10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2007

OR

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

For the transition period from                      to                     

Commission File Number
000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)

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

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

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

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

Yes þ      No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o      Accelerated filer þ      Non-accelerated filer 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 May 7, 2007 was 10,606,808. The number of the registrant’s subordinated units outstanding at May 7, 2007 was 2,552,018.

	Page
PART I — FINANCIAL INFORMATION		1
Item 1. Financial Statements		1
Consolidated and Condensed Balance Sheets as of March 31, 2007 (unaudited) and December 31, 2006 (audited)		1
Consolidated and Condensed Statements of Operations for the Three Months Ended March 31, 2007 and 2006 (unaudited)		2
Consolidated and Condensed Statements of Capital for the Three Months Ended March 31, 2007 and 2006 (unaudited)		3
Consolidated and Condensed Statements of Comprehensive Income for the Three Months Ended March 31, 2007 and 2006 (unaudited)		4
Consolidated and Condensed Statements of Cash Flows for the Three Months Ended March 31, 2007 and 2006 (unaudited)		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 3. Quantitative and Qualitative Disclosures about Market Risk		35
Item 4. Controls and Procedures		36
PART II. OTHER INFORMATION		37
Item 1. Legal Proceedings		37
Item 1A. Risk Factors		37
Item 6. Exhibits		37
SIGNATURE
CERTIFICATIONS
Consent of KPMG
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Martin Midstream GP LLC Balance Sheets

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	March 31,			December 31,
	2007			2006
	(Unaudited)			(Audited)
Assets
Cash	$	4,578		$	3,675
Accounts and other receivables, less allowance for doubtful accounts of $242 and $394		58,676			56,712
Product exchange receivables		1,982			7,076
Inventories		26,169			33,019
Due from affiliates		1,100			1,330
Other current assets		1,317			2,041
Total current assets		93,822			103,853
Property, plant, and equipment, at cost		339,731			323,967
Accumulated depreciation		(80,860	)		(76,122	)
Property, plant and equipment, net		258,871			247,845
Goodwill		27,600			27,600
Investment in unconsolidated entities		73,406			70,651
Other assets, net		6,594			7,512
	$	460,293		$	457,461
Liabilities and Partners’ Capital
Current installments of long-term debt	$	75		$	74
Trade and other accounts payable		55,239			53,450
Product exchange payables		6,018			14,737
Due to affiliates		7,959			10,474
Income taxes payable		276			86
Other accrued liabilities		3,293			3,876
Total current liabilities		72,860			82,697
Long-term debt		190,001			174,021
Other long-term obligations		2,671			2,218
Total liabilities		265,532			258,936
Partners’ capital		195,750			198,403
Accumulated other comprehensive income (loss)		(989	)		122
Total partners’ capital		194,761			198,525
Commitments and contingencies
	$	460,293		$	457,461

See accompanying notes to consolidated and condensed financial statements.

1

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended
	March 31,
	2007			2006
Revenues:
Terminalling and storage	$	6,951		$	5,756
Marine transportation		13,884			9,312
Product sales:
Natural gas services		101,788			101,924
Sulfur		15,171			15,389
Fertilizer		14,209			12,025
Terminalling and storage		3,793			2,416
		134,961			131,754
Total revenues		155,796			146,822
Costs and expenses:
Cost of products sold:
Natural gas services		96,772			98,083
Sulfur		10,337			10,471
Fertilizer		11,464			11,000
Terminalling and storage		3,015			1,999
		121,588			121,553
Expenses:
Operating expenses		18,993			13,900
Selling, general and administrative		2,721			2,386
Depreciation and amortization		4,894			3,952
Total costs and expenses		148,196			141,791
Other operating income		—			853
Operating income		7,600			5,884
Other income (expense):
Equity in earnings of unconsolidated entities		2,050			2,412
Interest expense		(3,577	)		(3,018	)
Debt prepayment premium		—			(1,160	)
Other, net		79			169
Total other income (expense)		(1,448	)		(1,597	)
Net income before taxes		6,152			4,287
Income taxes		349			—
Net income	$	5,803		$	4,287
General partner’s interest in net income	$	275		$	246
Limited partners’ interest in net income	$	5,528		$	4,041
Net income per limited partner unit — basic and diluted	$	0.42		$	0.33
Weighted average limited partner units — basic		13,152,826			12,299,009
Weighted average limited partner units — diluted		13,155,125			12,301,980

See accompanying notes to consolidated and condensed financial statements.

2

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)

	Partners’ Capital
														Accumulated
														Other
											General			Comprehensive
	Common					Subordinated					Partner			Income
	Units		Amount			Units		Amount			Amount			Amount			Total
Balances — January 1, 2006		5,829,652	$	100,206			3,402,690	$	(5,642	)	$	1,001		$	—		$	95,565
Net income		—		2,984			—		1,057			246			—			4,287
Follow-on public offering		3,450,000		95,273			—		—			—			—			95,273
General partner contribution		—		—			—		—			2,052			—			2,052
Unit-based compensation		3,000		4			—		—			—			—			4
Cash distributions		—		(5,662	)		—		(2,076	)		(277	)		—			(8,015	)
Adjustment in fair value of derivatives		—		—			—		—			—			(226	)		(226	)
Balances — March 31, 2006		9,282,652	$	192,805			3,402,690	$	(6,661	)	$	3,022		$	(226	)	$	188,940
Balances — January 1, 2007		10,603,808	$	201,387			2,552,018	$	(6,237	)	$	3,253		$	122		$	198,525
Net income		—		4,608			—		920			275			—			5,803
Cash distributions		—		(6,574	)		—		(1,582	)		(311	)		—			(8,467	)
Unit-based compensation		—		11			—		—			—			—			11
Adjustment in fair value of derivatives		—		—			—		—			—			(1,111	)		(1,111	)
Balances — March 31, 2007		10,603,808	$	199,432			2,552,018	$	(6,899	)	$	3,217		$	(989	)	$	194,761

See accompanying notes to consolidated and condensed financial statements.

3

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

	Three Months Ended
	March 31,
	2007			2006
Net income	$	5,803		$	4,287
Changes in fair values of commodity cash flow hedges		(164	)		(226	)
Commodity hedging losses reclassified to earnings		(432	)		—
Changes in fair value of interest rate cash flow hedges		(515	)		—
Comprehensive income	$	4,692		$	4,061

See accompanying notes to consolidated and condensed financial statements.

4

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Three Months Ended
	March 31,
	2007			2006
Cash flows from operating activities:
Net income	$	5,803		$	4,287
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		4,894			3,952
Amortization of deferred debt issuance costs		270			249
(Gain) on involuntary conversion of property, plant and equipment		—			(853	)
Equity in earnings of unconsolidated entities		(2,050	)		(2,412	)
Distributions from unconsolidated entities		200			160
Distributions in-kind from equity investments		1,853			1,932
Non-cash mark-to-market on derivatives		593			82
Other		11			8
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		(1,964	)		16,967
Product exchange receivables		5,094			(2,910	)
Inventories		6,850			2,067
Due from affiliates		230			(1,739	)
Other current assets		26			(128	)
Trade and other accounts payable		1,789			(19,995	)
Product exchange payables		(8,719	)		1,658
Due to affiliates		(2,515	)		2,854
Income taxes payable		190			(5,060	)
Other accrued liabilities		(770	)		(1,556)	)
Change in other non-current assets and liabilities		126			(35	)
Net cash provided (used) by operating activities		11,911			(472	)
Cash flows from investing activities:
Payments for property, plant and equipment		(15,764	)		(19,101	)
Acquisitions, net of cash acquired		—			(7,451	)
Proceeds from sale of property, plant and equipment		—			720
Return of investments from unconsolidated entities		1,125			150
Investments in unconsolidated entities		(3,883	)		(546	)
Net cash used in investing activities		(18,522	)		(26,228	)
Cash flows from financing activities:
Payments of long-term debt		(25,119	)		(82,904	)
Proceeds from long-term debt		41,100			19,100
Net proceeds from follow on public offering		—			95,273
Payments of debt issuance costs		—			(12	)
General partner contribution		—			2,052
Cash distributions paid		(8,467	)		(8,015	)
Net cash provided by financing activities		7,514			25,494
Net increase (decrease) in cash		903			(1,206	)
Cash at beginning of period		3,675			6,465
Cash at end of period	$	4,578		$	5,259

See accompanying notes to consolidated and condensed financial statements.

5

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

  (1) General

     Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership which provides terminalling and storage services for petroleum products and by-products, natural gas services, marine transportation services for petroleum products and by-products, sulfur gathering, processing and distribution and fertilizer manufacturing 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, 2006 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2007.

  (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

     In January 2006, the Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010. The Partnership accounts for the transaction under Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based payment transactions was $11 and $4 for the three months ended March 31, 2007 and 2006. The Partnership’s general partner contributed $2 in cash to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.

  (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 March 31, 2007 and 2006, the general partner received $163 and $134 in incentive distributions.

6

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

  (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 13,152,826 and 12,299,009 for the three months ended March 31, 2007 and 2006. For diluted net income per unit, the weighted average units outstanding were increased by 2,299 and 2,971 for the three months ended March 31, 2007 and 2006, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(2) Subsequent Event

     On May 2, 2007, the Partnership acquired the outstanding stock of Woodlawn Pipeline Company, Inc. (“Woodlawn”), a natural gas gathering and processing company with integrated gathering and processing assets in East Texas for $30,638. In addition, the Partnership purchased a compressor for $400 from an affiliate of the selling parties. In conjunction with this transaction, the Partnership also acquired a pipeline that delivers residue gas from the Woodlawn gas processing plant to the Texas Eastern Transmission pipeline system for $2,139.

(3) Inventories

     Components of inventories at March 31, 2007 and 2006 were as follows:

	March 31,		December 31,
	2007		2006
Natural gas liquids	$	11,387	$	17,061
Sulfur		2,445		4,397
Fertilizer — raw materials and packaging		2,603		2,412
Fertilizer — finished goods		5,152		4,807
Lubricants		3,018		2,592
Other		1,564		1,750
	$	26,169	$	33,019

7

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

(4) Investment in Unconsolidated Partnerships and Joint Ventures

     The Partnership, through its subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), owns 50% ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). Each of these interests are accounted for under the equity method of accounting.

     On June 30, 2006, the Partnership, through its Prism Gas subsidiary, acquired a 20% ownership interest in a partnership for approximately $196, which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). BCP is an approximate 67 mile pipeline located in the Barnett Shale extension. The pipeline traverses four counties with the most concentrated drilling occurring in Bosque County. BCP is operated by Panther Pipeline Ltd. who is the 42.5% interest owner. This interest is accounted for under the equity method of accounting.

     In accounting for the acquisition of the interests in Waskom, Matagorda and 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 for the three months ended March 31, 2007 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 $11,131 and $11,279 at March 31, 2007 and December 31, 2006. 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 quarter of 2007 or the year ended December 31, 2006.

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

     Activity related to these investment accounts is as follows:

	Waskom			PIPE			Matagorda			BCP			Total
Investment in unconsolidated entities, December 31, 2005	$	54,087		$	1,723		$	4,069		$	—		$	59,879
Distributions in kind		(1,932	)		—			—			—			(1,932	)
Cash contributions		546			—			—			—			546
Cash distributions		(150	)		—			(160	)		—			(310	)
Equity in earnings:
Equity in earnings from operations		2,174			68			170			—			2,412
Investment in unconsolidated entities, March 31, 2006	$	54,725		$	1,791		$	4,079		$	—		$	60,595
Investment in unconsolidated entities, December 31, 2006	$	64,937		$	1,718		$	3,786		$	210		$	70,651
Distributions in kind		(1,853	)		—			—			—			(1,853	)
Cash contributions		3,883			—			—			—			3,883
Cash distributions		(1,125	)		(200	)		—			—			(1,325	)
Equity in earnings:
Equity in earnings from operations		1,864			293			74			(33	)		2,198
Amortization of excess investment		(137	)		(4	)		(7	)		—			(148	)
Investment in unconsolidated entities, March 31, 2007	$	67,569		$	1,807		$	3,853		$	177		$	73,406

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

8

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

					Three Months Ended
	As of March 31,				March 31,
	Total		Partner’s				Net
	Assets		Capital		Revenues		Income
2007
Waskom	$	58,977	$	50,989	$	14,799	$	3,729

	As of December 31,
2006
Waskom	$	53,260	$	45,450	$	16,799	$	4,543

(5) Commodity Cash Flow Hedges

     The Partnership is exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, the Partnership has not engaged in commodity contract trading or hedging activities. However, in connection with the acquisition of Prism Gas, the Partnership has established a hedging policy and monitors and manages the commodity market risk associated with the commodity risk exposure of the Prism Gas acquisition. In addition, the Partnership is focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

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

     In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. In early 2006, the Partnership 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 March 31, 2007, 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. During the three months ended March 31, 2007, certain of the Partnership’s derivative instruments which were designated as hedges became ineffective due to fluctuations in the basis difference between the hedged item and the hedging instrument. As a result, these hedges are now marked to market through the statement of operations for the three months ended March 31, 2007.

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

	Three Months
	Ended March 31,
	2007			2006
Change in fair value of derivatives that do not qualify for hedge accounting	$	(283	)	$	286
Ineffective portion of derivatives		124			(11	)
Change in fair value of derivatives in the Consolidated Statement of Operations	$	(159	)	$	275

9

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

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

	March 31,			December 31,
	2007			2006
Fair value of derivative assets — current	$	318		$	882
Fair value of derivative assets — long term		—			221
Fair value of derivative liabilities — current		(186	)		—
Fair value of derivative liabilities — long term		(196	)		(74	)
Net fair value of derivatives	$	(64	)	$	1,029

     Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2007 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of March 31, 2007, the remaining term of the contracts extend no later than December 2009, with no single contract longer than one year. The Partnership’s counterparties to the derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank. For the three months ended March 31, 2007, 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 March 31, 2007.

March 31, 2007
	Total
Transaction	Volume		Remaining Terms
Type	Per Month	Pricing Terms	of Contracts	Fair Value
Mark to Market Derivatives:
Ethane Swap	8,000 BBL	Fixed price of $28.04 settled against Mt. Belvieu Purity	April 2007 to	$	4
		Ethane average monthly postings	December 2007
Crude Oil swap	5,000 BBL	Fixed price of $65.95 settled against WTI NYMEX average monthly closings	April 2007 to December 2007		129
Natural Gas swap and Natural Gas basis swap	20,000 MMBTU	Combined fixed price of $8.54 settled against “Inside FERC” Centerpoint Energy Gas Transmission Co.	April 2007 to December 2007		185
Natural Gas swap	30,000 MMBTU	Fixed price of $8.12 settled against “Inside FERC” Houston Ship Channel first of the month	January 2008 to December 2008		(145	)
Crude Oil Swap	3,000 BBL	Fixed price of $69.08 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(13	)
Total swaps not designated as cash flow hedges				$	160
Cash Flow Hedges:
Crude Oil Swap	5,000 BBL	Fixed price of $66.20 settled against WTI NYMEX average monthly closings	January 2008 to December 2008		(224	)
Total swaps designated as cash flow hedges				$	(224	)
Total net fair value of derivatives				$	(64	)

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

10

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

     As a result of the Prism Gas acquisition, the Partnership is exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales activities. 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 2009 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas and ethane.

     Based on estimated volumes, as of March 31, 2007, Prism Gas had hedged approximately 55%, 46%, and 14% of its commodity risk by volume for 2007, 2008, and 2009, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements. In addition, the Partnership will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil.

Hedging Arrangements in Place

Year	Commodity Hedged	Volume	Type of Derivative	Basis Reference
2007	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($65.95)	NYMEX
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Swap ($9.14)	Henry Hub
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Basis Swap (-$0.60)	Henry Hub to Centerpoint East
2007	Ethane	8,000 BBL/Month	Ethane Swap ($28.04)	Mt. Belvieu
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
2009	Condensate & Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($69.08)	NYMEX

     The Partnership’s principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of the Partnership’s natural gas and NGL sales are made at market-based prices. The Partnership’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or continuance 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 months ended March 31, 2007 and 2006, net gains and losses on swap hedge contracts increased crude revenue by $143 and decreased crude revenue by $200, respectively. As of March 31, 2007 an unrealized derivative fair value loss of $244, 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. 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 months ended March 31, 2007 and 2006, net losses and gains on swap hedge contracts decreased gas revenue by $373 and increased gas revenue by $321, respectively. As of March 31, 2007, there is no unrealized derivative fair value gain (loss) related to cash flow hedges of natural gas price risk recorded in other comprehensive income (loss).

11

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

Natural Gas Liquids

     For the three months ended March 31, 2007 and 2006, net gains on swap hedge contracts increased liquids revenue by $71 and $154, respectively. As of March 31, 2007, there is no unrealized derivative fair value gain (loss) related to cash flow hedges of ethane price risk recorded in other comprehensive income (loss).

(6) Interest Rate Cash Flow Hedge

     In April 2006, the Partnership entered into a cash flow hedge agreement with a notional amount of $75,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate term loan credit facility. This interest rate swap matures in November 2010. The Partnership designated this swap agreement as a cash flow hedge. Under the swap agreement, the Partnership pays a fixed rate of interest of 5.25% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.

     In December 2006, the Partnership entered into a cash flow hedge agreement with a notional amount of $40,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facility. This interest rate swap matures in December 2009. The Partnership designated this swap agreement as a cash flow hedge. Under the swap agreement, the Partnership pays a fixed rate of interest of 4.82% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.

     In December 2006, the 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 March 31, 2007 with an offset to current operations.

     During the quarter ended March 31, 2007, the Partnership recognized decreases in interest expense of less than $100 related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps. The total fair value of the interest rate swaps agreement was a liability of approximately $693 at March 31, 2007.

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

	March 31,			December 31,
	2007			2006
Fair value of derivative assets — current	$	117		$	377
Fair value of derivative assets — long term		—			112
Fair value of derivative liabilities — current		—			—
Fair value of derivative liabilities — long term		(810	)		(572	)
Net fair value of derivatives	$	(693	)	$	(83	)

12

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

(7) Related Party Transactions

     Included in the consolidated and condensed financial statements are various related party transactions and balances primarily with Martin Resource Management Corporation (“MRMC”) 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 March 31,
	2007		2006
Revenues:
Terminalling and storage	$	2,585	$	2,051
Marine transportation		6,554		2,465
Product sales:
Natural gas services		—		126
Fertilizer		8		24
Terminalling and storage		3		15
		11		165
	$	9,150	$	4,681
Costs and expenses:
Cost of products sold:
Natural gas services	$	12,210	$	13,792
Sulfur		1,105		1,483
Fertilizer		2,873		1,249
Terminalling and storage		—		1
	$	16,188	$	16,525
Expenses:
Operating expenses Marine transportation	$	4,162	$	4,523
Natural gas services		385		394
Sulfur		240		172
Fertilizer		37		38
Terminalling and storage		1,037		939
	$	5,861	$	6,066
Selling, general and administrative:
Natural gas services	$	167	$	165
Sulfur		92		107
Fertilizer		295		275
Terminalling and storage		14		18
Indirect overhead allocation, net of reimbursement		326		326
	$	894	$	891

13

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

(8) Business Segments

     The Partnership has five reportable segments: terminalling and storage, natural gas services, marine transportation, sulfur and fertilizer. 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 19 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2006 filed with the SEC on March 5, 2007. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

						Operating				Operating
						Revenues		Depreciation		Income
	Operating		Intersegment			after		and		(loss) after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Three months ended March 31, 2007
Terminalling and storage	$	10,841	$	(97	)	$	10,744	$	1,340	$	2,977		$	5,006
Natural gas services		101,788		—			101,788		431		1,944			704
Marine transportation		14,876		(992	)		13,884		1,939		1,018			5,103
Sulfur		15,442		(271	)		15,171		769		489			537
Fertilizer		14,546		(337	)		14,209		415		1928			4,414
Indirect selling, general and administrative		—		—			—		—		(756	)		—
Total	$	157,493	$	(1,697	)	$	155,796	$	4,894	$	7,600		$	15,764
Three months ended March 31, 2006
Terminalling and storage	$	8,278	$	(106	)	$	8,172	$	1,076	$	2,963		$	1,940
Natural gas services		101,924		—			101,924		396		1,248			2,682
Marine transportation		9,622		(310	)		9,312		1,411		709			6,676
Sulfur		15,818		(429	)		15,389		668		1,459			5,617
Fertilizer		12,107		(82	)		12,025		401		222			2,186
Indirect selling, general and administrative		—		—			—		—		(717	)		—
Total	$	147,749	$	(927	)	$	146,822	$	3,952	$	5,884		$	19,101

     The following table reconciles operating income to net income:

	Three Months Ended
	March 31
	2007			2006
Operating income	$	7,600		$	5,884
Equity in earnings of unconsolidated entities		2,050			2,412
Interest expense		(3,577	)		(3,018	)
Debt prepayment premium		—			(1,160	)
Other, net		79			169
Income taxes		(349	)		—
Net income	$	5,803		$	4,287

14

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

     Total assets by segment are as follows:

	March 31,		December 31,
	2007		2006
Total assets:
Terminalling and storage	$	92,745	$	89,354
Natural gas services		172,324		184,464
Marine transportation		81,781		77,668
Sulfur		61,082		62,210
Fertilizer		52,361		43,765
Total assets	$	460,293	$	457,461

(9) Public Offering

     In January 2006, the Partnership completed a public offering of 3,450,000 common units at a price of $29.12 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 61.6% limited partnership interest in the Partnership. Total proceeds from the sale of the 3,450,000 common units, net of underwriters’ discounts, commissions and offering expenses were $95,272. The Partnership’s general partner contributed $2,050 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital.

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

Proceeds received:
Sale of common units	$	100,464
General partner contribution		2,050
Total proceeds received	$	102,514
Use of Proceeds:
Underwriter’s fees	$	4,521
Professional fees and other costs		671
Repayment of debt under revolving credit facility		62,000
Working capital		35,322
Total use of proceeds	$	102,514

(10) Acquisitions

     (a) Asphalt Terminals. In August 2006 and October 2006, respectively, the Partnership acquired the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (“Prime”), for $4,842 which was allocated to property, plant and equipment. The assets are located in Houston, Texas and Port Neches, Texas. The Partnership entered into an agreement with Martin Resource Management, which Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will assume all additional expenses to operate the facility.

     (b) Corpus Christi Barge Terminal. In July 2006, the Partnership acquired a marine terminal located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6,200 which was all allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land, and includes three tanks with a combined shell capacity of approximately 240,000 barrels, pump and piping infrastructure for truck unloading and product delivery to two oil docks, and there are several pumps, controls, and an office building on site for administrative use.

15

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

     (c) Marine Vessels. In November 2006, the Partnership acquired the La Force, an offshore tug, for $6,001 from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 with new engines installed in 2005.

     In January 2006, the Partnership acquired the Texan, an offshore tug, and the Ponciana, an offshore NGL barge, for $5,850 from Martin Resource Management. The acquisition price was based on a third-party appraisal. In March 2006, these vessels went into service under a long term charter with a third party. In February 2006, the Partnership acquired the M450, an offshore barge, for $1,551 from a third party. In March 2006, this vessel went into service under a one-year evergreen charter with an affiliate of MRMC.

(11) Long-Term Debt

     At March 31, 2007 and December 31, 2006, long-term debt consisted of the following:

	March 31,		December 31,
	2007		2006
**$120,000 Revolving loan facility at variable interest rate (7.50%* weighted average at March 31, 2007), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries	$	60,000	$	44,000
***$130,000 Term loan facility at variable interest rate (7.69%* at March 31, 2007), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries		130,000		130,000
Other secured debt maturing in 2008, 7.25%		76		95
Total long-term debt		190,076		174,095
Less current installments		75		74
Long-term debt, net of current installments	$	190,001	$	174,021

*     Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.50%. Effective April 1, 2007, the applicable margin for existing borrowings decreased to 2.00%. We incur a commitment fee on the unused portions of the credit facility.

**   Effective December 13, 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 April 13, 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 March 28, 2007, 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 August 18, 2006, the Partnership purchased certain terminalling assets and assumed associated long term debt of $113 with a fixed rate cost of 7.25%.

16

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

     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, we increased our revolving credit facility $25,000 resulting in a committed $120,000 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 March 31, 2007, we had $60,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of March 31, 2007, we had $59,900 available under our 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. 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) incur indebtedness or grant certain liens for its joint ventures.

     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 (x) 5.5 to 1.0 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter thereafter. The Partnership was in compliance with the debt covenants contained in credit facility for the year ended December 31, 2006 and as of March 31, 2007.

     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 under the term loan through March 31, 2007. 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.

17

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

     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 $170,600 to a high of $198,100. As of March 31, 2007, the Partnership had $59,900 available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility.

     On July 15, 2005, the Partnership assumed $9,400 of U.S. Government Guaranteed Ship Financing Bonds, maturing in 2021, relating to the acquisition of CF Martin Sulphur L.P. (“CF Martin Sulphur”). The outstanding balance as of December 31, 2005 was $9,104. These bonds were payable in equal semi-annual installments of $291, and were secured by certain marine vessels owned by CF Martin Sulphur. Pursuant to the terms of an amendment to the Partnership’s credit facility that it entered into in connection with the acquisition of CF Martin Sulphur, the Partnership was obligated to repay these bonds by March 31, 2006. The Partnership redeemed these bonds on March 6, 2006 with available cash and borrowings from its credit facility. Also, at redemption, a pre-payment premium was paid in the amount of $1,160.

     The Partnership paid cash interest in the amount of $3,603 and $3,777 for the quarters ended March 31, 2007 and 2006 respectively. Capitalized interest for the quarters ended March 31, 2007 and 2006 was $539 and $272, respectively.

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

(12) Income Taxes

     The operations of the Partnership are not subject to income taxes, except for the Texas margin tax as described in the following paragraph, and as a result, the Partnership’s income is taxed directly to its owners. As a result of its acquisition of Prism Gas, the Partnership assumed a current tax liability of $6.3 million as a result of a tax event triggered by the transfer of the ownership of the assets of Prism Gas in 2005 from a corporate to a partnership structure through the partial liquidation of the corporation. This liability was paid in 2006. The final liquidation of this corporate entity was completed on November 15, 2006. Additional federal and state income taxes of $214 resulting from the liquidation were recorded in current year income tax expense for the quarter ending March 31, 2007.

     On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Partnership has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change was immaterial. The impact of the change in deferred tax assets does not have a material impact on tax expense. State income taxes attributable to the Texas margin tax of $135 were recorded in current year income tax expense for the quarter ending March 31, 2007.

     The components of current income tax expense from operations recorded for the three months ended March 31, 2007 are as follows:

Federal	$	169
State		180
	$	349

18

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2007
(Unaudited)

(13) Gain on Involuntary Conversion of Assets

     During the third quarter of 2005, the Partnership experienced a casualty loss caused by two major storms, Hurricane Katrina and Hurricane Rita. Physical damage to the Partnership’s assets caused by the hurricanes, as well as the related removal and recovery costs, were covered by insurance subject to a deductible. The Partnership recorded an additional insurance receivable during the first quarter of 2006, which resulted in a gain of $853 for this involuntary conversion of assets reported in other operating income. The total insurance receivable at March 31, 2006 relating to these damages of $2,541 was subsequently collected.

19

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. Risks Factors” of our Form 10-K for the year ended December 31, 2006 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2007.

Overview

     We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Our five 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;

• Sulfur gathering, processing and distribution; and

• Fertilizer 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 approximately 39.4% of our limited partnership units. 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

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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.

Recent Development

     On May 2, 2007, we acquired the outstanding stock of Woodlawn Pipeline Company, Inc. (“Woodlawn”), a natural gas gathering and processing company with integrated gathering and processing assets in East Texas for $30.6 million. In addition, we purchased a compressor for $0.4 million from an affiliate of the selling parties. In conjunction with this transaction, we also acquired a pipeline that delivers residue gas from the Woodlawn processing plant to the Texas Eastern Transmission pipeline system for $2.1 million.

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, 2006 filed with the SEC on March 5, 2007 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 SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”).

     Derivatives

     In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. In early 2006, we adopted a hedging policy that allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges 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 March 31, 2007, 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 NGLs with third parties. We record the balance of NGLs due to other companies under these agreements at quoted market product prices and the balance of NGLs and sulfur due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out method.

     In September 2005, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. This pronouncement provides additional accounting guidance for situations involving inventory exchanges between parties to that contained in APB Opinion No. 29, Accounting for Nonmonetary Transactions and SFAS 153, Exchanges of Nonmonetary Assets. The standard is effective for new arrangements entered into in reporting periods beginning after March 15, 2006. The adoption did not have a material impact on our financial statements.

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     Revenue Recognition

     Revenue for our five 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. Revenue for lubricants and drilling fluids products 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 and Fertilizer – Revenue is recognized when the customer takes title to the product, either at our plant or the customer facility.

     Equity Method Investments

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

     We own an unconsolidated 50% interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), and Panther Interstate Pipeline Energy LLC (“PIPE”). These interests are accounted for under the equity method of accounting.

     On June 30, 2006, we, through our subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). This interest 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.

     We have four “reporting units” which contained goodwill. These reporting units were four of our reporting segments: marine transportation, natural gas services, sulfur and fertilizer.

     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.

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     Environmental Liabilities

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

     Allowance for Doubtful Accounts

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

• 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; and

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

     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 38.6% 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

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energy industry. We do not have employees. Martin Resource Management employees are responsible for conducting our business and operating our assets on our behalf.

     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 and indirect 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 $12.7 million of direct costs and expenses for the three months ended March 31, 2007 compared to $11.6 million for the three months ended March 31, 2006. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses. Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million for the twelve month period ending October 31, 2006. For each of the subsequent three years, this amount may be increased by no more than the percentage increase in the consumer price index and is also subject to adjustment for expansions of our operations. As of May 7, 2007, we have not increased this cap. We reimbursed Martin Resource Management for $0.4 million of indirect expenses for the three months ended March 31, 2007 and 2006. These indirect expenses cover all of the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The omnibus agreement also contains significant non-compete provisions and indemnity obligations.

     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, 2006 filed with the SEC on March 5, 2007.

     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 65 million gallons. 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 and fertilizer payroll reimbursements from Martin Resource Management accounted for approximately 14% of our total cost of products sold during both the three months ended March 31, 2007 and 2006. 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% and 3% of our total revenues for the three months ended March 31, 2007 and 2006, respectively. In connection with the closing of

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the acquisition of the marine services assets from Tesoro Marine Services, L.L.C., we entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel provides terminal services to us to handle lubricants, greases and drilling fluids.

     For a more comprehensive discussion concerning these commercial agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions — Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2006 filed with the SEC on March 5, 2007.

     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 months ended March 31, 2007 and 2006 have been derived from the consolidated and condensed financial statements of the Partnership.

     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 ended March 31, 2007 and 2006. The results of operations for the first three months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

						Operating					Operating			Operating
			Revenues			Revenues		Operating			Income			Income (loss)
	Operating		Intersegment			after		Income			Intersegment			after
	Revenues		Eliminations			Eliminations		(loss)			Eliminations			Eliminations
	(In thousands)
Three months ended March 31, 2007
Terminalling and storage	$	10,841	$	(97	)	$	10,744	$	2,887		$	90		$	2,977
Natural gas services		101,788		—			101,788		1,944			—			1,944
Marine transportation		14,876		(992	)		13,884		2,004			(986	)		1,018
Sulfur		15,442		(271	)		15,171		(262	)		751			489
Fertilizer		14,546		(337	)		14,209		1,783			145			1,928
Indirect selling, general and administrative		—		—			—		(756	)		—			(756	)
Total	$	157,493	$	(1,697	)	$	155,796	$	7,600		$	—		$	7,600
Three months ended March 31, 2006
Terminalling and storage	$	8,278	$	(106	)	$	8,172	$	3,005		$	(42	)	$	2,963
Natural gas services		101,924		—			101,924		1,248			—			1,248
Marine transportation		9,622		(310	)		9,312		1,019			(310	)		709
Sulfur		15,818		(429	)		15,389		1,153			306			1,459
Fertilizer		12,107		(82	)		12,025		176			46			222
Indirect selling, general and administrative		—		—			—		(717	)		—			(717	)
Total	$	147,749	$	(927	)	$	146,822	$	5,884		$	—		$	5,884

     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 of

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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 March 31, 2007 Compared to the Three Months Ended March 31, 2006

     Our total revenues before eliminations were $157.5 million for the three months ended March 31, 2007 compared to $147.8 million for the three months ended March 31, 2006, an increase of $9.7 million, or 7%. Our operating income was $7.6 million for the three months ended March 31, 2007 compared to $5.9 million for the three months ended March 31, 2006, an increase of $1.7 million, or 31%.

     The results of operations are described in greater detail on a segment basis below.

     Terminalling and Storage Segment

     The following table summarizes our results of operations in our terminalling and storage segment.

	Three Months Ended
	March 31,
	2007		2006
	(In thousands)
Revenues:
Services	$	6,951	$	5,756
Products		3,890		2,522
Total revenues		10,841		8,278
Cost of products sold		3,165		2,063
Operating expenses		3,420		2,967
Selling, general and administrative expenses		29		20
Depreciation and amortization		1,340		1,076
		2,887		2,152
Other operating income		—		853
Operating income	$	2,887	$	3,005

     Revenues. Our terminalling and storage revenues increased $2.6 million, or 31%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. Service revenue accounted for $1.2 million of this increase. The service revenue increase was primarily a result of acquisitions of the Corpus Christi terminal, our two asphalt terminals and increased business activity at our shore based terminals. Product revenue increased $1.4 million due to a 32% increase in sales volumes, and a 17% increase in product cost that was passed through to our customers.

     Cost of products sold. Our cost of products sold increased $1.1 million, or 53%, for the three months ended March 31, 2007, compared to the three months ended March 31, 2006. This increase was primarily a result of 32% increase in sales volumes and a 17% increase in product cost that was passed through to our customers.

     Operating expenses. Operating expenses increased $0.5 million, or 15%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This increase is due primarily to $0.2 million of additional operating expenses from the acquisition of the Corpus Christi terminal and $0.1 million of increased product handling fees.

     Selling, general and administrative expenses. Selling, general and administrative expenses were approximately the same for both three month periods.

     Depreciation and amortization. Depreciation and amortization increased $0.3 million, or 25% for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This increase was primarily a result of our 2006 acquisitions.

     Other operating income. Other operating income decreased $0.9 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This decrease consisted solely of a gain of $0.9 million related to an involuntary conversion of assets in 2006.

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     In summary, our terminalling and storage operating income decreased $0.1 million, or 4%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006.

     Natural Gas Services Segment

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

	Three Months Ended
	March 31,
	2007		2006
	(In thousands)
Revenues	$	101,788	$	101,924
Cost of products sold		96,772		98,083
Operating expenses		1,323		1,304
Selling, general and administrative expenses		1,318		893
Depreciation and amortization		431		396
Operating income	$	1,944	$	1,248
Equity in Earnings of Unconsolidated Entities	$	2,050	$	2,412
NGL Volumes (gallons)		89,656		89,679

     Revenues. Our natural gas services revenues were approximately the same for both three month periods. Our historical NGL distribution segment revenues increased $1.4 million, or 2%. The increase in revenues is primarily due from an increase in sales volumes, resulting from increased demand from our industrial customers and retail propane customers as we experienced colder temperatures during the first quarter of 2007 as compared to this same period last year. However, the increase in sales volumes in our historical NGL distribution segment was offset by a 2% decrease in our average sales price per gallon in 2007 compared to 2006.

     Despite the increases gained in our historical NGL distribution segment, Prism Gas experienced a $1.5 million, or 8% decline in revenue. The decrease in revenue was comprised of a $0.4 million decline in NGL sales, a $0.8 million drop in natural gas sales, $0.4 million loss on derivative contracts, offset by a $0.1 million increase in gathering and processing fees. The decline in both NGL and natural gas sales was primarily attributable to shut in volumes due to unanticipated operational issues on a third party pipeline that have since been resolved.

     Costs of products sold. Our cost of products decreased $1.3 million, or 1%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This decrease was primarily related to Prism Gas, as they experienced a $1.1 million decline in cost of products sold due primarily from shut in volumes caused by unanticipated operational issues on a third party pipeline that have since been resolved. The balance of the decrease of $0.2 million relates to our historical NGL distribution segment. During the first quarter of 2007 we were able to expand our per gallon margins in our historical NGL distribution segment by 68%, as a result of colder weather.

     Operating expenses. Operating expenses were approximately the same for both three month periods.

     Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.4 million, or 48%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This increase was primarily a result of increased payroll costs.

     Depreciation and amortization. Depreciation and amortization was approximately the same for both three month periods.

     In summary, our natural gas services operating income increased $0.7 million, or 56%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006.

     Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $2.1 million for the three months ended March 31, 2007 compared to $2.4 for the three months ended March 31,

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2006. During the first quarter of 2007 the fractionator at the Waskom Plant was shut down for an approximate two week period to accommodate our plant expansion. In addition, gas supply at the Waskom Plant has increased, but less volumes are being processed as higher operating expenses associated with processing gas in excess of plant capacity made processing the increased volumes uneconomical. Our planned expansion of the Waskom Plant to 250 Mcfd which we expect to be completed at the end of the second quarter of 2007 will allow us to economically process these increased volumes.

     Marine Transportation Segment

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

	Three Months Ended
	March 31,
	2007		2006
	(In thousands)
Revenues	$	14,876	$	9,622
Operating expenses		10,867		7,072
Selling, general and administrative expenses		66		120
Depreciation and amortization		1,939		1,411
Operating income	$	2,004	$	1,019

     Revenues. Our marine transportation revenues increased $5.3 million, or 55%, for the three months ended March 31, 2007, compared to the three months ended March 31, 2006. Our offshore revenues increased $1.3 million primarily from the acquisition of two integrated tug barge units. Our inland marine operations generated an additional $3.8 million in revenue from increased utilization of our fleet as a result of a geographical redistribution of our assets on the gulf coast. We also had increased contract rates, and operated an additional number of leased vessels.

     Operating expenses. Operating expenses increased $3.8 million, or 54%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. We experienced increases in operating costs from our outside towing expense for leased vessels and property damage claims. Additionally, associated costs increased from the acquisition of two offshore tug barge units.

     Selling, general, and administrative expenses. Selling, general and administrative expenses decreased $0.1 million, or 44%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006.

     Depreciation and Amortization. Depreciation and amortization increased $0.5 million, or 37%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This increase was primarily a result of capital expenditures made in the last twelve months.

     In summary, our marine transportation operating income increased $1.0 million, or 97%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006.

     Sulfur Segment

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

	Three Months Ended
	March 31,
	2007			2006
	(In thousands)
Revenues	$	15,442		$	15,818
Cost of products sold		10,524			10,901
Operating expenses		4,261			2,862
Selling, general and administrative expenses		151			234
Depreciation and amortization		768			668
Operating income	$	(262	)	$	1,153
Sulfur Volumes (long tons)		294.8			197.0

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     Revenues. Our sulfur revenues decreased $0.4 million, or 2%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This decrease resulted from a 50% increase in sales volume offset by a 31% decrease in sales price. Our selling price per ton decreased due to the U.S. domestic market price decreasing $19.50 per ton for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. The decline in our selling price resulted from a decrease in demand from our sulfur customers.

     Cost of products sold. Our cost of products sold decreased $0.4 million, or 3%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This decrease in our cost of products sold was approximately the same as our decrease in sulfur revenue as our supply cost from our sulfur producers decreased.

     Operating expenses. Our operating expenses increased $1.4 million, or 49%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This increase was a result of increased marine transportation expenses. These marine transportation cost increases primarily related to repairs and maintenance and associated outside towing costs as our offshore tug was out of service for unanticipated repairs.

     Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.1 million, or 36%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006.

     Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 15%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. This is attributable to the priller conveyor system at our Neches facility which was completed in August 2006.

     In summary, our sulfur operating income decreased $1.4 million, or 123%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006.

     Fertilizer Segment

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

	Three Months Ended
	March 31,
	2007		2006
	(In thousands)
Revenues	$	14,546	$	12,107
Cost of products sold and operating expenses		11,947		11,128
Selling, general and administrative expenses		401		401
Depreciation and amortization		415		402
Operating income	$	1,783	$	176
Fertilizer Volumes (tons)		79.3		64.8

     Revenues. Our fertilizer business revenues increased $2.4 million, or 20%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. Our sales volume increased 22% due to increased demand from our customers. This increased demand was driven by higher commodity prices in the agricultural markets we serve.

     Cost of products sold and operating expenses. Our cost of products sold and operating expenses increased $0.8 million, or 7%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. The increase was less than our revenue increase as we expanded our per ton margins.

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

     Depreciation and amortization. Depreciation and amortization were approximately the same for both three month periods.

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     In summary our fertilizer operating income increased $1.6 million, or 913%, for the three months ended March 31, 2007 compared to the three months ended March 31, 2006.

     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 ended March 31, 2007 and 2006 are as follows:

	Three Months Ended
	March 31,
	2007			2006
Revenues		100	%		100	%
Cost of products sold		78	%		83	%
Operating expenses		12	%		9	%
Selling, general and administrative expenses		2	%		2	%
Depreciation and amortization		3	%		3	%

     Equity in Earnings of Unconsolidated Entities

     For the three months ended March 31, 2007 and 2006 equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom, Matagorda and PIPE. PIPE also includes equity in earnings of our unconsolidated interest in BCP for the three months ended March 31, 2007.

     Equity in earnings of unconsolidated entities was $2.1 million for the three months ended March 31, 2007 compared to $2.4 million for the three months ended March 31, 2006, a decrease of $0.3 million. This decrease is related to earnings received from Waskom, Matagorda, PIPE and BCP.

     Interest Expense

     Our interest expense for all operations was $3.6 million for the three months ended March 31, 2007, compared to the $3.0 million for the three months ended March 31, 2006, an increase of $0.6 million, or 20%. This increase was primarily due to an increase in average debt outstanding and an increase in interest rates in the first quarter of 2007 compared to the same period in 2006.

     Indirect Selling, General and Administrative Expenses

     Indirect selling, general and administrative expenses were $0.8 million for the three months ended March 31, 2007 compared to $0.7 million for the three months ended March 31, 2006, an increase of $0.1 million, or 14%.

     Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income. Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million for the period ending October 31, 2006. Subsequently, this amount may be increased by no more than the percentage increase in the consumer price index. In addition, Martin Resource Management and us can agree, subject to approval of the Conflicts Committee of our general partner, to adjust this amount for expansions of our operations and acquisitions. Martin Resource Management allocated indirect selling, general and administrative expenses of $0.4 million for both three months ended March 31, 2007 and 2006, respectively.

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Liquidity and Capital Resources

     Cash Flows and Capital Expenditures

     For the three months ended March 31, 2007, cash increased $0.9 million as a result of $11.9 million provided by operating activities, $18.5 million used in investing activities and $7.5 million provided by financing activities. For the three months ended March 31, 2006, cash decreased $1.2 million, as a result of $0.5 million used by operating activities, $26.2 million used in investing activities and $25.5 million provided by financing activities.

     For the three months ended March 31, 2007 our investing activities of $18.5 million consisted primarily of payments for capital expenditures of $15.8 million, investments in unconsolidated entities of $3.9 million and returns of investments from unconsolidated entities of $1.1 million. For the three months ended March 31, 2006, our investing activities of $26.2 million consisted primarily of payments for capital expenditures and acquisitions of $26.6 million, proceeds from sale of property, plant and equipment of $0.7 million, investments in unconsolidated entities of $0.5 million and returns of investments from unconsolidated entities of $0.2 million.

     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 three months ended March 31, 2007 and 2006, our capital expenditures for property and equipment were $15.8 million and $26.6 million, respectively.

     As to each period:

• For the three months ended March 31, 2007, we spent $14.8 million for expansion and $1.0 million for maintenance. Our expansion capital expenditures were made in connection with projects related to upgrading a number of our marine transportation assets, construction projects associated with our existing terminalling facilities, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and in our terminal segment for terminal facilities where $0.1 million in maintenance capital expenditures was spent in connection with restoration of assets destroyed in Hurricanes Rita and Katrina.

• For the three months ended March 31, 2006, we spent $23.3 million for expansion and $3.3 million for maintenance. Our expansion capital expenditures were made in connection with our marine vessel purchases, construction projects associated with Prism Gas, the sulfur priller construction project at our Neches facility in Beaumont, Texas, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dockings of our vessels pursuant to the United States Coast Guard requirements and in our terminal segment for terminal facilities where $1.3 million in maintenance capital expenditures was spent in connection with restoration of assets destroyed in Hurricanes Rita and Katrina.

     We made net investments in unconsolidated entities of $3.9 million and $0.5 million during the three months ended March 31, 2007 and 2006, respectively. The net investment in unconsolidated entities includes $4.1 million and $1.2 million of expansion capital expenditures in the three months ended March 31, 2007 and 2006, respectively.

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     For the three months ended March 31, 2007, financing activities consisted of cash distributions paid to common and subordinated unitholders of $8.5 million, payment of long term debt to financial lenders of $25.1 million and borrowings of long-term debt under our credit facility of $41.1 million. For the three months ended March 31, 2006, financing activities consisted of cash distributions paid to common and subordinated unitholders of $8.0 million, net proceeds from a follow on equity offering of $95.3 million, payment of long term debt to financial lenders of $82.9 million, borrowings of long-term debt under our credit facility of $19.1 million, and contributions of $2.1 million from our general partner.

     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 March 31, 2007, we had $190.1 million of outstanding indebtedness, consisting of outstanding borrowings of $60.0 million under our revolving credit facility and $130.0 million under our term loan facility and $0.1 million of other secured debt.

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

     In November 2005, we borrowed approximately $63.1 million under our credit facility to pay a portion of the purchase price for the Prism Gas acquisition. The remainder of the purchase price was funded by $5.0 million previously escrowed by us, $15.5 million of new equity capital provided by Martin Resource Management in exchange for newly issued common units, approximately $9.6 million of newly issued common units issued to a certain number of the sellers and approximately $0.8 million in capital provided by Martin Resource Management for acquisition costs and to maintain its 2% general partnership interest in us. The common units were priced at $32.54 per common unit, based on the average closing price of our common units on the NASDAQ during the ten trading days immediately preceding and immediately following the date of the execution of the definitive purchase agreement.

     In January 2006, we completed a follow-on public offering of 3,450,000 common units, resulting in proceeds of $95.4 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $2.1 million in cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. Of the net proceeds, $62.0 million was used to pay then current balances under our revolving credit facility and $7.5 million was used to fund a portion of the redemption price for our U.S. Government Guaranteed Ship Financing Bonds. These bonds were paid on March 6, 2006 with available cash and borrowings from our revolving credit facility. At such time, we also paid the related $1.2 million pre-payment premium. The remainder of the net proceeds has been or will be used to fund future organic growth projects.

     In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a capital contribution of approximately $0.3 million made by our general partner in order to maintain its 2% general partner interest in us. These funds were used to reduce the revolving line of credit.

     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 2007. However, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. For a discussion of such risks, please read “Item 1A. Risk Factors — Risks Related to Our Business” in our annual report on Form 10-K for the year ended December 31, 2006 filed with the SEC on March 5, 2007.

     Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of March 31, 2007 is as follows: (dollars in thousands):

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	Payment due by period
	Total				1-3		3-5		Due
Type of Obligation	Obligation		Less than One Year		Years		Years		Thereafter
	(in thousands)
Long-Term Debt
Revolving credit facility	$	60,000	$	—	$	—	$	60,000	$	—
Term loan facility		130,000		—		—		130,000		—
Other		76		75		1		—		—
Non-competition agreements		950		250		450		100		150
Operating leases		31,480		3,927		9,949		5,905		11,699
Interest expense(1)
Revolving Credit Facility		15,194		4,198		8,396		2,600		—
Term loan facility		33,831		9,347		18,694		5,790		—
Other		5		5		—		—		—
Total contractual cash obligations	$	271,536	$	17,802	$	37,490	$	204,395	$	11,849

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

     Letter of Credit At December 31, 2006, 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. 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 March 31, 2007, we had $60.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of March 31, 2007, we had $59.9 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 $170.6 million to a high of $198.1 million.

     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 2.50%. As a result of our leverage ratio test, effective April 1,

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2007, the applicable margin for existing borrowings decreased to 2.00%. We incur a commitment fee on the unused portions of the credit facility.

     Effective April 13, 2006, we entered into a cash flow hedge that swaps $75.0 million of floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010.

     Effective December 13, 2006, we entered into a cash flow hedge that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing spread. The cash flow hedge matures in December, 2009.

     Effective December 13, 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 as a cash flow hedge.

     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 (x) 5.5 to 1.0 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter thereafter. We are in compliance with the debt covenants contained in the credit facility.

     On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. No prepayments under the term loan were required to be made in 2006. 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 May 7, 2007, our outstanding indebtedness includes $223.0 million under our credit facility, including $33.0 million borrowed in connection with the Woodlawn acquisition.

Seasonality

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

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adversely impacted operating expenses and the four hurricanes that impacted the Gulf of Mexico and Florida in the third quarter of 2004 adversely impacted our terminalling and storage and marine transportation business’s revenues.

Impact of Inflation

     Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three months ended March 31, 2007 and 2006. However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot assure 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 three months ended March 31, 2007 or 2006. Under our omnibus agreement, Martin Resource Management will indemnify us through November 6, 2007, against:

• certain potential environmental liabilities associated with the assets it contributed to us relating to events or conditions that occurred or existed before the closing of our initial public offering in November 2002; and

• any payments we are required to make, as a successor in interest to affiliates of Martin Resource Management, under environmental indemnity provisions contained in the contribution agreement associated with the contribution of assets by Martin Resource Management to CF Martin Sulphur L.P. in November 2000.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

     Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not engaged in commodity contract trading or hedging activities. However, in connection with our acquisition of Prism Gas, we have established a hedging policy. For the period ended March 31, 2007, changes in the fair value of our derivative contracts were recorded both in earnings and comprehensive income since we have designated a portion of our derivative instruments as hedges as of March 31, 2007.

     Commodity Price Risk. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not engaged in commodity contract trading or hedging activities. Under our hedging policy, we monitor and manage the commodity market risk associated with the commodity risk exposure of Prism Gas. In addition, we are focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

     We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the commodity derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank.

     On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, and have established a maximum credit limit threshold pursuant to our hedging policy and monitor the appropriateness of these limits on an ongoing basis.

     As a result of the Prism Gas acquisition, we are exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales

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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 2009 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas and ethane.

     Based on estimated volumes, as of March 31, 2007, Prism Gas had hedged approximately 55%, 46%, and 14% of its commodity risk by volume for 2007, 2008, and 2009, 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

Year	Commodity Hedged	Volume	Type of Derivative	Basis Reference
2007	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($65.95)	NYMEX
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Swap ($9.14)	Henry Hub
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Basis Swap (-$0.60)	Henry Hub to Centerpoint East
2007	Ethane	8,000 BBL/Month	Ethane Swap ($28.04)	Mt. Belvieu
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
2009	Condensate & Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($69.08)	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 continuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Partnership.

     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 7.63% as of March 31, 2007. We had a total of $190.0 million of indebtedness outstanding under our credit facility as of the date hereof of which $45.0 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on March 31, 2007, 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 $0.5 million annually.

Item 4. Controls and Procedures

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

     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 15d-15(f)) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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.

Item 1A. Risk Factors

     There have been no material changes in our risk factors from those disclosed in “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2006 filed with the SEC on March 5, 2007.

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.

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SIGNATURES

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

	Martin Midstream Partners L.P.
	By:	Martin Midstream GP LLC
		Its General Partner
Date: May 7, 2007		By:	/s/ Ruben S. Martin
			Ruben S. Martin
			President and Chief Executive Officer

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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	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).
3.4	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).
3.5	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).
3.6	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).
3.7	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).
3.8	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	Martin Resource Management Corporation Purchase Plan for Units of Martin Midstream Partners L.P. (filed as Exhibit 10.1 to the Partnership’s registration statement on Form S-8 (Reg. No. 333-140152), filed January 23, 2007 and incorporated herein by reference).
10.2	Stock Purchase Agreement, dated April 27, 2007, by and among Woodlawn Pipeline Company, Inc., Lantern Resources, L.P., David P. Deison and Prism Gas Systems I, L.P. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 2, 2007, and incorporated herein by reference).
10.3	Asset Purchase Agreement, dated April 27, 2007, by and among Peak Gas Gathering L.P. and Prism Gas Systems I, L.P. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed May 2, 2007, and incorporated herein by reference).
23.1*	Consent of KPMG
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 December 31, 2006 (audited) and March 31, 2007 (unaudited) of Martin Midstream GP LLC.

* Filed or furnished herewith

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EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Martin Midstream GP LLC

We consent to the incorporation by reference in the registration statements (No. 333-117023) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. and Subsidiaries of our report dated May 7, 2007, with respect to the consolidated balance sheet of Martin Midstream GP LLC as of December 31, 2006, which report appears in the March 31, 2007 report on Form 10-Q of Martin Midstream Partners L.P.

KPMG LLP

/s/ KPMG LLP

Shreveport, Louisiana
May 7, 2007

EX-31.1

Exhibit 31.1

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

I, Ruben S. Martin, certify that:

     1. I have reviewed this quarterly report on Form 10-Q of Martin Midstream Partners L.P.;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

          a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

          b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

          c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

          d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

          a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

          b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2007

/s/ Ruben S. Martin

Ruben S. Martin, President and

Chief Executive Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-31.2

Exhibit 31.2

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

I, Robert D. Bondurant, certify that:

     1. I have reviewed this quarterly report on Form 10-Q of Martin Midstream Partners L.P.;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

          a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

          b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

          c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

          d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

          a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

          b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2007

/s/ Robert D. Bondurant

Robert D. Bondurant, Executive Vice President and

Chief Financial Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)*

     In connection with the Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ending March 31, 2007 as filed with the Securities and Exchange Commission (the “Report”), I, Ruben S. Martin, Chief Executive Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

     (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

     (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

/s/ Ruben S. Martin

Ruben S. Martin,

Chief Executive Officer of Martin Midstream GP LLC,

General Partner of Martin Midstream Partners L.P.

May 7, 2007

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)*

     In connection with the Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ending March 31, 2007 as filed with the Securities and Exchange Commission (the “Report”), I, Robert D. Bondurant, Chief Financial Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

     (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

     (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

/s/ Robert D. Bondurant

Robert D. Bondurant,

Chief Financial Officer

of Martin Midstream GP LLC,

General Partner of Martin Midstream Partners L.P.

May 7, 2007

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

EX-99.1

Exhibit 99.1

Independent Auditors’ Report

The Board of Directors
Martin Midstream GP LLC:

     We have audited the accompanying consolidated balance sheet of Martin Midstream GP LLC as of December 31, 2006. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

     We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit of a balance sheet also includes examining, on a test basis, evidence supporting the amounts and disclosures in that balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the consolidated balance sheet provides a reasonable basis for our opinion.

     In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Martin Midstream GP LLC at December 31, 2006, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Shreveport, Louisiana
May 7, 2007

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

	March 31,			December 31,
	2007			2006
	(Unaudited)			(Audited)
Assets
Cash	$	4,578		$	3,675
Accounts and other receivables, less allowance for doubtful accounts of $242 and $394		58,676			56,712
Product exchange receivables		1,982			7,076
Inventories		26,169			33,019
Due from affiliates		1,100			1,330
Other current assets		1,317			2,049
Total current assets		93,822			103,861
Property, plant and equipment, at cost		339,731			323,967
Accumulated depreciation		(80,860	)		(76,122	)
Property, plant and equipment, net		258,871			247,845
Goodwill		27,600			27,600
Investment in unconsolidated entities		73,406			70,651
Other assets, net		6,594			7,512
	$	460,293		$	457,469
Liabilities and Members’ Equity
Current installments of long-term debt	$	75		$	74
Trade and other accounts payable		55,239			53,450
Product exchange payables		6,018			14,737
Due to affiliates		9,899			12,612
Other accrued liabilities		3,452			3,876
Total current liabilities		74,683			84,749
Long-term debt		190,001			174,021
Other long-term obligations		3,107			2,626
Total liabilities		267,791			261,396
Minority interests		191,574			195,302
Members’ equity		928			771
		192,502			196,073
Commitments and contingencies	$	460,293		$	457,469

See accompanying notes to the consolidated balance sheets

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(1) ORGANIZATION AND DESCRIPTION OF BUSINESS

     Martin Midstream GP LLC (the “General Partner”) is a single member Delaware limited liability company formed on June 21, 2002 to become the general partner of Martin Midstream Partners L.P. (the “Company”). The General Partner owns a 2% general partner interest and incentive distribution rights in the Company. The General Partner is a wholly owned subsidiary of Martin Resource Management Corporation (“MRMC”).

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

     Martin Midstream Partners L.P. (the “Company”) is a publicly traded limited Company which provides terminalling and storage services for petroleum products and by-products, natural gas services, marine transportation services for petroleum products and by-products, sulfur gathering, processing and distribution and fertilizer manufacturing and distribution.

     On November 10, 2005, the Company acquired Prism Gas Systems I, L.P. (“Prism Gas”) which is engaged in the gathering, processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana. Through the acquisition of Prism Gas, the Company also acquired 50% ownership interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), and the Panther Interstate Pipeline energy LLC (“Panther”) each accounted for under the equity method of accounting.

     The petroleum products and by-products the Company collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as 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. The Company operates primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry.

     (2) SIGNIFICANT ACCOUNTING POLICIES

     (a) Principles of Presentation and Consolidation

     The consolidated balance sheets include the financial position of the General Partner and the Company and its wholly-owned subsidiaries (collectively, the “Company”). All significant intercompany balances and transactions have been eliminated in consolidation. As the General Partner only has a 2% interest in the Company, the remaining 98% not owned is shown as minority interests in the consolidated balance sheets. In addition, the Company evaluates its relationships with other entities to identify whether they are variable interest entities as defined by FASB Interpretation No 46(R) Consolidation of Variable Interest Entities (“FIN 46R”) and to assess whether they are the primary beneficiary of such entities. If the determination is made that the Company is the primary beneficiary, then that entity is included in the consolidated balance sheet in accordance with FIN 46(R). No such variable interest entities exist as of March 31, 2007 and December 31, 2006.

     (b) Product Exchanges

     Product exchange balances due to other companies under negotiated agreements are recorded at quoted market product prices while balances due from other companies are recorded at the lower of cost (determined using the “FIFO” method) or market.

3

     (c) Inventories

     Inventories are stated at the lower of cost or market. Cost is determined by using the “FIFO” method for all inventories.

     (d) Revenue Recognition

Revenue for the Company’s five 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.

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.

Natural gas/LPG services – Natural gas gathering and processing revenues are recognized when title passes or service is performed. LPG distribution revenue is recognized when product is delivered by truck to our LPG customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, the Company recognizes LPG distribution revenue when the customer receives the product from either the storage facility or pipeline.

Sulfur – Revenue is recognized when the customer takes title to the product, either at our plant or the customer facility.

Fertilizer – Revenue is recognized when the customer takes title to the product, either at our plant or the customer facility.

     (e) Equity Method Investments

     The Company uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Company’s share of accumulated earnings less capital withdrawals and dividends. Any excess of cost over the underlying equity in net assets is recognized as goodwill. Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock.

     (f) Property, Plant, and Equipment

     Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.

     Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.

     (g) Goodwill and Other Intangible Assets

     Goodwill represents the excess of costs over fair value of net assets of businesses acquired. Goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. Intangible assets with estimated useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with FASB Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible assets primarily consists of covenants not-to-compete obtained through business combinations and are being amortized over the life of the respective agreements.

4

     (h) Debt Issuance Costs

     In connection with the Company’s multi-bank credit facility, on November 10, 2005, it incurred debt issuance costs of $3,258. In connection with the amendment and expansion of the Company’s multi-bank credit facility on June 30, 2006, it incurred debt issuance costs of $372. These debt issuance costs, along with the remaining unamortized deferred issuance costs relating to the line of credit facility as of November 10, 2005 which remain deferred, are amortized over 60 month term of the new debt arrangement. The unamortized balance of debt issuance costs, classified as other assets amounted to $3,899 at March 31, 2007 and $4,169 at December 31, 2006.

     (i) Impairment of Long-Lived Assets

     In accordance with SFAS No. 144, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. Goodwill is tested annually for impairment, and is tested for impairment more frequently if events and circumstances indicate that the asset might be impaired. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value. This determination is made at the reporting unit level and consists of two steps. First, the Company determines the fair value of a reporting unit and compares it to its carrying amount. Second, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation, in accordance with FASB Statement No. 141, Business Combinations. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. The Company performed its annual test in the third quarters of 2006 with no indication of impairment.

     (j) Asset Retirement Obligation

     Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143”), an Asset Retirement Obligation (“ARO”) which consists of costs associated with legal obligations to retire tangible, long-lived assets is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143, clarifies that the recognition and measurement provisions of SFAS 143 apply to asset retirement obligations in which the timing or method of settlement may be conditional on a future event that may or may not be within the control of the entity. The Company’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment.

     The transportation equipment includes pipeline systems. The Company transports LPGs through the pipeline system and gathering system. The Company also gathers natural gas from wells owned by producers and delivers natural gas and NGLs on our pipeline systems, primarily in Texas and Louisiana to the fractionation facility of our 50% owned joint venture. The Company is obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, the Company is not able to reasonably determine the fair value of the asset retirement obligations for our trunk and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate. In order to determine a removal date of our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of natural gas, the Company is not a producer of the field reserves, and therefore does not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which the Company gathers natural gas. In the absence of such information, the Company is not able to make a reasonable estimate of when future dismantlement and removal dates of our gathering assets will occur. With regard to our trunk pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, the Company can evaluate its trunk pipelines for alternative uses, which can be and have been found. The Company will record such asset retirement obligations in

5

the period in which more information becomes available for the Company to reasonably estimate the settlement dates of the retirement obligations.

     (k) Derivative Instruments and Hedging Activities

     Derivative Instruments and Hedging Activities—SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established accounting and reporting standards for derivative instruments and hedging activities. It requires that all derivatives be included on the balance sheet as an asset or liability measured at fair value and that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If such hedge accounting criteria are met, the change is deferred in shareholders’ equity as a component of accumulated other comprehensive income. The deferred items are recognized in the period the derivative contract is settled.

     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 March 31, 2007 and December 31, 2006, the Company has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity.

     (l) Allowance for Doubtful Accounts

     Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable.

     (m) Unit Grants

     In January 2006, the Company issued 1,000 restricted units to each of its three independent, non-employee directors under its long-term incentive plan. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010. The Company accounts for the transaction under EITF Issue 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.”

     (n) Incentive Distribution Rights

     The General Partner holds a 2% general partner interest and certain incentive distribution rights in the Company. Incentive distribution rights represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved. The Company is required to distribute all of its available cash from operating surplus, as defined in the Company agreement. The target distribution levels entitle the general partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unit holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months ended March 31, 2007, the general partner received incentive distributions. Such distributions have been eliminated in the accompanying consolidated balance sheet.

     (o) Use of Estimates

     Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare their consolidated balance sheets in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

     (p) Environmental Liabilities

     The Company’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

6

     (q) Income Taxes

     The General Partner is a disregarded entity for federal income tax purposes. Its activity is included in the consolidated federal income tax return of MRMC; however, for financial reporting purposes, current federal income taxes are computed and recorded as if the General Partner filed a separate federal income tax return.

     Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax liabilities relating primarily to the timing of recognizing partnership earnings and insurance revenues totaled $436 and $407 at March 31, 2007 and December 31, 2006, respectively, and are included in other liabilities in the accompanying balance sheet.

     The operations of the Company are generally not subject to income taxes and as a result, the Company’s income is taxed directly to its owners.

     On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Company has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change and subsequent changes in deferred tax assets and liabilities are immaterial. At March 31, 2007, the Company has recorded a liability attributable to the Texas Margin tax of $135.

(3) IMPACT OF RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

     In September 2006, the FASB issued FAS 157, which will become effective for the Company on January 1, 2008. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the Partnership from the adoption of FAS 157 in 2008 will depend on the Partnership’s assets and liabilities at that time that are required to be measured at fair value.

     In September 2005, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. This pronouncement provides additional accounting guidance for situations involving inventory exchanges between parties to that contained in APB Opinion no. 29, Accounting for Nonmonetary Transactions and SFAS 153, Exchanges of Nonmonetary Assets. The standard is effective for new arrangements entered into in reporting periods beginning after March 15, 2006. The adoption did not have a material impact on the Company’s consolidated balance sheet.

     In May 2005, the FASB, as part of an effort to conform to international accounting standards, issued SFAS No. 154, “Accounting Changes and Error Corrections,” or SFAS No. 154, which was effective for the Partnership beginning on January 1, 2006. SFAS No. 154 requires that all voluntary changes in accounting principles be retrospectively applied to prior financial statements as if that principle had always been used, unless it is impracticable to do so. When it is impracticable to calculate the effects on all prior periods, SFAS No. 154 requires that the new principle be applied to the earliest period practicable. The adoption of SFAS No. 154 did not have a material effect on the Company’s consolidated balance sheet.

(4) ACQUISITIONS

     (a) Asphalt Terminals. In August 2006 and October 2006, respectively, the Company acquired the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (“Prime”), for $4,842 which was allocated to property, plant and equipment. The assets are located in Houston, Texas and Port Neches, Texas. The Company entered into an agreement with Martin Resource Management, which Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will assume all additional expenses to operate the facility.

7

     (b) Corpus Christi Barge Terminal. In July 2006, the Company acquired a marine terminal located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6,200 which was all allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land, and includes three tanks with a combined shell capacity of approximately 240,000 barrels, pump and piping infrastructure for truck unloading and product delivery to two oil docks, and there are several pumps, controls, and an office building on site for administrative use.

     (c) Marine Vessels. In November 2006, the Company acquired the La Force, an offshore tug, for $6,001 from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 with new engines installed in 2005.

     In January 2006, the Company acquired the Texan, an offshore tug, and the Ponciana, an offshore NGL barge, for $5,850 from Martin Resource Management. The acquisition price was based on a third-party appraisal. In March 2006, these vessels went into service under a long term charter with a third party. In February 2006, the Company acquired the M450, an offshore barge, for $1,551 from a third party. In March 2006, this vessel went into service under a one-year evergreen charter with an affiliate of MRMC.

(5) INVENTORIES

     Components of inventories at March 31, 2007 and December 31, 2006 were as follows:

	March 31,		December 31,
	2007		2006
	(Unaudited)		(Audited)
Liquefied petroleum gas	$	11,387	$	17,061
Sulfur		2,445		4,397
Fertilizer — raw materials and packaging		2,603		2,412
Fertilizer — finished goods		5,152		4,807
Lubricants		3,018		2,592
Other		1,564		1,750
	$	26,169	$	33,019

(6) PROPERTY, PLANT AND EQUIPMENT

     At March 31, 2007 and December 31, 2006 , property, plant, and equipment consisted of the following:

		March 31, 2007		December 31, 2006
	Depreciable Lives	(Unaudited)		(Audited)
Land	—	$	13,652	$	12,559
Improvements to land and buildings	10-39 years		29,520		26,868
Transportation equipment	3- 7 years		537		531
Storage equipment	5-20 years		23,151		22,343
Marine vessels	4-30 years		125,321		124,323
Operating equipment	3-30 years		103,990		103,929
Furniture, fixtures and other equipment	3-20 years		1,450		1,450
Construction in progress			42,110		31,964
		$	339,731	$	323,967

(7) GOODWILL AND OTHER INTANGIBLE ASSETS

     The following information relates to goodwill balances as of the periods presented:

8

	March 31,		December 31,
	2007		2006
	(Unaudited)		(Audited)
Carrying amount of goodwill:
Marine transportation	$	2,026	$	2,026
Natural gas/LPG services		20,225		20,225
Sulfur		4,533		4,533
Fertilizer		816		816
	$	27,600	$	27,600

     The following information relates to covenants not-to-compete as of the periods presented:

	March 31,		December 31,
	2007		2006
	(Unaudited)		(Audited)
Covenants not-to-compete:
Terminalling and storage	$	1,398	$	1,561
Natural gas/LPG services		600		600
Sulfur		100		100
Fertilizer		690		690
		2,839		2,951
Less accumulated amortization		1,025		877
	$	1,763	$	2,074

The covenants not-to-compete are in the consolidated balance sheets as other assets, net.

(8) RELATED PARTY TRANSACTIONS

     Amounts due to affiliates in the consolidated balance sheets as of March 31, 2007 (unaudited) and December 31, 2006, are primarily with MRMC and its affiliates and Waskom.

     The General Partner’s balances are primarily related to (1) Company cash distributions that were paid to a related party on behalf of the General Partner and (2) director fees that were paid by a related party on behalf of the General Partner. The Company contributions and distributions have been eliminated in the accompanying consolidated balance sheet.

     The Company’s balances are related to transactions involving the purchase and sale of LPG products, lube oil products, sulfur and sulfuric acid products, fertilizer products; land and marine transportation services; terminalling and storage services, and other purchases of products and services representing operating expenses.

(9) INVESTMENT IN UNCONSOLIDATED COMPANYS AND JOINT VENTURES

     The Company, through its subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), owns 50% ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). Each of these interests are accounted for under the equity method of accounting.

     On June 30, 2006, the Company, through its Prism Gas subsidiary, acquired a 20% ownership interest in a Company for approximately $196, which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). BCP is an approximate 67 mile pipeline located in the Barnett Shale extension. The pipeline traverses four counties with the most concentrated drilling occurring in Bosque County. BCP is operated by Panther Pipeline Ltd. who is the 42.5% interest owner. This interest is accounted for under the equity method of accounting.

     In accounting for the acquisition of the interests in Waskom, Matagorda and 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 for the three months ended March 31, 2007 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 $11,131 and $11,279 at March 31, 2007 and December 31, 2006. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually.

9

     Certain financial information related to the Company’s investments in the unconsolidated equity method investees as of March 31, 2007 and December 31, 2006 is shown below:

	Investments
	As of		As of
	March 31, 2007		December 31, 2006
	(Unaudited)		(Audited)
Waskom	$	67,569	$	64,937
Matagorda		3,853		3,786
PIPE		1,807		1,718
BCP		177		210
	$	73,406	$	70,651

	As of		As of
	March 31,		December 31,
	2007		2006
Waskom	(Unaudited)		(Audited)
Total assets	$	58,977	$	53,260
Partners’ capital		50,989		45,450

(10) LONG-TERM DEBT

     At March 31, 2007 and December 31, 2006, long-term debt consisted of the following:

	March 31,		December 31,
	2007		2006
**$120,000 Revolving loan facility at variable interest rate (7.50%* weighted average at March 31, 2007), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries	$	60,000	$	44,000
***$130,000 Term loan facility at variable interest rate (7.69%* at March 31, 2007), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries		130,000		130,000
Other secured debt maturing in 2008, 7.25%		76		95
Total long-term debt		190,076		174,095
Less current installments		75		74
Long-term debt, net of current installments	$	190,001	$	174,021

*

Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.50%. Effective April 1, 2007, the applicable margin for existing borrowings decreased to 2.00%. We incur a commitment fee on the unused portions of the credit facility.

**

Effective December 13, 2006, the Company entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 4.82% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in December 2009.

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*** The $130,000 term loan has $105,000 hedged. Effective April 13, 2006, the Company entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in November 2010. Effective March 28, 2007, the Company entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This cash flow hedge matures in March 2010.

     On August 18, 2006, the Company purchased certain terminalling assets and assumed associated long term debt of $113 with a fixed rate cost of 7.25%.

     On November 10, 2005, the Company entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general Company purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of March 31, 2007, we had $60,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of March 31, 2007, we had $59,900 available under our revolving credit facility.

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

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

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

     The credit facility also contains covenants, which, among other things, require the Company to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (x) 5.5 to 1.0 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter thereafter. The Company was in compliance with the debt covenants contained in credit facility for the year ended December 31, 2006 and as of March 31, 2007.

     On November 10 of each year, commencing with November 10, 2006, the Company must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made under the term loan through March 31, 2007. If the Company receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Company must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Company must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

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     Draws made under the Company’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Company’s credit facility have ranged from a low of $170,600 to a high of $198,100. As of March 31, 2007, the Company had $59,900 available for working capital, internal expansion and acquisition activities under the Company’s credit facility.

     In connection with the Company’s Woodlawn acquisition on May 2, 2007, the Company borrowed approximately $33 million under its revolving credit facility ( see note 15).

(11) FINANCIAL INSTRUMENTS

     Statement of Financial Accounting Standards No. 107, Disclosures about Fair Value of Financial Instruments, requires that the Company disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for the Company’s financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

Accounts and other receivables, trade and other accounts payable, other accrued liabilities, and due from/to affiliates — The carrying amounts approximate fair value because of the short maturity of these instruments.

Long-term debt including current installments — The carrying amount of the revolving and term loan facilities approximates fair value due to the debt having a variable interest rate.

(12) INTEREST RATE CASH FLOW HEDGES

     In April 2006, the Company entered into a cash flow hedge agreement with a notional amount of $75,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate term loan credit facility. This interest rate swap matures in November 2010. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 5.25% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.

     In December 2006, the Company entered into a cash flow hedge agreement with a notional amount of $40,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facility. This interest rate swap matures in December 2009. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 4.82% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.

     In December 2006, the Company entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006; therefore, hedge accounting was not utilized. The swap has been recorded at fair value at March 31, 2007 with an offset to current operations.

     The total fair value of the interest rate swaps agreement was a liability of approximately $693 at March 31, 2007.

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

	March 31,			December 31,
	2007			2006
Fair value of derivative assets — current	$	117		$	377
Fair value of derivative assets — long term		—			112
Fair value of derivative liabilities — current		—			—
Fair value of derivative liabilities — long term		(810	)		(572	)
Net fair value of derivatives	$	(693	)	$	(83	)

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(13) COMMODITY CASH FLOW HEDGES

     The Company is exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, the Company has not engaged in commodity contract trading or hedging activities. However, in connection with the acquisition of Prism Gas, the Company has established a hedging policy and monitors and manages the commodity market risk associated with the commodity risk exposure of the Prism Gas acquisition. In addition, the Company is focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

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

     In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. During the three months ended March 31, 2007, certain of the Company’s derivative instruments which were designated as hedges became ineffective due to fluctuations in the basis difference between the hedged item and the hedging instrument. As a result, these hedges are now marked to market through the statement of operations for the three months ended March 31, 2007.

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

	March 31,			December 31,
	2007			2006
Fair value of derivative assets — current	$	318		$	882
Fair value of derivative assets — long term		—			221
Fair value of derivative liabilities — current		(186	)		—
Fair value of derivative liabilities — long term		(196	)		(74	)
Net fair value of derivatives	$	(64	)	$	1,029

     Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2007 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of March 31, 2007, the remaining term of the contracts extend no later than December 2009, with no single contract longer than one year. The Company’s counterparties to the derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank.

	March 31, 2007
	Total
Transaction	Volume		Remaining Terms
Type	Per Month	Pricing Terms	of Contracts	Fair Value
Mark to Market Derivatives::
Ethane Swap	8,000 BBL	Fixed price of $28.04 settled against Mt. Belvieu Purity Ethane average monthly postings	April 2007 to December 2007		4
Crude Oil swap	5,000 BBL	Fixed price of $65.95 settled against WTI NYMEX average monthly closings	April 2007 to December 2007		129
Natural Gas swap and Natural Gas basis swap	20,000 MMBTU	Combined fixed price of $8.54 settled against “Inside FERC” Centerpoint Energy Gas Transmission Co.	April 2007 to December 2007		185

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	March 31, 2007
	Total
Transaction	Volume		Remaining Terms
Type	Per Month	Pricing Terms	of Contracts	Fair Value
Crude Oil Swap	3,000 BBL	Fixed price of $69.08 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(13	)
Natural Gas swap	30,000 MMBTU	Fixed price of $8.12 settled against “Inside FERC” Houston Ship Channel first of the month	January 2008 to December 2008		(145	)
Total swaps not designated as cash flow hedges				$	160
Cash Flow Hedges:
Crude Oil Swap	5,000 BBL	Fixed price of $66.20 settled against WTI NYMEX average monthly closings	January 2008 to December 2008		(224	)
Total swaps designated as cash flow hedges				$	(224	)
Total net fair value of derivatives				$	(64	)

     Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2006 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of December 31, 2006, the remaining term of the contracts extend no later than December 2009, with no single contract longer than one year. The Company’s counterparties to the derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank.

	December 31, 2006
	Total
	Volume		Remaining Terms
Transaction Type	Per Month	Pricing Terms	of Contracts	Fair Value
Mark to Market Derivatives::
Crude Oil swap	5,000 BBL	Fixed price of $65.95 settled against WTI NYMEX average monthly closings	May 2007 to December 2007		103
Natural Gas swap and Natural Gas basis swap	20,000 MMBTU	Combined fixed price of $8.54 settled against IF Centerpoint Energy Gas Transmission Co.	May 2007 to December 2007		556
Total swaps not designated as cash flow hedges				$	659
Cash Flow Hedges:
Ethane Swap	8,000 BBL	Fixed price of $28.04 settled against Mt. Belvieu Purity Ethane average monthly postings	May 2007 to December 2007		223
Crude Oil Swap	5,000 BBL	Fixed price of $66.20 settled against WTI NYMEX average monthly closings	May 2008 to December 2008		(74	)
Natural Gas swap	30,000 MMBTU	Fixed price of $8.12 settled against IF Houston Ship Channel first of the month	May 2008 to December 2008		155
Crude Oil Swap	3,000 BBL	Fixed price of $69.08 settled against WTI NYMEX average monthly closings	May 2009 to December 2009		66
Total swaps designated as cash flow hedges				$	370
Total net fair value of derivatives				$	1,029

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     On all transactions where the Company is exposed to counterparty risk, the Company analyzes the counterparty’s financial condition prior to entering into an agreement, and has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis.

     As a result of the Prism Gas acquisition, the Company is exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales activities. Prism Gas gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (POL) and percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 2009 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas and ethane.

     Based on estimated volumes, as of March 31, 2007, Prism Gas had hedged approximately 55%, 46%, and 14% of its commodity risk by volume for 2007, 2008, and 2009, respectively. The Company anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Company will be able to do so or that the terms thereof will be similar to the Company’s existing hedging arrangements. In addition, the Company will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil.

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

(14) COMMITMENTS AND CONTINGENCIES

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

(15) SUBSEQUENT EVENT

     On May 2, 2007, the Company acquired the outstanding stock of Woodlawn Pipeline Company, Inc. (“Woodlawn”), a natural gas gathering and processing company with integrated gathering and processing assets in East Texas for $30,638. In addition, the Company purchased a compressor for $400 from an affiliate of the selling parties. In conjunction with this transaction, the Company also acquired a pipeline that delivers residue gas from the Woodlawn gas processing plant to the Texas Eastern Transmission pipeline system for $2,139.

15