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, 2009

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o            No o

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

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

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

Yes o           No þ

          The number of the registrant’s Common Units outstanding at May 6, 2009 was 13,688,152. The number of the registrant’s subordinated units outstanding at May 6, 2009 was 850,674.

 

 

		Page
PART I — FINANCIAL INFORMATION			2
Item 1. Financial Statements			2
Consolidated and Condensed Balance Sheets as of March 31, 2009 (unaudited) and December 31, 2008 (audited)			2
Consolidated and Condensed Statements of Operations for the Three Months Ended March 31, 2009 and 2008 (unaudited)			3
Consolidated and Condensed Statements of Capital for the Three Months Ended March 31, 2009 and 2008 (unaudited)			4
Consolidated and Condensed Statements of Comprehensive Income for the Three Months Ended March 31, 2009 and 2008 (unaudited)			5
Consolidated and Condensed Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008 (unaudited)			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 3. Quantitative and Qualitative Disclosures about Market Risk			44
Item 4. Controls and Procedures			45
PART II. OTHER INFORMATION			46
Item 1. Legal Proceedings			46
Item 1A. Risk Factors			46
Item 5. Other Information			46
Item 6. Exhibits			47
SIGNATURE
CERTIFICATIONS
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

		March 31,				December 31,
		2009				2008
		(Unaudited)				(Audited)
Assets
Cash		$	7,965			$	7,983
Accounts and other receivables, less allowance for doubtful accounts of $599 and $481			66,732				68,117
Product exchange receivables			5,808				6,924
Inventories			32,494				42,461
Due from affiliates			1,903				555
Fair value of derivatives			3,793				3,623
Other current assets			1,060				1,079
Total current assets			119,755				130,742
Property, plant, and equipment, at cost			550,213				537,381
Accumulated depreciation			(133,396	)			(125,256	)
Property, plant and equipment, net			416,817				412,125
Goodwill			37,405				37,405
Investment in unconsolidated entities			79,089				79,843
Fair value of derivatives			1,171				1,469
Other assets, net			6,832				7,332
		$	661,069			$	668,916
Liabilities and Capital
Trade and other accounts payable		$	70,323			$	87,382
Product exchange payables			8,283				10,924
Due to affiliates			27,641				13,420
Income taxes payable			278				414
Fair value of derivatives			7,975				6,478
Other accrued liabilities			3,238				6,077
Total current liabilities			117,738				124,695
Long-term debt			301,700				295,000
Deferred income taxes			8,443				8,538
Fair value of derivatives			2,937				4,302
Other long-term obligations			1,642				1,667
Total liabilities			432,460				434,202
Partners’ capital			232,672				239,649
Accumulated other comprehensive loss			(4,063	)			(4,935	)
Total partners’ capital			228,609				234,714
Commitments and contingencies		$	661,069			$	668,916

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Three Months Ended
		March 31,
		2009				2008
Revenues:
Terminalling and storage		$	9,599			$	7,920
Marine transportation			16,336				16,403
Product sales:
Natural gas services			90,866				207,092
Sulfur services			26,586				70,225
Terminalling and storage			13,519				11,376
			130,971				288,693
Total revenues			156,906				313,016
Costs and expenses:
Cost of products sold:
Natural gas services			82,667				202,850
Sulfur services			18,435				56,340
Terminalling and storage			12,105				9,921
			113,207				269,111
Expenses:
Operating expenses			23,888				24,217
Selling, general and administrative			4,179				3,479
Depreciation and amortization			8,405				7,340
Total costs and expenses			149,679				304,147
Other operating income			—				139
Operating income			7,227				9,008
Other income (expense):
Equity in earnings of unconsolidated entities			2,059				3,510
Interest expense			(4,669	)			(4,743	)
Other, net			23				181
Total other expense			(2,587	)			(1,052	)
Net income before taxes			4,640				7,956
Income tax benefit			230				61
Net income		$	4,870			$	8,017
General partner’s interest in net income		$	807			$	651
Limited partners’ interest in net income		$	4,063			$	7,366
Net income per limited partner unit — basic and diluted		$	0.28			$	0.51
Weighted average limited partner units — basic			14,532,826				14,532,826
Weighted average limited partner units — diluted			14,537,094				14,535,491

          See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Partners’ Capital
																						Accumulated
																						Other
																		General				Comprehensive
		Common								Subordinated								Partner				Income (Loss)
		Units				Amount				Units				Amount				Amount				Amount				Total
Balances — January 1, 2008			12,837,480			$	244,520				1,701,346			$	(6,022	)		$	4,112			$	(6,762	)		$	235,848
Net income			—				6,141				—				1,225				651				—				8,017
Cash distributions			—				(8,986	)			—				(1,191	)			(719	)			—				(10,896	)
Unit-based compensation			—				17				—				—				—				—				17
Adjustment in fair value of derivatives			—				—				—				—				—				(4,992	)			(4,992	)
Balances — March 31, 2008			12,837,480			$	241,692				1,701,346			$	(5,988	)		$	4,044			$	(11,754	)		$	227,994
Balances — January 1, 2009			13,688,152			$	239,333				850,674			$	(3,688	)		$	4,004			$	(4,935	)		$	234,714
Net income			—				3,826				—				237				807				—				4,870
Cash distributions			—				(10,266	)			—				(638	)			(962	)			—				(11,866	)
Unit-based compensation			—				19				—				—				—				—				19
Adjustment in fair value of derivatives			—				—				—				—				—				872				872
Balances — March 31, 2009			13,688,152			$	232,912				850,674			$	(4,089	)		$	3,849			$	(4,063	)		$	228,609

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Three Months Ended
		March 31,
		2009				2008
Net income		$	4,870			$	8,017
Changes in fair values of commodity cash flow hedges			419				213
Commodity cash flow hedging losses reclassified to earnings			(697	)			(665	)
Changes in fair value of interest rate cash flow hedges			(623	)			(4,540	)
Interest rate cash flow hedging gains reclassified to earnings			1,773				—
Comprehensive income		$	5,742			$	3,025

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Three Months Ended
		March 31,
		2009				2008
Cash flows from operating activities:
Net income		$	4,870			$	8,017
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			8,405				7,340
Amortization of deferred debt issuance costs			281				279
Deferred taxes			(95	)			(80	)
Gain on disposition or sale of property, plant and equipment			—				(140	)
Equity in earnings of unconsolidated entities			(2,059	)			(3,510	)
Distributions from unconsolidated entities			650				—
Distributions in-kind from equity investments			1,303				2,580
Non-cash derivatives loss			1,132				1,888
Other			19				17
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables			1,385				(8,454	)
Product exchange receivables			1,116				668
Inventories			9,967				747
Due from affiliates			(1,348	)			(1,583	)
Other current assets			19				(1,159	)
Trade and other accounts payable			(17,059	)			19,329
Product exchange payables			(2,641	)			(2,679	)
Due to affiliates			14,221				(506	)
Income taxes payable			(136	)			(15	)
Other accrued liabilities			(2,839	)			(809	)
Change in other non-current assets and liabilities			(39	)			14
Net cash provided by operating activities			17,152				21,944
Cash flows from investing activities:
Payments for property, plant and equipment			(12,864	)			(33,600	)
Acquisitions, net of cash acquired			—				(5,983	)
Proceeds from sale of property, plant and equipment			—				404
Return of investments from unconsolidated entities			220				450
Distributions from unconsolidated entities for operations			640				506
Net cash used in investing activities			(12,004	)			(38,223	)
Cash flows from financing activities:
Payments of long-term debt			(28,400	)			(58,120	)
Proceeds from long-term debt			35,100				88,100
Cash distributions paid			(11,866	)			(10,896	)
Net cash provided by (used in) financing activities			(5,166	)			19,084
Net increase (decrease) in cash			(18	)			2,805
Cash at beginning of period			7,983				4,113
Cash at end of period		$	7,965			$	6,918

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

(1) General

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

          The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and U.S. generally accepted accounting principles for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by generally accepted accounting principles for annual audited financial statements of the type contained in the Partnership’s annual reports on Form 10-K. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for such interim periods are not necessarily indicative of the results of operations for the full year. These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission (the “SEC”) on March 4, 2009.

          (a) Use of Estimates

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

          (b) Unit Grants

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

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

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

          The Partnership accounts for the transactions under Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based payment transactions was $19 and $17 for the three months ended March 31, 2009 and 2008, respectively. The Partnership’s general partner contributed cash of $2 in January 2006 and $3 in May 2007 to the Partnership in conjunction with the issuance of those restricted units in order to maintain its 2% general partner interest in the Partnership. The Partnership’s general partner did not make a contribution attributable to the restricted units issued to its three independent, non-employee directors in May 2008, as such units were purchased in the open market by the Partnership for $93.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

          (c) Incentive Distribution Rights

          The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights (“IDRs”) in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the partnership agreement, and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once 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 2% of quarterly cash distributions up to $0.55 per unit, 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, 2009 and 2008 the general partner received $724 and $501, respectively, in incentive distributions.

          (d) Net Income per Unit

          In March 2008, the Emerging Issues Task Force (“EITF”) of the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”). EITF 07-4 addresses the application of the two-class method under SFAS No. 128 “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. To the extent the partnership agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the partnership agreement. EITF 07-4 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.

          The Partnerhsip adopted EITF 07-04 on January 1, 2009. Adoption did not impact the Partnership’s computation of earnings per limited partner unit as cash distributions exceeded earnings for the three months ended March 31, 2009 and 2008, and the IDRs do not share in losses under our partnership agreement. In the event the Partnership’s earnings exceed cash distributions, EITF 07-04 will have an impact on the computation of the Partnership’s earnings per limited partner unit. Our Partnership agreement does not explicitly limit distributions to the general partner; therefore, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the Partnership agreement. For the three months ended March 31, 2009 and 2008, the general partner’s interest in net income, including the IDRs, represents distributions declared after period end on behalf of the general partner interest and IDRs less the allocated excess of distributions over earnings for the periods.

          The following table reconciles net income to limited partners’ interest in net income:

		Three Months Ended
		March 31
		2009				2008
Net income		$	4,870			$	8,017
Less:
Distributions payable on behalf of IDRs			(724	)			(501	)
Distributions payable on behalf of general partner interest			(237	)			(218	)
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest			154				68
Limited partners’ interest in net income		$	4,063			$	7,366

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

          The weighted average units outstanding for basic net income per unit were 14,532,826 for both the three months ended March 31, 2009 and 2008. For diluted net income per unit, the weighted average units outstanding were increased by 4,268 and 2,665 for the three months ended March 31, 2009 and 2008, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

          (e) Income taxes

          With respect to our taxable subsidiary (Woodlawn Pipeline Co., Inc.), income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted 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.

(2) New Accounting Pronouncements

          In March 2008, the EITF issued EITF 07-4. EITF 07-4 addresses the application of the two-class method under SFAS No. 128 “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions. EITF 07-4 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We adopted EITF 07-04 on January 1, 2009. See Note 1 (d) for more information.

          In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133” (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and was effective for the Partnership on January 1, 2009. Since SFAS No. 161 requires enhanced disclosures concerning derivatives and hedging activities (see Note 7 for disclosures related to the adoption of SFAS 161), the adoption of SFAS 161 effective January 1, 2009 did not affect the consolidated financial position, results of operations or cash flows of the Partnership.

          In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 establishes new accounting, disclosure and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 was effective for the Partnership on January 1, 2009. The adoption of SFAS No. 160 had no impact on the Partnership’s consolidated financial statements. However, it could impact accounting for future transactions.

          In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) retains the underlying concepts of SFAS No. 141 in that all business combinations are still required to be accounted for at fair value under the acquisition method of accounting, but SFAS No. 141(R) establishes revised principles and requirements for how entities will recognize and measure assets and liabilities acquired in a business combination, including but not limited to, generally expensing of acquisition costs as incurred and valuing noncontrolling interests (minority interests) at fair value at the acquisition date. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. SFAS No. 141(R) will impact all acquisitions closed on or after January 1, 2009.

          In April 2009, the FASB issued FASB Staff Position (“FSP”) FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP FAS 141(R)-1”). This pronouncement amends FAS No. 141-R to clarify the initial and subsequent

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

recognition, subsequent accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP SFAS No. 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value, as determined in accordance with SFAS No. 157, if the acquisition-date fair value can be reasonably estimated. If the acquisition-date fair value of an asset or liability cannot be reasonably estimated, the asset or liability would be measured at the amount that would be recognized in accordance with FASB Statement No. 5, “Accounting for Contingencies” (“SFAS No. 5”), and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss.” FSP FAS No. 141(R)-1 became effective for the Partnership as of January 1, 2009. As the provisions of FSP FAS 141(R)-1 are applied prospectively to business combinations with an acquisition date on or after the guidance became effective, the impact to the Partnership cannot be determined until the transactions occur. No such transactions occurred during the first quarter of 2009.

          In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. We adopted SFAS 157 as of January 1, 2008, with the exception of the application of the statement to non-recurring nonfinancial assets and nonfinancial liabilities, which was delayed to fiscal years beginning after November 15, 2008, which we therefore adopted as of January 1, 2009. As of March 31, 2009, we do not have any significant non-recurring measurements of nonfinancial assets and nonfinancial liabilities. See Note 3 — Fair Value Measurements for further information.

          Accounting Standards Not Yet Adopted. In April 2009, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS 157-4, Determining Fair Value when the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions that are not Orderly (“FSP FAS 157-4”), which is effective for the Partnership for the quarterly period beginning April 1, 2009. FSP FAS 157-4 affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date under current market conditions. The FSP provides guidance for estimating fair value when the volume and level of market activity for an asset or liability have significantly decreased and determining whether a transaction was orderly. This FSP applies to all fair value measurements when appropriate. The Partnership does not expect that the adoption of this statement will have a significant impact on its financial statements.

          In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1”), which is effective for the Partnership for the quarterly period beginning April 1, 2009. FSP FAS 107-1 requires an entity to provide the annual disclosures required by FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, in its interim consolidated financial statements. The Partnership will provide the additional disclosures required by FSP FAS 107-1 in its quarterly report on Form 10-Q for the period ended June 30, 2009.

(3) Fair Value Measurements

          During the first quarter of 2008, the Partnership adopted SFAS 157. SFAS 157 established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of SFAS 157 had no impact on the Partnership’s financial position or results of operations.

          SFAS 157 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. SFAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value into one of the following categories:

Level 1: Quoted market prices in active markets for identical assets or liabilities.
Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

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

          The Partnership’s derivative instruments which consist of commodity and interest rate swaps are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets, which is considered Level 2. Refer to Notes 7, 8 and 9 for further information on the Partnership’s derivative instruments and hedging activities.

          The following items are measured at fair value on a recurring basis subject to the disclosure requirements of SFAS 157 at March 31, 2009:

						Fair Value Measurements at Reporting Date
						Using
						Quoted Prices in				Significant
						Active Markets				Other				Significant
						for				Observable				Unobservable
						Identical Assets				Inputs				Inputs
		March 31,
Description		2009				(Level 1)				(Level 2)				(Level 3)
Assets
Interest rate derivatives		$	415			$	—			$	415			$	—
Commodity derivatives			4,549				—				4,549				—
Total assets		$	4,964			$	—			$	4,964			$	—
Liabilities
Interest rate derivatives		$	(10,912	)		$	—			$	(10,912	)		$	—

          The following items are measured at fair value on a recurring basis subject to the disclosure requirements of SFAS 157 at December 31, 2008:

						Fair Value Measurements at Reporting Date
						Using
						Quoted Prices in				Significant
						Active Markets				Other				Significant
						for				Observable				Unobservable
						Identical Assets				Inputs				Inputs
		December 31,
Description		2008				(Level 1)				(Level 2)				(Level 3)
Assets
Commodity derivatives		$	5,092			$	—			$	5,092			$	—
Liabilities
Interest rate derivatives		$	(10,780	)		$	—			$	(10,780	)		$	—

(4) Acquisitions

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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

(5) Inventories

          Components of inventories at March 31, 2009 and December 31, 2008 were as follows:

		2009				2008
Natural gas liquids		$	6,295			$	10,530
Sulfur			1,342				6,522
Sulfur based products			12,431				14,879
Lubricants			9,595				8,110
Other			2,831				2,420
		$	32,494			$	42,461

(6) Investments in Unconsolidated Partnerships and Joint Ventures

          The Partnership’s Prism Gas Systems I, L.P. (“Prism Gas”) subsidiary owns an unconsolidated 50% interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), and the Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these assets are accounted for by the equity method.

          On June 30, 2006, the Partnership’s Prism Gas subsidiary, acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). The lease contract provides for termination in June 2009 and an extension of the lease is not currently contemplated. This interest is accounted for by 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 $149 and $148 for the three months ended March 31, 2009 and 2008, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $9,943 and $10,092 at March 31, 2009 and December 31, 2008, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually or if changes in circumstance indicate that a potential impairment exists. No impairment was recognized for the three months ended March 31, 2009 or 2008.

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

          Activity related to these investment accounts for the three months ended March 31, 2009 and 2008 is as follows:

		Waskom				PIPE				Matagorda				BCP				Total
Investment in unconsolidated entities, December 31, 2008		$	74,978			$	1,214			$	3,559			$	92			$	79,843
Distributions in kind			(1,303	)			—				—				—				(1,303	)
Distributions from unconsolidated entities			(650	)															(650	)
Contributions to (distributions from) unconsolidated entities:
Cash contributions			—				90				—				—				90
Contributions to (distributions from) unconsolidated entities for operations			(730	)			—				—				—				(730	)
Return of investments			—				(25	)			(195	)			—				(220	)
Equity in earnings:
Equity in earnings (losses) from operations			1,969				161				120				(42	)			2,208
Amortization of excess investment			(138	)			(4	)			(7	)			—				(149	)
Investment in unconsolidated entities, March 31, 2009		$	74,126			$	1,436			$	3,477			$	50			$	79,089

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

		Waskom				PIPE				Matagorda				BCP				Total
Investment in unconsolidated entities, December 31, 2007		$	70,237			$	1,582			$	3,693			$	178			$	75,690
Distributions in kind			(2,580	)			—				—				—				(2,580	)
Contributions to (distributions from) unconsolidated entities for operations			(506	)			—				—				—				(506	)
Return of investments			(300	)			(105	)			(45	)			—				(450	)
Equity in earnings:
Equity in earnings from operations			3,640				12				47				(41	)			3,658
Amortization of excess investment			(137	)			(4	)			(7	)			—				(148	)
Investment in unconsolidated entities, March 31, 2008		$	70,354			$	1,485			$	3,688			$	137			$	75,664

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

										Three Months Ended
		As of March 31								March 31
						Partner’s								Net
		Total Assets				Capital				Revenues				Income
2009
Waskom		$	75,857			$	66,301			$	15,430			$	3,939

		As of December 31
2008
Waskom		$	67,666			$	57,658			$	26,733			$	7,280

          As of March 31, 2009 and December 31, 2008, the Partnership’s interest in cash of the unconsolidated equity method investees was $1,267 and $1,956, respectively.

(7) Risk Management and Financial Instruments

          In March 2008, the FASB issued SFAS 161 which changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 is effective for fiscal years and interim periods. The Partnership adopted SFAS 161 on January 1, 2009.

          Derivative Financial Instruments

          The Partnership’s results of operations are materially impacted by changes in crude oil, natural gas and natural gas liquids prices and interest rates. In an effort to manage our exposure to these risks, we periodically enter into various derivative instruments, including commodity and interest rate hedges. In accordance with SFAS 133, we are required to recognize all derivative instruments as either assets or liabilities at fair value on our Consolidated Balance Sheets and to recognize certain changes in the fair value of derivative instruments on our Consolidated Statements of Operations.

          The Partnership performs, at least quarterly, both a prospective and retrospective assessment of the effectiveness of our hedge contracts, including assessing the possibility of counterparty default. If we determine that a derivative is no longer expected to be highly effective, we discontinue hedge accounting prospectively and recognize subsequent changes in the fair value of the hedge in earnings. As a result of our effectiveness assessment at March 31, 2009, we believe our hedge contracts will continue to be effective in offsetting changes in cash flow or fair value attributable to the hedged risk.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

          Cash flow hedges

          For derivative instruments that are designated and qualify as cash flow hedges under SFAS 133, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income and reclassified into earnings in the same period during which the hedged transaction affects earnings. The effective portion of the derivative represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. To the extent the change in the fair value of the hedge does not perfectly offset the change in the fair value of the hedged item, the ineffective portion of the hedge is immediately recognized in earnings.

          The following table summarizes the fair values and classification of our derivative instruments in our Condensed and Consolidated Balance Sheet:

Fair Values of Derivative Instruments in the Consolidated Balance Sheet

		Derivative Assets										Derivative Liabilities
				Fair Values										Fair Values
				March 31,				December 31,						March 31,				December 31,
		Balance Sheet Location		2009				2008				Balance Sheet Location		2009				2008
Derivatives designated as hedging instruments under Statement 133:
		Current:										Current:
Interest rate contracts		Fair value of derivatives		$	—			$	—			Fair value of derivatives		$	1,945			$	5,427
Commodity contracts		Fair value of derivatives			2,343				2,430			Fair value of derivatives			—				—
					2,343				2,430						1,945				5,427
		Non-current:										Non-current:
Interest rate contracts		Fair value of derivatives			2				—			Fair value of derivatives			457				4,050
Commodity contracts		Fair value of derivatives			494				716			Fair value of derivatives			—				—
					496				716						457				4,050
Total derivatives designated as hedging instruments under Statement 133				$	2,839			$	3,146					$	2,402			$	9,477
Derivatives not designated as hedging instruments under Statement 133:
		Current:										Current:
Interest rate contracts		Fair value of derivatives		$	346			$	—			Fair value of derivatives		$	6.030			$	1,051
Commodity contracts		Fair value of derivatives			1,104				1,193			Fair value of derivatives			—				—
					1,450				1,193						6,030				1,051
		Non-current:										Non-current:
Interest rate contracts		Fair value of derivatives			67				—			Fair value of derivatives			2,480				252
Commodity contracts		Fair value of derivatives			608				753			Fair value of derivatives			—				—
					675				753						2,480				252
Total derivatives not designated as hedging instruments under Statement 133				$	2,125			$	1,946					$	8,510			$	1,303

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Three Months Ended March 31, 2009 and 2008

																				Ineffective Portion and Amount
		Effective Portion																		Excluded from Effectiveness Testing
																				Location of
																				Gain or
										Location of Gain										(Loss)
										or (Loss)		Amount of Gain or								Recognized		Amount of Gain or
		Amount of Gain or								Reclassified from		(Loss) Reclassified								in Income		(Loss) Recognized in
		(Loss) Recognized in								Accumulated		from Accumulated								on		Income on
		OCI on Derivatives								OCI into Income		OCI into Income								Derivatives		Derivatives
		2009				2008						2009				2008						2009				2008
Derivatives designated as hedging instruments under Statement 133
Interest rate contracts		$	(623	)		$	(4,540	)		Interest Expense		$	(1,773	)		$	—			Interest Expense		$	—			$	—
Commodity contracts			419				213			Natural Gas Revenues			718				544			Natural Gas Revenues			(21	)			121
Total derivatives designated as hedging instruments under Statement 133		$	(204	)		$	(4,327	)				$	(1,055	)		$	544					$	(21	)		$	121

				Amount of Gain or
		Location of Gain or (Loss)		(Loss) Recognized in
		Recognized in Income on		Income on
		Derivatives		Derivatives
				2009				2008
Derivatives not designated as hedging instruments under Statement 133
Interest rate contracts		Interest Expense		$	(150	)		$	(773	)
Commodity contracts		Natural Gas Services Revenues			250				(2,725	)
Total derivatives not designated as hedging instruments under Statement 133				$	100			$	(3,458	)

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

          Amounts expected to be reclassified into earnings for the subsequent twelve month period are losses of $8,365 for interest rate cash flow hedges and gains of $2,375 for commodity cash flow hedges. See notes 8 and 9 for further discussion of the Partnership’s commodity and interest rate hedging activities.

(8) Commodity Cash Flow Hedges

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

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

          In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings. The Partnership is exposed to the risk that periodic changes in the fair value of derivatives qualifying for hedge accounting will not be effective, as defined, or that derivatives will no longer qualify for hedge accounting. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is recorded to earnings. Likewise, if a hedge ceases to qualify for hedge accounting, any change in the fair value of derivative instruments since the last period is recorded to earnings; however, in accordance with SFAS No. 133, any amounts previously recorded to AOCI would remain there until such time as the original forecasted transaction occurs, then would be reclassified to earnings or if it is determined that continued reporting of losses in AOCI would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods, then the losses would be immediately reclassified to earnings. The Partnership did not have any such situations occur for the three months ended March 31, 2009 and 2008.

          Due to the volatility in commodity markets, the Partnership is unable to predict the amount of ineffectiveness each period, including the loss of hedge accounting, which is determined on a derivative by derivative basis. This may result, and has resulted in increased volatility in the Partnership’s financial results. Factors that have and may continue to lead to ineffectiveness and unrealized gains and losses on derivative contracts include: the substantial fluctuation in energy prices, the number of derivatives the Partnership holds, and significant weather events that have affected energy production. The number of instances in which the Partnership has discontinued hedge accounting for specific hedges is primarily due to those reasons. However, even though these derivatives may not qualify for hedge accounting under SFAS No. 133, the Partnership continues to hold the instruments as it believes they continue to afford the Partnership opportunities to manage commodity risk exposure.

          As of March 31, 2009 and 2008, the Partnership has both derivative instruments qualifying for hedge accounting under SFAS No. 133 with fair value changes being recorded in AOCI as a component of partners’ capital and derivative instruments not designated as hedges being marked to market with all market value adjustments being recorded in earnings.

          Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2009 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of March 31, 2009, the remaining term of the contracts extend no later than December 2010, with no single contract longer than one year. For the three months ended March 31, 2009, changes in the fair value of the Partnership’s derivative contracts were recorded in

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

both earnings and in AOCI as a component of partners’ capital.

March 31, 2009
		Total
		Volume				Remaining Terms
Transaction Type		Per Month		Pricing Terms		of Contracts		Fair Value
Mark to Market Derivatives::
Crude Oil Swap		3,000 BBL		Fixed price of $69.08 settled against WTI NYMEX average monthly closings		April 2009 to December 2009		$	405
Crude Oil Swap		3,000 BBL		Fixed price of $70.90 settled against WTI NYMEX average monthly closings		April 2009 to December 2009			453
Crude Oil Swap		3,000 BBL		Fixed price of $72.25 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			356
Crude Oil Swap		1,000 BBL		Fixed price of $104.80 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			498
Total swaps not designated as cash flow hedges								$	1,712
Cash Flow Hedges:
Natural Gas swap		30,000 MMBTU		Fixed price of $9.025 settled against Inside Ferc Columbia Gulf daily average		April 2009 to December 2009		$	1,274
Crude Oil Swap		1,000 BBL		Fixed price of $70.45 settled against WTI NYMEX average monthly closings		April 2009 to December 2009			147
Natural Gasoline Swap		2,000 BBL		Fixed price of $86.42 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.		April 2009 to December 2009			729
Crude Oil Swap		2,000 BBL		Fixed price of $69.15 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			166
Natural Gasoline Swap		1,000 BBL		Fixed price of $94.14 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings		January 2010 to December 2010			521
Total swaps designated as cash flow hedges								$	2,837
Total net fair value of commodity derivatives								$	4,549

          The Partnership’s credit exposure related to commodity cash flow hedges is represented by the positive fair value of contracts to the Partnership at March 31, 2009. These outstanding contracts expose the Partnership to credit loss in the event of nonperformance by the counterparties to the agreements. The Partnership has incurred no losses associated with counterparty nonperformance on derivative contracts.

          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 agreements with three counterparties containing collateral provisions. Based on those current agreements, cash deposits are required to be posted whenever the net fair value of derivatives associated with the individual counterparty exceed a specific threshold. If this threshold is exceeded, cash is posted by the Partnership if the value of derivatives is a liability to the Partnership. As of March 31, 2009 the Partnership has no cash collateral deposits posted with counterparties.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

          The Partnership is exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales activities. The Partnerships 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. The Partnership has entered into hedging transactions through 2010 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas, and natural gasoline.

          Based on estimated volumes, as of March 31, 2009, the Partnership had hedged approximately 48% and 22% of its commodity risk by volume for 2009 and 2010, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.

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

Impact of Cash Flow Hedges

Crude Oil

          For the three months ended March 31, 2009 and 2008, net gains and losses on swap hedge contracts increased crude revenue by $180 and decreased crude revenue by $1,092, respectively. As of March 31, 2009 an unrealized derivative fair value gain of $917, related to current and terminated cash flow hedges of crude oil price risk, was recorded in AOCI. Fair value gains of $147, $148 and $623 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at March 31, 2009 adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

Natural Gas

          For the three months ended March 31, 2009 and 2008, net gains and losses on swap hedge contracts increased gas revenue by $370 and decreased gas revenue by $699, respectively. As of March 31, 2009 an unrealized derivative fair value gain of $1,274 related to cash flow hedges of natural gas was recorded in AOCI. This fair value gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

Natural Gas Liquids

          For the three months ended March 31, 2009 and 2008, net gains and losses on swap hedge contracts increased liquids revenue by $397 and decreased liquids revenue by $269, respectively. As of March 31, 2009, an unrealized derivative fair value gain of $2,075 related to current and terminated cash flow hedges of natural gas liquids price risk was recorded in AOCI. Fair value gains of $730, $453 and $892 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at March 31, 2009 adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

(9) Interest Rate Derivatives

          The Partnership is exposed to market risks associated with interest rates. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt and term loan credit facilities. In accordance with SFAS 133, all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings.

          The Partnership has entered into several cash flow hedge agreements with an aggregate notional amount of $235,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities.

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

						Paying				Receiving
Date of Hedge		Notional Amount				Fixed Rate				Floating Rate				Maturity Date
October 2008		$	40,000				2.820	%		3 Month LIBOR				October 2010
January 2008		$	25,000				3.400	%		3 Month LIBOR				January 2010
March 2009		$	25,000				1.290	%		1 Month LIBOR				September 2010
March 2009		$	40,000				0.970	%		1 Month LIBOR				December 2009
February 2009		$	75,000				1.295	%		1 Month LIBOR				November 2010

          The following interest rate swaps have been de-designated as cash flow hedges by the Partnership:

						Paying				Receiving
Date of Hedge		Notional Amount				Fixed Rate				Floating Rate				Maturity Date
September 2007		$	25,000				4.605	%		3 Month LIBOR				September 2010
November 2006		$	40,000				4.820	%		3 Month LIBOR				December 2009
March 2006		$	75,000				5.250	%		3 Month LIBOR				November 2010

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

          The following interest rate swaps have not been designated as cash flow hedges by the Partnership:

Paying

Receiving

Date of Hedge

Notional Amount

Fixed Rate

Floating Rate

Maturity Date

November 2006

$

30,000

4.765

%

3 Month LIBOR

September 2010

						Receiving				Paying
Date of Hedge		Notional Amount				Fixed Rate				Floating Rate				Maturity Date
March 2009		$	30,000				0.440	%		3 Month LIBOR				September 2009
March 2009		$	40,000				1.420	%		3 Month LIBOR				December 2009
March 2009		$	25,000				1.590	%		1 Month LIBOR				September 2010
February 2009		$	75,000				1.445	%		1 Month LIBOR				November 2010

          These swaps have been recorded at fair value with an offset to current earnings.

          The Partnership recognized increases in interest expense of $1,923 and $773 for the three months ended March 31, 2009 and 2008, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate hedges. The net effect in fixed rate for the Partnership’s hedged portion of long-term debt is 4.22% as of March 31, 2009. See Note 12 for more information on the Partnership’s overall weighted average interest on the Partnership’s long-term debt.

(10) Related Party Transactions

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

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

		Three Months Ended March 31,
		2009				2008
Revenues:
Terminalling and storage		$	3,926			$	3,778
Marine transportation			4,900				6,224
Product sales:
Natural gas services			127				1,199
Sulfur services			1,529				4,511
Terminalling and storage			11				18
			1,667				5,728
		$	10,493			$	15,730
Costs and expenses:
Cost of products sold:
Natural gas services		$	11,011			$	20,403
Sulfur services			2,905				3,318
Terminalling and storage			205				278
		$	14,121			$	23,999
Expenses:
Operating expenses
Marine transportation		$	4,690			$	7,224
Natural gas services			441				383
Sulfur services			924				165
Terminalling and storage			2,945				2,271
		$	9,000			$	10,043
Selling, general and administrative:
Natural gas services		$	204			$	200
Sulfur services			534				440
Indirect overhead allocation, net of reimbursement			875				674
		$	1,613			$	1,314

(11) Business Segments

          The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation and sulfur services. The Partnership’s reportable segments are strategic business units

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2009
(Unaudited)

that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

          The accounting policies of the operating segments are the same as those described in Note 2 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 4, 2009. 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				Revenues				Depreciation				Income
		Operating				Intersegment				after				and				(loss) after				Capital
		Revenues				Eliminations				Eliminations				Amortization				eliminations				Expenditures
Three months ended March 31, 2009 Terminalling and storage		$	24,204			$	(1,086	)		$	23,118			$	2,500			$	1,783			$	4,730
Natural gas services			90,866				—				90,866				1,119				2,751				1,111
Marine transportation			17,243				(907	)			16,336				3,301				863				2,027
Sulfur services			26,586				—				26,586				1,485				3,293				4,996
Indirect selling, general and administrative			—				—				—				—				(1,463	)			—
Total		$	158,899			$	(1,993	)		$	156,906			$	8,405			$	7,227			$	12,864
Three months ended March 31, 2008 Terminalling and storage		$	20,362			$	(1,066	)		$	19,296			$	2,141			$	1,176			$	4,451
Natural gas services			207,092				—				207,092				977				41				1,169
Marine transportation			16,981				(578	)			16,403				2,794				792				26,126
Sulfur services			70,241				(16	)			70,225				1,428				8,326				1,854
Indirect selling, general and administrative			—				—				—				—				(1,327	)			—
Total		$	314,676			$	(1,660	)		$	313,016			$	7,340			$	9,008			$	33,600