30 2008, and that this deficiency in internal control over financial reporting at September 30, 2008 is a material weakness. This control deficiency could result in a misstatement to our annual or interim financial statements that would not be prevented or detected. We have implemented procedures that require the quarterly consultation with and review by our third party advisor with respect to our hedging activity and accounting for our derivative instruments.

Changes in internal controls. There were no changes in our internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f) that occurred during the fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. As noted above, during our fourth fiscal quarter, we have implemented changes in our internal controls over financial reporting to address the material weakness described above.

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 has 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

Indemnification Agreements. On November 6, 2008, we and Martin Midstream GP entered into an Indemnification Agreement with each of the directors of Martin Midstream GP, Ruben S. Martin, III, John P. Gaylord, Howard Hackney and C. Scott Massey. Each Indemnification Agreement requires us and Martin Midstream GP to indemnify each such indemnitee to the fullest extent permitted by law, from and against all liabilities and expenses incurred in connection with any proceeding against such indemnitee. Each Indemnification Agreement also provides for the advancement of expenses incurred by such indemnitee in connection with any proceeding against such indemnitee with respect to which such indemnitee may be entitled to indemnification by us or Martin Midstream GP. The foregoing description of each Indemnification Agreement is qualified in its entirety by reference to the form of Indemnification Agreement attached hereto as Exhibit 10.1, which is incorporated herein by reference.

Certain Other Information. In addition to the litigation relating to Martin Resource Management previously disclosed on our Form 8-K filed on September 5, 2008 and described in Note 16, “Commitments and Contingencies” in Notes to Consolidated and Condensed Financial Statement on page 24 of this quarterly report, in October 2008 a separate lawsuit was filed in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o/ Angela Santi Jones), which holds shares of Martin Resource Management common stock. The suit alleges, among other things, that the Defendant and Karen Yost breached the fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust.

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.

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).
	10.1	*	Form of Indemnification Agreement.
	10.2		Third Amendment to Second Amended and Restated Credit Agreement, effective as of September 24, 2008, among the Operating Partnership, the Partnership, the Operating General Partner, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed September 30, 2008, and incorporated herein by reference).
	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 September 30, 2008 (unaudited) and December 31, 2007 (audited) of the General Partner.


*		Filed or furnished herewith


	Martin Midstream Partners L.P. By: Martin Midstream GP LLC Its General Partner
Date: November 6, 2008	By:	/s/ Ruben S. Martin
		Ruben S. Martin
		President and Chief Executive Officer


		Page

PART I — FINANCIAL INFORMATION			1

Item 1.	Financial Statements		1

	Consolidated and Condensed Balance Sheets as of September 30, 2008 (unaudited) and December 31, 2007 (audited)		1
	Consolidated and Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2008 and 2007 (unaudited)		2
	Consolidated and Condensed Statements of Capital for the Three and Nine Months Ended September 30, 2008 and 2007 (unaudited)		3
	Consolidated and Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2008 and 2007 (unaudited)		4
	Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007 (unaudited)		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3.	Quantitative and Qualitative Disclosures about Market Risk		46

Item 4.	Controls and Procedures		47

PART II. OTHER INFORMATION			48

Item 1.	Legal Procedings		48

Item 1A.	Risk Factors		48

Item 5.	Other Information		48

Item 6.	Exhibits		48

SIGNATURE CERTIFICATIONS

EX-10.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1