Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2007


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 August 7, 2007 was 11,986,808. The number of the registrant’s subordinated units outstanding at August 7, 2007 was 2,552,018


	Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements		1
Consolidated and Condensed Balance Sheets as of June 30, 2007 (unaudited) and December 31, 2006 (audited)		1
Consolidated and Condensed Statements of Operations for the Three and Six Months Ended June 30, 2007 and 2006 (unaudited)		2
Consolidated and Condensed Statements of Capital for the Three and Six Months Ended June 30, 2007 and 2006 (unaudited)		3
Consolidated and Condensed Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2007 and 2006 (unaudited)		4
Consolidated and Condensed Statements of Cash Flows for the Six Months Ended June 30, 2007 and 2006 (unaudited)		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3. Quantitative and Qualitative Disclosures about Market Risk		43

Item 4. Controls and Procedures		44

PART II. OTHER INFORMATION		45

Item 1. Legal Proceedings		45

Item 1A. Risk Factors		45

Item 6. Exhibits		45

SIGNATURE CERTIFICATIONS
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Balance Sheet as of December 31, 2006

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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


	June 30,			December 31,
	2007			2006
	(Unaudited)			(Audited)
Assets
Cash	$	324		$	3,675
Accounts and other receivables, less allowance for doubtful accounts of $207 and $394		54,204			56,712
Product exchange receivables		2,906			7,076
Inventories		32,799			33,019
Due from affiliates		2,475			1,330
Other current assets		1,331			2,041

Total current assets		94,039			103,853


Property, plant, and equipment, at cost		392,883			323,967
Accumulated depreciation		(86,094	)		(76,122	)

Property, plant and equipment, net		306,789			247,845


Goodwill		37,405			27,600
Investment in unconsolidated entities		73,185			70,651
Other assets, net		10,617			7,512

	$	522,035		$	457,461


Liabilities and Partners’ Capital

Current installments of long-term debt	$	58		$	74
Trade and other accounts payable		63,122			53,450
Product exchange payables		7,336			14,737
Due to affiliates		5,780			10,474
Income taxes payable		461			86
Other accrued liabilities		3,723			3,876

Total current liabilities		80,480			82,697


Long-term debt		180,000			174,021
Deferred income taxes		8,896			—
Other long-term obligations		2,333			2,218

Total liabilities		271,709			258,936


Partners’ capital		250,011			198,403
Accumulated other comprehensive income		315			122

Total partners’ capital		250,326			198,525


Commitments and contingencies
	$	522,035		$	457,461

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)
(Dollars in thousands, except per unit amounts)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Revenues:
Terminalling and storage	$	7,037		$	5,592		$	13,988		$	11,348
Marine transportation		15,154			10,909			29,038			20,221
Product sales:
Natural gas services		105,321			84,058			207,109			185,982
Sulfur		16,912			17,624			32,083			33,013
Fertilizer		13,441			12,071			27,650			24,096
Terminalling and storage		4,449			2,798			8,242			5,214

		140,123			116,551			275,084			248,305

Total revenues		162,314			133,052			318,110			279,874


Costs and expenses:
Cost of products sold:
Natural gas services		100,939			81,517			197,711			179,600
Sulfur		11,694			11,701			22,031			22,172
Fertilizer		10,722			10,402			22,186			21,402
Terminalling and storage		3,917			2,317			6,932			4,316

		127,272			105,937			248,860			227,490

Expenses:
Operating expenses		20,663			14,381			39,656			28,281
Selling, general and administrative		2,744			2,605			5,465			4,991
Depreciation and amortization		5,468			4,255			10,362			8,207

Total costs and expenses		156,147			127,178			304,343			268,969

Other operating income		—			—			—			853

Operating income		6,167			5,874			13,767			11,758


Other income (expense):
Equity in earnings of unconsolidated entities		2,418			2,310			4,468			4,722
Interest expense		(2,739	)		(3,018	)		(6,316	)		(6,036	)
Debt prepayment premium		—			—			—			(1,160	)
Other, net		72			82			151			251

Total other income (expense)		(249	)		(626	)		(1,697	)		(2,223	)

Net income before taxes	$	5,918		$	5,248		$	12,070		$	9,535
Income taxes		(9	)		—			340			—

Net income	$	5,927		$	5,248		$	11,730		$	9,535


General partner’s interest in net income	$	354		$	237		$	629		$	483
Limited partners’ interest in net income	$	5,573		$	5,011		$	11,101		$	9,052

Net income per limited partner unit — basic and diluted	$	0.41		$	0.40		$	0.82		$	0.72

Weighted average limited partner units — basic		13,638,101			12,682,342			13,478,271			12,491,734
Weighted average limited partner units — diluted		13,642,950			12,685,002			13,483,246			12,494,428

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)
(Dollars in thousands)


	Partners’ Capital
														Accumulated
														Other
											General			Comprehensive
	Common					Subordinated					Partner			Income
	Units		Amount			Units		Amount			Amount			Amount		Total
Balances — January 1, 2006		5,829,652	$	100,206			3,402,690	$	(5,642	)	$	1,001		$	—	$	95,565

Net Income		—		6,651			—		2,401			483			—		9,535

Follow-on public offering		3,450,000		95,273			—		—			—			—		95,273

General partner contribution		—		—			—		—			2,052			—		2,052

Unit-based compensation		3,000		9			—		—			—			—		9

Cash distributions		—		(11,325	)		—		(4,150	)		(554	)		—		(16,029	)

Change in other comprehensive income		—		—			—		—			—			481		481


Balances — June 30, 2006		9,282,652	$	190,814			3,402,690	$	(7,391	)	$	2,982		$	481	$	186,886


Balances — January 1, 2007		10,603,808	$	201,387			2,552,018	$	(6,237	)	$	3,253		$	122	$	198,525

Net Income		—		9,254			—		1,847			629			—		11,730

Follow-on public offering		1,380,000		55,934			—		—			—			—		55,934

General partner contribution		—		—			—		—			1,192			—		1,192

Unit-based compensation		3,000		26			—		—			—					26

Cash distributions		—		(13,361	)		—		(3,216	)		(697	)		—		(17,274	)

Change in other comprehensive income		—		—			—		—			—			193		193


Balances — June 30, 2007		11,986,808	$	253,240			2,552,018	$	(7,606	)	$	4,377		$	315	$	250,326

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)
(Dollars in thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Net income	$	5,927		$	5,248		$	11,730		$	9,535
Changes in fair values of commodity cash flow hedges		(193	)		(315	)		(357	)		(552	)
Cash flow hedging gains (losses) reclassified to earnings		40			25			(270	)		36
Changes in fair value of interest rate cash flow hedge		1,457			997			820			997


Comprehensive income	$	7,231		$	5,955		$	11,923		$	10,016

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)
(Dollars in thousands)


	Six Months Ended
	June 30,
	2007			2006
Cash flows from operating activities:
Net income	$	11,730		$	9,535

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10,362			8,207
Amortization of deferred debt issuance costs		540			500
Deferred taxes		(68	)		—
Gain on involuntary conversion of property, plant and equipment		—			(853	)
Equity in earnings of unconsolidated entities		(4,468	)		(4,722	)
Distributions from unconsolidated entities		486			383
Distributions in-kind from equity investments		4,541			3,915
Non-cash mark-to-market on derivatives		854			638
Other		26			57
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		6,769			20,500
Product exchange receivables		4,170			(4,178	)
Inventories		702			(1,607	)
Due from affiliates		(1,145	)		(11	)
Other current assets		148			(169	)
Trade and other accounts payable		6,059			(21,016	)
Product exchange payables		(7,401	)		3,546
Due to affiliates		(4,694	)		3,344
Income taxes payable		277			—
Other accrued liabilities		(892	)		(7,036	)
Change in other non-current assets and liabilities		(47	)		(109	)

Net cash provided by operating activities		28,043			10,924


Cash flows from investing activities:
Payments for property, plant and equipment		(36,772	)		(37,753	)
Acquisitions, net of cash acquired		(37,344	)		(7,451	)
Proceeds from sale of property, plant and equipment		—			770
Insurance proceeds from involuntary conversion of property, plant and equipment		—			2,541
Return of investments from unconsolidated entities		2,684			304
Investments in unconsolidated entities		(5,777	)		(1,336	)

Net cash used in investing activities		(77,209	)		(42,925	)


Cash flows from financing activities:
Payments of long-term debt		(97,287	)		(86,304	)
Proceeds from long-term debt		103,250			35,000
Payments of debt issuance costs		—			(319	)
Net proceeds from follow on public offering		55,934			95,273
General partner contribution		1,192			2,052
Cash distributions paid		(17,274	)		(16,029	)

Net cash provided by financing activities		45,815			29,673


Net decrease in cash		(3,351	)		(2,328	)
Cash at beginning of period		3,675			6,465

Cash at end of period	$	324		$	4,137

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)
June 30, 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

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 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 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 $15 and $6 for the three months ended June 30, 2007 and 2006 and $26 and $9 for the six months ended June 30, 2007 and 2006. The Partnership’s general partner contributed cash of $2 in January 2006 and $3 in May 2007 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.

(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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

excess of $0.625 per unit until all unitholders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months ended June 30, 2007 and 2006 the general partner received $240 and $134 in incentive distributions. For the six months ended June 30, 2007 and 2006, the general partner received and $402 and $268 in incentive distributions.

(d) Net Income per Unit

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

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

The weighted average units outstanding for basic net income per unit were 13,638,101 and 12,682,342 for the three months ended June 30, 2007 and 2006, respectively, and 13,478,271 and 12,491,734 for the six months ended June 30, 2007 and 2006, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 4,849 and 2,660 for the three months ended June 30, 2007 and 2006, respectively, and 4,975 and 2,694 for the six months ended June 30, 2007 and 2006, 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 Company 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) Acquisitions

(a) Lubricants Terminal

In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (Mega Lubricants) located in Channelview, Texas. The terminal is located on 5.6 acres of land, and consists of 38

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

tanks with a storage capacity of approximately 600,000 gallons, pump and piping infrastructure for lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an administrative office.

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


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

Total	$	4,738

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

(b) Woodlawn Pipeline Company Inc.

On May 2, 2007, the Partnership, through its subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), acquired 100% of the outstanding stock of Woodlawn Pipeline Company Inc. (“Woodlawn”). The results of Woodlawn’s operations have been included in the consolidated financial statements beginning May 2, 2007. Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 160 miles of natural gas gathering pipe, approximately 40 miles of condensate transport pipe and a 30 Mcf/day processing plant. Prism Gas acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from Woodlawn to the Texas Eastern Transmission pipeline system.

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

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


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

Total	$	32,606

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

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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

(c) 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 Corporation (“MRMC”), pursuant to which MRMC will operate the facilities through a terminalling service agreement based upon throughput rates and will assume all additional expenses to operate the facility.

(d) 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.

(e) 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 and new engines were 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 MRMC. 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.

(3) Inventories

Components of inventories at June 30, 2007 and December 31, 2006 were as follows:


	June 30,		December 31,
	2007		2006
Natural Gas Liquids	$	18,109	$	17,061
Sulfur		2,252		4,397
Fertilizer — raw materials and packaging		2,535		2,412
Fertilizer — finished goods		4,839		4,807
Lubricants		3,606		2,592
Other		1,458		1,750

	$	32,799	$	33,019

(4) Investment in Unconsolidated Partnerships and Joint Ventures

The Partnership, through its subsidiary Prism Gas, owns 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). Each of these interests is 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.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

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 $297 for the three months and six months ended June 30, 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 $10,982 and $11,279 at June 30, 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 six months 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, 2006	$	64,937		$	1,718		$	3,786		$	210		$	70,651
Distributions in kind		(4,541	)		—			—			—			(4,541	)
Cash contributions		5,670			—			—			107			5,777
Cash distributions		(2,625	)		(470	)		(75	)		—			(3,170	)
Equity in earnings:
Equity in earnings from operations		4,301			419			110			(65	)		4,765
Amortization of excess investment		(275	)		(8	)		(14	)		—			(297	)


Investment in unconsolidated entities, June 30, 2007	$	67,467		$	1,659		$	3,807		$	252		$	73,185


	Waskom			PIPE			Matagorda			BCP		Total
Investment in unconsolidated entities, December 31, 2005	$	54,087		$	1,723		$	4,069		$	—	$	59,879

Distributions in kind		(3,915	)		—			—			—		(3,915	)
Cash contributions		1,140			—			—			196		1,336
Cash distributions		(150	)		(139	)		(398	)		—		(687	)
Equity in earnings:
Equity in earnings from operations		4,380			97			245			—		4,722

Investment in unconsolidated entities, June 30, 2006	$	55,542		$	1,681		$	3,916		$	196	$	61,335

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


					Three Months Ended				Six Months Ended
	As of June 30,				June 30,				June 30,
			Partner's				Net				Net
	Total Assets		Capital		Revenues		Income		Revenues		Income
2007
Waskom	$	58,476	$	51,058	$	18,374	$	4,873	$	33,173	$	8,602


	As of December 31,
2006
Waskom	$	53,260	$	45,450	$	17,471	$	4,537	$	34,270	$	9,080

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

(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.

Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of June 30, 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 six months ended June 30, 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.

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						Six Months
	Ended						Ended
	June 30						June 30
	2007			2006			2007			2006
Change in fair value of derivatives that do not qualify for hedge accounting	$	(509	)	$	(418	)	$	(793	)	$	(132	)
Ineffective portion of derivatives qualifying for hedge accounting		(35	)		(25	)		89			(35	)

Change in fair value of derivatives in the Consolidated Statement of Operations	$	(544	)	$	(443	)	$	(704	)	$	(167	)

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


	June 30,			December 31,
	2007			2006
Fair value of derivative assets — current	$	225		$	882
Fair value of derivative assets — long term		—			221
Fair value of derivative liabilities — current		(561	)		—
Fair value of derivative liabilities — long term		(500	)		(74	)

Net fair value of derivatives	$	(836	)	$	1,029

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2007 (all gas quantities are expressed in British Thermal Units, crude oil and

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

natural gas liquids are expressed in barrels). As of June 30, 2007, the remaining term of the contracts extend no later than December 2010, 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 three and six months ended June 30, 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 June 30, 2007.

June 30, 2007


	Total
	Volume		Remaining Terms
Transaction 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	July 2007 to December 2007	$	(120	)

Crude Oil swap	5,000 BBL	Fixed price of $65.95 settled against WTI NYMEX average monthly closings	July 2007 to December 2007		(152	)

Natural Gas swap and Natural Gas basis swap	20,000 MMBTU	Combined fixed price of $8.54 settled against Henry Hub Centerpoint Energy Gas Transmission Co.	July 2007 to December 2007		225

Natural Gas swap	30,000 MMBTU	Fixed price of $8.12 settled against Houston Ship Channel first of the month	January 2008 to December 2008		(132	)

Crude Oil Swap	3,000 BBL	Fixed price of $70.75 settled against WTI NYMEX average monthly closings	January 2008 to December 2008		(50	)

Crude Oil Swap	3,000 BBL	Fixed price of $69.08 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(104	)

Crude Oil Swap	3,000 BBL	Fixed price of $70.90 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(51)


Total swaps not receiving hedge accounting				$	(384	)


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	$	(336	)

Ethane Swap	5,000 BBL	Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings	January 2008 to December 2008		(43	)

Crude Oil Swap	1,000 BBL	Fixed price of $70.45 settled against WTI NYMEX average monthly closings	January 2009 to December 2009		(21	)

Crude Oil Swap	2,000 BBL	Fixed price of $69.15 settled against WTI NYMEX average monthly closings	January 2010 to December 2010		(52)


Total swaps receiving hedge accounting				$	(452	)


Total net fair value of derivatives				$	(836	)

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.

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,

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

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 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 ethane.

Based on estimated volumes, as of June 30, 2007, Prism Gas had hedged approximately 39%, 50%, 22% and 7% of its commodity risk by volume for 2007, 2008, 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. 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
2008	Ethane	5,000 BBL/Month	Ethane Swap ($27.30)	Mt. Belvieu
2008	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($70.75)	NYMEX
2009	Condensate & Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($69.08)	NYMEX
2009	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($70.90)	NYMEX
2009	Condensate	1,000 BBL/Month	Crude Oil Swap ($70.45)	NYMEX
2010	Condensate	2,000 BBL/Month	Crude Oil Swap ($69.15)	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 month periods ended June 30, 2007 and 2006, net gains and losses on swap hedge contracts decreased crude revenue by $494 and $355, respectively. For the six month periods ending June 30, 2007 and 2006 net gains and losses on swap hedge contracts decreased crude revenue by $351 and $555, respectively. As of June 30, 2007 an unrealized derivative fair value loss of $374, related to cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2008, 2009 and 2010. 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.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

Natural Gas

For the three month periods ended June 30, 2007 and 2006, net gains and losses on swap hedge contracts increased gas revenue by $130 and $110, respectively. For the six month periods ended June 30, 2007 and 2006, net losses and gains on swap hedge contracts decreased gas revenue by $243 and increased gas revenue by $431, respectively. As of June 30, 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).

Natural Gas Liquids

For the three month periods ended June 30, 2007 and 2006, net gains and losses on swap hedge contracts decreased liquids revenue by $180 and $198, respectively. For the six month periods ended June 30, 2007 and 2006, net gains and losses on swap hedge contracts decreased liquids revenue by $110 and $44, respectively. As of June 30, 2007 an unrealized derivative fair value loss of $43, related to cash flow hedges of natural gas liquids 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.

(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 June 30, 2007 with an offset to current operations.

During the three and six months ended June 30, 2007, the Partnership recognized decreases in interest expense of $403 and $431, 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 total fair value of the interest rate swap agreements was recorded as an asset (liability) of approximately $1,122 and $(83) at June 30, 2007 and December 31, 2006, respectively.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

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


	June 30,		December 31,
	2007		2006
Fair value of derivative assets — current	$	473	$	377
Fair value of derivative assets — long term		649		112
Fair value of derivative liabilities — current		—		—
Fair value of derivative liabilities — long term		—		(572	)

Net fair value of derivatives	$	1,122	$	(83	)

(7) Related Party Transactions

Included in the consolidated and condensed financial statements are various related party transactions and balances primarily with 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				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Revenues:
Terminalling and storage	$	2,683	$	2,246	$	5,268	$	4,297
Marine transportation		6,133		3,144		12,687		5,609
Product sales:
Natural gas services		641		2		641		128
Fertilizer		91		—		99		24
Terminalling and storage		7		6		10		21

		739		8		750		173

	$	9,555	$	5,398	$	18,705	$	10,079


Costs and expenses:
Cost of products sold:
Natural gas services	$	13,646	$	14,150	$	25,856	$	27,942
Sulfur		1,143		1,578		2,248		3,061
Fertilizer		2,168		1,885		5,041		3,134
Terminalling and storage		—		—		—		1

	$	16,957	$	17,613	$	33,145	$	34,138


Expenses:
Operating expenses Marine transportation	$	5,123	$	5,445	$	9,285	$	9,968
Natural gas services		378		414		763		808
Sulfur		279		180		519		352
Fertilizer		50		37		87		75
Terminalling and storage		1,138		901		2,175		1,840

	$	6,968	$	6,977	$	12,829	$	13,043


Selling, general and administrative:
Natural gas services	$	174	$	168	$	341	$	333
Sulfur		95		113		187		220
Fertilizer		302		290		597		565
Terminalling and storage		14		21		28		39
Indirect overhead allocation, net of reimbursement		326		326		652		652

	$	911	$	918	$	1,805	$	1,809

(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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

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				Income (loss)
	Operating		Intersegment			after		Depreciation		after			Capital
	Revenues		Eliminations			Eliminations		and Amortization		eliminations			Expenditures
Three months ended June 30, 2007
Terminalling and storage	$	11,622	$	(137	)	$	11,485	$	1,466	$	2,563		$	6,278
Natural gas services		105,321		—			105,321		871		464			890
Marine transportation		15,897		(742	)		15,155		1,963		1,385			10,541
Sulfur		17,218		(307	)		16,911		752		708			434
Fertilizer		13,663		(221	)		13,442		416		1,897			2,866
Indirect selling, general and administrative		—		—			—		—		(850	)		—


Total	$	163,721	$	(1,407	)	$	162,314	$	5,468	$	6,167		$	21,009


Three months ended June 30, 2006
Terminalling and storage	$	8,486	$	(96	)	$	8,390	$	1,093	$	2,114		$	4,604
Natural gas services		84,058		—			84,058		408		(44	)		867
Marine transportation		11,308		(399	)		10,909		1,628		1,686			5,308
Sulfur		17,909		(285	)		17,624		720		2,092			3,905
Fertilizer		12,167		(96	)		12,071		406		875			3,968
Indirect selling, general and administrative		—		—			—		—		(849	)		—


Total	$	133,928	$	(876	)	$	133,052	$	4,255	$	5,874		$	18,652


						Operating				Operating
						Revenues		Depreciation		Income (loss)
	Operating		Intersegment			after		and		after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Six months ended June 30, 2007
Terminalling and storage	$	22,463	$	(234	)	$	22,229	$	2,806	$	5,540		$	11,283
Natural gas services		207,109		—			207,109		1,302		2,408			1,594
Marine transportation		30,773		(1,734	)		29,039		3,902		2,403			15,643
Sulfur		32,660		(578	)		32,082		1,521		1,197			971
Fertilizer		28,209		(558	)		27,651		831		3,825			7,281
Indirect selling, general and administrative		—		—			—		—		(1,606	)		—


Total	$	321,214	$	(3,104	)	$	318,110	$	10,362	$	13,767		$	36,772


Six months ended June 30, 2006
Terminalling and storage	$	16,764	$	(202	)	$	16,562	$	2,169	$	5,077		$	6,544
Natural gas services		185,982		—			185,982		804		1,204			3,549
Marine transportation		20,930		(709	)		20,221		3,039		2,395			11,984
Sulfur		33,727		(714	)		33,013		1,388		3,551			9,522
Fertilizer		24,274		(178	)		24,096		807		1,097			6,154
Indirect selling, general and administrative		—		—			—		—		(1,566	)		—


Total	$	281,677	$	(1,803	)	$	279,874	$	8,207	$	11,758		$	37,753

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

The following table reconciles operating income to net income:


	Three Months Ended						Six Months Ended
	June 30						June 30
	2007			2006			2007			2006
Operating income	$	6,167		$	5,874		$	13,767		$	11,758
Equity in earnings of unconsolidated entities		2,418			2,310			4,468			4,722
Interest expense		(2,739	)		(3,018	)		(6,316	)		(6,036	)
Debt prepayment premium		—			—			—			(1,160	)
Other, net		72			82			151			251
Income taxes		9			—			(340	)		—

Net income	$	5,927		$	5,248		$	11,730		$	9,535

Total assets by segment are as follows:


	June 30,		December 31,
	2007		2006
Total assets:
Terminalling and storage	$	104,039	$	89,354
Natural gas services		220,117		184,464
Marine transportation		89,859		77,668
Sulfur		57,699		62,210
Fertilizer		50,321		43,765

Total assets	$	522,035	$	457,461

(9) Public Equity Offerings

In May, 2007, the Partnership completed a public offering of 1,380,000 common units at a price of $42.25 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 64.3% limited partnership interest in the Partnership. Total proceeds from the sale of the 1,380,000 common units, net of underwriters’ discounts, commissions and offering expenses were $55,934. The Partnership’s general partner contributed $1,190 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital.

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


*Proceeds received:*
Sale of common units	$	58,305
General partner contribution		1,190

Total proceeds received	$	59,495


*Use of Proceeds:*
Underwriter’s fees	$	2,107
Professional fees and other costs		264
Repayment of debt under revolving credit facility		55,850
Working capital		1,274

Total use of proceeds	$	59,495

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

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) Long-term Debt

At June 30, 2007 and December 31, 2006, long-term debt consisted of the following:


	June 30,		December 31,
	2007		2006
*$120,000 Revolving loan facility at variable interest rate (6.93% weighted average at June 30, 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	$	50,000	$	44,000
**$130,000 Term loan facility at variable interest rate (7.12% at June 30, 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%		58		95

Total long-term debt		180,058		174,095
Less current installments		58		74

Long-term debt, net of current installments	$	180,000	$	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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. Effective July 1, 2007, the applicable margin for existing borrowings remains 2.00%. As a result of our leverage ratio test, effective October 1, 2007, the applicable margin for existing borrowing will decrease to 1.75%. 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%.

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 June 30, 2007, we had $50,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of June 30, 2007, we had $69,880 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) its joint ventures to incur indebtedness or grant certain liens.

The credit facility also contains covenants, which, among other things, require the Partnership to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

with the debt covenants contained in credit facility for the year ended December 31, 2006 and as of June 30, 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 June 30, 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.

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 $226,850. As of June 30, 2007, the Partnership had $69,880 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. 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 $2,342 and $2,484 for the three months ended June 30, 2007 and 2006, respectively, and $5,945 and $6,261 for the six months ended June 30, 2007 and 2006, respectively. Capitalized interest was $806 and $398 for the three months ended June 30, 2007 and 2006, respectively, and $1,345 and $670 for the six months ended June 30, 2007 and 2006, respectively.

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

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

(11) Income Taxes

The operations of a partnership are generally not subject to income taxes, and a partnership’s income is generally taxed directly to its owners. However, the Partnership is subject to the Texas margin tax as described below and our subsidiary, Woodlawn, is subject to income taxes. Current income taxes related to the operations of this subsidiary since acquisition total $14. In connection with the Woodlawn acquisition, the Partnership also established deferred taxes associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment. A deferred tax benefit related to these basis differences of $68 was recorded for the three and six month periods ended June 30, 2007.

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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
June 30, 2007
(Unaudited)

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 $173 resulting from the liquidation were recorded in current year income tax expense for the six months ending June 30, 2007.

On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. 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 and $269 were recorded in current year income tax expense for the three and six months ending June 30, 2007.

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


	Three Months Ended			Six Months Ended
	2007			2007
Current:
Federal	$	(40	)	$	157
State		99			251

	$	59		$	408


Deferred:
Federal	$	(68	)	$	(68	)

	$	(9	)	$	340

(12) 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.

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

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

Forward-Looking Statements

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

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

Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 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 35.7% 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

terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.

Critical Accounting Policies

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

You should also read Note 1, “General” in Notes to Consolidated and Condensed Financial Statements contained in this quarterly report and the “Significant Accounting Policies” note in the consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 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 June 30, 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.

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 – Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership based on specific contract terms at either the shipping or delivery point.

Equity Method Investments

We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under the provisions of 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.

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

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

Environmental Liabilities

We have historically not experienced circumstances requiring us to account for environmental remediation obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other related environmental studies that we may elect to perform. We

would record changes to our estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related eventual liability.

Allowance for Doubtful Accounts

In evaluating the 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 34.9% limited partnership interest and a 2% general partnership interest in us and all of our incentive distribution rights.

Management

Martin Resource Management directs our business operations through its ownership and control of our general partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of management expertise and established relationships throughout the energy industry. We do

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

Related Party Agreements

We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires us to reimburse Martin Resource Management for all direct 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 $12.4 million of direct costs and expenses for the three months ended June 30, 2007 compared to $12.8 million for the three months ended June 30, 2006. We reimbursed Martin Resource Management for $25.2 million of direct costs and expenses for the six months ended June 30, 2007 compared to $24.3 million for the six months ended June 30, 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 August 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 June 30, 2007 and 2006. We reimbursed Martin Resource Management for $0.7 million of indirect expenses for the six months ended June 30, 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 13% and 17% of our total cost of products sold

during the three months ended June 30, 2007 and 2006, respectively; and approximately 13% and 15% of our total cost of products sold during the six months ended June 30, 2007 and 2006, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for approximately 6% and 4% of our total revenues for the three months ended June 30, 2007 and 2006, respectively. Our sales to Martin Resource Management accounted for approximately 6% and 4% of our total revenues for the six months ended June 30, 2007 and 2006, respectively. In connection with the closing of the Tesoro Marine asset acquisition, 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 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.

Approval and Review of Related Party Transactions

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee of our general partner’s board of directors, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.

Results of Operations

The results of operations for the three and six months ended June 30, 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 and six months ended June 30, 2007 and 2006. The results of operations for the first six months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.


						Operating								Operating
			Revenues			Revenues					Operating			Income (loss)
	Operating		Intersegment			after		Operating			Income Intersegment			after
	Revenues		Eliminations			Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)
Three months ended June 30, 2007
Terminalling and storage	$	11,622	$	(137	)	$	11,485	$	2,611		$	(48	)	$	2,563
Natural gas services		105,321		—			105,321		464			—			464
Marine transportation		15,897		(742	)		15,155		2,080			(695	)		1,385
Sulfur		17,218		(307	)		16,911		425			283			708
Fertilizer		13,663		(221	)		13,442		1,437			460			1,897
Indirect selling, general and administrative		—		—			—		(850	)		—			(850	)

Total	$	163,721	$	(1,407	)	$	162,314	$	6,167		$	—		$	6,167


						Operating								Operating
			Revenues			Revenues					Operating			Income (loss)
	Operating		Intersegment			after		Operating			Income Intersegment			after
	Revenues		Eliminations			Eliminations		Income (loss)			Eliminations			Eliminations
Three months ended June 30, 2006
Terminalling and storage	$	8,486	$	(96	)	$	8,390	$	2,142		$	(28	)	$	2,114
Natural gas services		84,058		—			84,058		(44	)		—			(44	)
Marine transportation		11,308		(399	)		10,909		2,085			(399	)		1,686
Sulfur		17,909		(285	)		17,624		1,728			364			2,092
Fertilizer		12,167		(96	)		12,071		812			63			875
Indirect selling, general and administrative		—		—			—		(849	)		—			(849	)


Total	$	133,928	$	(876	)	$	133,052	$	5,874		$	—		$	5,874


											Operating			Operating
			Revenues			Operating					Income			Income (loss)
	Operating		Intersegment			Revenues		Operating			Intersegment			after
	Revenues		Eliminations			after Eliminations		Income (loss)			Eliminations			Eliminations
						(In thousands)
Six months ended June, 2007
Terminalling and storage	$	22,463	$	(234	)	$	22,229	$	5,498		$	42		$	5,540
Natural gas services		207,109		—			207,109		2,408			—			2,408
Marine transportation		30,773		(1,734	)		29,039		4,084			(1,681	)		2,403
Sulfur		32,660		(578	)		32,082		163			1,034			1,197
Fertilizer		28,209		(558	)		27,651		3,220			605			3,825
Indirect selling, general and administrative		—		—			—		(1,606	)		—			(1,606	)


Total	$	321,214	$	(3,104	)	$	318,110	$	13,767		$	—		$	13,767


Six months ended June 30, 2006
Terminalling and storage	$	16,764	$	(202	)	$	16,562	$	5,147		$	(70	)	$	5,077
Natural gas services		185,982		—			185,982		1,204			—			1,204
Marine transportation		20,930		(709	)		20,221		3,104			(709	)		2,395
Sulfur		33,727		(714	)		33,013		2,881			670			3,551
Fertilizer		24,274		(178	)		24,096		988			109			1,097
Indirect selling, general and administrative		—		—			—		(1,566	)		—			(1,566	)


Total	$	281,677	$	(1,803	)	$	279,874	$	11,758		$	—		$	11,758

Our results of operations are discussed on a comparative basis below. There are certain items of income and expense which we do not allocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment.

Three Months Ended June 30, 2007 Compared to the Three Months Ended June 30, 2006

Our total revenues before eliminations were $163.7 million for the three months ended June 30, 2007 compared to $133.9 million for the three months ended June 30, 2006, an increase of $29.8 million, or 22%. Our operating income before eliminations was $6.2 million for the three months ended June 30, 2007 compared to $5.9 million for the three months ended June 30, 2006, an increase of $0.3 million, or 5%.

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

Terminalling and Storage Segment

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


	Three Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues:
Services	$	7,037	$	5,592
Products		4,585		2,894

Total revenues		11,622		8,486

Cost of products sold		3,938		2,385
Operating expenses		3,576		2,837
Selling, general and administrative expenses		31		29
Depreciation and amortization		1,466		1,093

Operating income	$	2,611	$	2,142

Revenues. Our terminalling and storage revenues increased $3.1 million, or 37%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. Service revenue accounted for $1.4 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 $1.7 million primarily due to $0.8 million from the assets of Mega Lubricants Inc. (“Mega Lube”) and an additional 7% increase in historical sales volumes and a 19% increase in product cost that was able to be passed along to our customers.

Cost of products sold. Our cost of products sold increased $1.5 million, or 65%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This was primarily a result of $0.7 million from the Mega Lube acquisition and an additional 7% increase in historical sales volumes and a 19% increase in product cost that was able to be passed along to our customers.

Operating expenses. Operating expenses increased $0.7 million, or 26%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase was due primarily to $0.4 million of additional operating expenses from the acquisition of the Corpus Christi terminal and increased salaries, property and liability premiums and product handling costs.

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

Depreciation and amortization. Depreciation and amortization expenses increased $0.4 million, or 34%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase was primarily a result of our recent acquisitions and capital expenditures.

In summary, our terminalling operating income increased $0.5 million, or 22%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006.

Natural Gas Services Segment

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


	Three Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	105,321	$	84,058
Cost of products sold		100,939		81,517
Operating expenses		1,812		1,260
Selling, general and administrative expenses		1,236		917
Depreciation and amortization		870		408

Operating income (loss)	$	464	$	(44	)


Equity in Earnings of Unconsolidated Entities	$	2,418	$	2,310

NGL Volumes (gallons)		72,988		69,229

Revenues. Our natural gas services revenues increased $21.3 million, or 25%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. Our historical NGL distribution segment increased $14.5 million, or 23%. The increase in revenues is primarily due to an increase in sales volumes, resulting from increased demand from our industrial customers. In addition to increased sales volumes, our average sales price per gallon increased 8%, due to a general increase in the prices of NGL’s.

In addition to the increased activity in our historical NGL distribution segment, Prism Gas experienced a $6.8 million, or 33% increase in revenues. The increase in revenue was comprised of a $7.1 million increase in natural gas sales, a $0.4 million increase in gathering and processing fees, offset by a $0.1 million loss on derivative contracts and a $0.6 million decline in NGL sales. The increase in both natural gas sales and processing fees is primarily attributable to the acquisition of Woodlawn Pipeline Company Inc. (“Woodlawn”).

Costs of product sold. Our cost of products increased $19.4 million, or 24%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase was primarily related to our historical NGL distribution segment, as we experienced a $13.9 million increase in cost of products sold. Our per gallon margin increased by 21% as we were able to increase our per gallon margin with our industrial customers. The balance of the increase of $5.5 million relates primarily to the Woodlawn acquisition.

Operating expenses. Operating expenses increased $0.6 million, or 44%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase is primarily related to the Woodlawn acquisition.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.3 million, or 35%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase is primarily related to the Woodlawn acquisition along with an increase in other administrative expenses.

Depreciation and amortization. Depreciation and amortization increased $0.5 million, or 113% for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase is primarily related to the Woodlawn acquisition.

In summary, our natural gas services operating income increased $0.5 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $2.4 million and $2.3 million for the three months ended June 30, 2007 and 2006, respectively. This reflects the results of our unconsolidated equity method investees since we acquired Prism Gas on November 10, 2005. In connection with this acquisition, we acquired an unconsolidated 50% interest in each of Waskom, Matagorda and PIPE. As a result, these interests are accounted for using the equity method of accounting and we do not include any portion of their net income in our operating income. On June 30, 2006, the Partnership, through its subsidiary Prism Gas, acquired a 20% ownership interest in the partnership which owns the lease rights to the Bosque County Pipeline (“BCP”). This interest is accounted for under the equity method of accounting.

Marine Transportation Segment

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


	Three Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	15,897	$	11,308
Operating expenses		11,836		7,441
Selling, general and administrative expenses		17		154
Depreciation and amortization		1,964		1,628

Operating income	$	2,080	$	2,085

Revenues. Our marine transportation revenues increased $4.6 million, or 41%, for the three months ended June 30, 2007, compared to the three months ended June 30, 2006. Our inland marine operations generated an additional $4.1 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. Our offshore revenues increased $0.3 million.

Operating expenses. Operating expenses increased $4.4 million, or 59%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. We experienced increases in operating costs from outside towing expenses for leased vessels, repairs and maintenance, injury claims, and crew wages.

Selling, general, and administrative expenses. Selling, general and administrative expenses decreased $0.1 million, or 89%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006.

Depreciation and Amortization. Depreciation and amortization increased $0.3 million, or 21%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase was primarily a result of capital expenditures made in the last twelve months.

In summary, our marine transportation operating income remained consistent for both three month periods..

Sulfur Segment

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


	Three Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	17,218	$	17,909
Cost of products sold		11,895		11,986
Operating expenses		3,942		3,207
Selling, general and administrative expenses		203		268
Depreciation and amortization		753		720

Operating income	$	425	$	1,728


Sulfur Volumes (long tons)		295.3		230.2

Revenues. Our sulfur revenues decreased $0.7 million, or 4%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This decrease resulted from a 28% increase in sales

volume offset by a 27% decrease in sales price. The sales volume increase was due to a new sales contract with an individual customer negotiated in 2007. The sales price decrease was a result of a change in the mix of sales in the respective geographic locations in which we sell and a decrease in both world and domestic market prices.

Cost of products sold. Our cost of products sold decreased $0.1 million, or 1%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This decrease was less than our sales revenue decline as our margin per ton fell due to competitive pressure.

Operating expenses. Our operating expenses increased $0.7 million, or 23%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase was a result of increased marine transportation expenses. These marine transportation cost increases related to payroll and repairs and maintenance.

Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.1 million, or 24%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006.

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

In summary, our sulfur operating income decreased $1.3 million, or 75%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006.

Fertilizer Segment

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


	Three Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	13,663	$	12,167
Cost of products sold		11,402		10,561
Selling, general and administrative expenses		408		388
Depreciation and amortization		416		406

Operating income	$	1,437	$	812


Fertilizer Volumes (tons)		67.1		63.7

Revenues. Our fertilizer revenues increased $1.5 million, or 12%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. Our sales volume increased 5% 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. Our cost of products sold increased $0.8 million, or 8%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This percentage increase was less than our percentage increase in sales, resulting in an increased gross margin per ton.

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

Depreciation and amortization. Depreciation and amortization remained consistent for both three month periods.

In summary, our fertilizer operating income increased $0.6 million, or 77%, for the three months ended June 30, 2007 compared to the three months ended June 30, 2006.

Six Months Ended June 30, 2007 Compared to the Six Months Ended June 30, 2006

Our total revenues before eliminations were $321.2 million for the six months ended June 30, 2007 compared to $281.7 million for the six months ended June 30, 2006, an increase of $39.5 million, or 14%. Our operating income before eliminations was $13.8 million for the six months ended June 30, 2007 compared to $11.8 million for the six months ended June 30, 2006, an increase of $2.0 million, or 17%.

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

Terminalling and Storage Segment

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


	Six Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues:
Services	$	13,988	$	11,348
Products		8,475		5,416

Total revenues		22,463		16,764

Cost of products sold		7,103		4,448
Operating expenses		6,996		5,804
Selling, general and administrative expenses		60		49
Depreciation and amortization		2,806		2,169

		5,498		4,294

Other operating income		—		853

Operating income	$	5,498	$	5,147

Revenues. Our terminalling and storage revenues increased $5.7 million, or 34%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. Service revenue accounted for $2.6 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 $3.1 million primarily due to $0.8 million from the Mega Lube acquisition and an additional 23% increase in historical sales volumes and an 18% increase in product cost that was able to be passed along to our customers.

Cost of products sold. Our cost of products increased $2.7 million, or 60%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This was primarily a result of $0.7 million from the Mega Lube acquisition and an additional 23% increase in historical sales volumes and an 18% increase in product cost that was able to be passed along to our customers.

Operating expenses. Operating expenses increased $1.2 million, or 21%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This increase is due primarily to $0.6 million of additional operating expenses from the acquisition of the Corpus Christi terminal and increased salaries, property and liability premiums and product handling costs.

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

Depreciation and amortization. Depreciation and amortization increased $0.6 million, or 29% for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This increase was primarily a result of our recent acquisition and capital expenditures.

Other operating income. Other operating income decreased $0.9 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This decrease consisted solely of a gain of $0.9 million related to an involuntary conversion of assets in 2006.

In summary, terminalling and storage operating income increased $0.4 million, or 7%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006.

Natural Gas Services Segment

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


	Six Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	207,109	$	185,982
Cost of products sold		197,711		179,600
Operating expenses		3,135		2,565
Selling, general and administrative expenses		2,554		1,809
Depreciation and amortization		1,301		804

Operating income	$	2,408	$	1,204


Equity in Earnings of Unconsolidated Entities	$	4,469	$	4,722


NGL Volumes (gallons)		167,185		158,908

Revenues. Our natural gas services revenues increased $21.1 million, or 11%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. Our historical NGL distribution segment revenues increased $15.9 million, or 11%. This increase in revenues is primarily due to an increase in sales volumes, resulting from increased demand from our retail propane and industrial customers. In addition to increased sales volumes, our average sales price per gallon increased 2%, due to a general increase in the prices of NGL’s.

In addition to the increased activity in our historical NGL distribution segment, Prism Gas experienced a $5.2 million, or 13% increase in revenues. The increase in revenue was comprised of a $6.3 million increase in natural gas sales and a $0.5 million increase in gathering and processing fees, offset by a $1.1 million decrease in NGL sales and a $0.5 million loss on derivative contracts. The increase in both natural gas sales and gathering and processing fees is primarily attributable to the Woodlawn acquisition.

Costs of product sold. Our cost of products increased $18.1 million, or 10%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This increase was primarily related to our historical NGL distribution segment, as we experienced a $13.7 million increase in cost of products sold. As the result of colder weather experienced earlier in the year, our per gallon margin increased by 44% for the six months ended June 30, 2007 as compared to the same period last year. The balance of the increase of $4.4 million relates to the Woodlawn acquisition.

Operating expenses. Operating expenses increased $0.6 million, or 22%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This increase is primarily related to the Woodlawn acquisition as well as additional operating pipeline lease expenses.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.7 million, or 41%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. Of the increase, $0.5 million relates to increased payroll costs and other professional fees.

Depreciation and amortization. Depreciation and amortization increased $0.5 million, or 62%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This increase was primarily a result of the Woodlawn acquisition.

In summary, our natural gas services operating income increased $1.2 million, or 100%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $4.5 and $4.7 million for the six months ended June 30, 2007 and 2006, respectively. This reflects the results of our unconsolidated equity method investees since we acquired Prism Gas on November 10, 2005. In connection with this acquisition, we acquired an unconsolidated 50% interest in each of Waskom, Matagorda and PIPE. As a result, these interests are accounted for using the equity method of accounting and we do not include any portion of their net income in our operating income. On June 30, 2006, the Partnership, through its subsidiary Prism Gas, acquired a 20% ownership interest in a partnership that owns the lease rights to the Bosque County Pipeline (“BCP”). This interest is accounted for under the equity method of accounting.

Marine Transportation Segment

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


	Six Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	30,773	$	20,930
Operating expenses		22,703		14,513
Selling, general and administrative expenses		83		274
Depreciation and amortization		3,903		3,039

Operating income	$	4,084	$	3,104

Revenues. Our marine transportation revenues increased $9.8 million, or 47%, for the six months ended June 30, 2007, compared to the six months ended June 30, 2006. Our inland marine operations generated an additional $7.9 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 additional numbers of leased vessels. Our offshore revenues increased $1.6 million primarily from the acquisition of two integrated tug barge units.

Operating expenses. Operating expenses increased $8.2 million, or 56%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. We experienced increases in operating costs from outside towing expenses for leased vessels, repairs and maintenance, injury and property damage claims, and crew wages.

Selling, general, and administrative expenses. Selling, general and administrative expenses decreased $0.2 million, or 70%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006.

Depreciation and Amortization. Depreciation and amortization increased $0.9 million, or 28%, for the six months ended June 30, 2007 compared to the six months ended June 30, 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 32%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006.

Sulfur Segment

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


	Six Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	32,660	$	33,727
Cost of products sold		22,419		22,887
Operating expenses		8,203		6,069
Selling, general and administrative expenses		354		502
Depreciation and amortization		1,521		1,388

Operating income	$	163	$	2,881


Sulfur Volumes (long tons)		590.1		427.9

Revenues. Our sulfur revenues decreased $1.1 million, or 3%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This decrease resulted from a 38% increase in sales volume offset by a 28% decrease in sales price. The sales volume increase was due to a new sales contract negotiated with an individual customer in 2007. The sales price decrease was a result of a change in the mix of sales in the respective geographic locations in which we sell and a decrease in both world and domestic market prices.

Cost of products sold. Our cost of products sold decreased $0.5 million, or 2%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This decrease was less than our sales revenue decline as our margin per ton fell due to competitive pressure.

Operating expenses. Our operating expenses increased $2.1 million, or 35%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This increase was a result of increased marine transportation expenses. These marine transportation cost increases related to payroll, outside towing, and repairs and maintenance.

Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.1 million, or 29%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006.

Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 10%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This is attributable to the Neches priller conveyor system which was completed in August 2006.

In summary, our sulfur operating income decreased $2.7 million, or 94%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006.

Fertilizer Segment

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


	Six Months Ended
	June 30,
	2007		2006
	(In thousands)
Revenues	$	28,209	$	24,274
Cost of products sold		23,349		21,689
Selling, general and administrative expenses		809		789
Depreciation and amortization		831		808

Operating income	$	3,220	$	988


Fertilizer Volumes (tons)		146.4		128.4

Revenues. Our fertilizer revenues increased $3.9 million, or 16%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. Our sales volume increased 14% 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. Our cost of products sold increased $1.7 million, or 8%, for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. As our demand increased, we were able to spread our margins resulting in an increased gross margin per ton.

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

Depreciation and amortization. Depreciation and amortization remained consistent for both six month periods.

In summary, our fertilizer operating income increased $2.2 million, or 226%, for the six months ended June 30, 2007 compared to the six months ended June 30, 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 and six months ended June 30, 2007 and 2006 are as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Revenues		100	%		100	%		100	%		100	%
Cost of products sold		78	%		80	%		78	%		81	%
Operating expenses		13	%		11	%		13	%		10	%
Selling, general and administrative expenses		2	%		2	%		2	%		2	%
Depreciation and amortization		3	%		3	%		3	%		3	%

Equity in Earnings of Unconsolidated Entities

For the three and six months ended June 30, 2007 and 2006 equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom, Matagorda and PIPE. Also, included are equity in earnings of our unconsolidated interest in BCP for the three and six months ended June 30, 2007.

Equity in earnings of unconsolidated entities was $2.4 million for the three months ended June 30, 2007 compared to $2.3 million for the three months ended June 30, 2006, an increase of $0.1 million. This increase is related to earnings received from Waskom, Matagorda, PIPE and BCP.

Equity in earnings of unconsolidated entities was $4.5 million for the six months ended June 30, 2007 compared to $4.7 million for the six months ended June 30, 2006, a decrease of $0.2 million. This decrease is related to earnings received from Waskom, Matagorda, PIPE and BCP.

Interest Expense

Our interest expense for all operations was $2.7 million for the three months ended June 30, 2007, compared to the $3.0 million for the three months ended June 30, 2006, a decrease of $0.3 million, or 10%. This decrease was primarily due to recognized decreases in interest expense of $0.4 million, related to the difference between the fixed rate and the floating rate of interest on the mark-to-market interest rate swap and net cash settlement of all interest rate swaps.

Our interest expense for all operations was $6.3 million for the six months ended June 30, 2007, compared to the $6.0 million for the six months ended June 30, 2006, an increase of $0.3 million, or 5%. This increase was primarily due to an increase in average debt outstanding and an increase in interest rates in the first six months of 2007 compared to the same period in 2006. This decrease was primarily due to recognized decreases in interest expense of $0.4 million, 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.

Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses were $0.9 million for the three months ended June 30, 2007 compared to $0.8 million for the three months ended June 30, 2006, an increase of $0.1 million, or 13%.

Indirect selling, general and administrative expenses were $1.6 million for both six months ended June 30, 2007 and 2006.

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 we 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 $0.3 million for both three months ended June 30, 2007 and 2006. Martin Resource Management allocated indirect selling, general and administrative expenses of $0.7 million for both six months ended June 30, 2007 and 2006, respectively.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

For the six months ended June 30, 2007, cash decreased $3.4 million as a result of $28.0 million provided by operating activities, $77.2 million used in investing activities and $45.8 million provided by financing activities. For the six months ended June 30, 2006, cash decreased $2.3 million as a result of $10.9 million provided by operating activities, $42.9 million used in investing activities and $29.7 million provided by financing activities.

For the six months ended June 30, 2007 our investing activities of $77.2 million consisted of capital expenditures, acquisitions, return of investments from unconsolidated entities and investments in unconsolidated entities. For the six months ended June 30, 2006 our investing activities of $42.9 million consisted of capital expenditures, acquisitions, proceeds from sale of property, plant and equipment, insurance proceeds from involuntary conversion of property, plant and equipment, investments in and distributions from unconsolidated partnerships.

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

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

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

For the six months ended June 30, 2007 and 2006, our capital expenditures for property and equipment were $68.8 million and $45.2 million, respectively.

As to each period:

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

	•		For the six months ended June 30, 2006, we spent $36.3 million for expansion and $8.9 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 dry dockings of our vessels pursuant to the United States Coast Guard requirements and in our terminal segment for terminal facilities where $3.9 million in maintenance capital expenditures was spent in connection with restoration of assets

destroyed in Hurricanes Rita and Katrina.

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

For the six months ended June 30, 2006, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $16.0 million, net proceeds from a follow on equity offering of $95.3 million, payments of long term debt to financial lenders of $86.3 million, borrowings of long-term debt under our credit facility of $35.0 million, contributions of $2.1 million from our general partner and payments of debt issuance costs of $0.3 million.

We made net investments in unconsolidated entities of $5.8 and $1.3 million during the six months ended June 30, 2007 and 2006, respectively. The net investment in unconsolidated entities includes $6.1 million and $2.3 million of expansion capital expenditures in the six months ended June 30, 2007 and 2006, respectively.

Capital Resources

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

As of June 30, 2007, we had $180.1 million of outstanding indebtedness, consisting of outstanding borrowings of $50.0 million under our revolving credit facility and $130.0 million under our term loan facility and $0.1 of other secured debt.

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

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

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

In January 2006, we completed a follow-on public offering of 3,450,000 common units, resulting in proceeds of $95.3 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 will be used to provide working capital.

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. Please read “Item 1A. Risk Factors — Risks Related to Our Business” for a discussion of such risks.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of June 30, 2007 is as follows: (dollars in thousands):


	Payment due by period
	Total		Less than		1-3		3-5		Due
Type of Obligation	Obligation		One Year		Years		Years		Thereafter
Long-Term Debt
Revolving credit facility	$	50,000	$	—	$	—	$	50,000	$	—
Term loan facility		130,000		—		—		130,000		—
Other		58		58		—		—		—
Non-competition agreements		850		250		400		100		100
Operating leases		30,292		3,844		9,637		5,726		11,085
Interest expense(1)
Revolving Credit Facility		11,662		3,464		6,928		1,270		—
Term loan facility		31,332		9,307		18,613		3,412		—
Other		4		4		—		—		—


Total contractual cash obligations	$	254,198	$	16,927	$	35,578	$	190,508	$	11,185


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

Letter of Credit At June 30, 2007, we have 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 June 30, 2007, we had $50.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of June 30, 2007, we had $69.9 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 $226.9 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 2.00%. Effective July 1, 2007, the applicable margin for existing borrowings remains 2.00%. As a result of our leverage ratio test, effective October 1, 2007, the applicable margin for existing borrowing will decrease to 1.75%. We incur a commitment fee on the unused portions of the credit facility.

Effective April 13, 2006, we entered into an interest rate swap that swaps $75.0 million of floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in November 2010 is accounted for using hedge accounting.

Effective December 13, 2006, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing spread. This interest rate swap, which matures in December, 2009, is accounted for using hedge accounting.

Effective 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 using hedge accounting.

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

The credit facility also contains covenants, which, among other things, require us to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (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 August 6, 2007, our outstanding indebtedness includes $196.8 million under our credit facility.

Seasonality

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

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three months ended June 30, 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 six months ended June 30, 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 June 30, 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 June 30, 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 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 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 ethane.

Based on estimated volumes, as of June 30, 2007, Prism Gas had hedged approximately 39%, 50%, 22% and 7% of its commodity risk by volume for 2007, 2008, 2009 and 2010, 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
2008	Ethane	5,000 BBL/Month	Ethane Swap ($27.30)	Mt. Belvieu
2008	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($70.75)	NYMEX
2009	Condensate & Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($69.08)	NYMEX
2009	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($70.90)	NYMEX
2009	Condensate	1,000 BBL/Month	Crude Oil Swap ($70.45)	NYMEX
2010	Condensate	2,000 BBL/Month	Crude Oil Swap ($69.15)	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 7.07% as of June 30, 2007. We had a total of $180.0 million of indebtedness outstanding under our credit facility as of the date hereof of which $35.0 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on June 30, 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 $0.4 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.

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. Please see “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.

SIGNATURES

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


		Martin Midstream Partners L.P.

		By:		Martin Midstream GP LLC Its General Partner



Date: August 7, 2007	By:	/s/ Ruben S. Martin
		Ruben S. Martin
		President and Chief Executive Officer

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		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).
10.2		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).
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