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 September 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 November 6, 2007 was 11,986,808. The number of the registrant’s subordinated units outstanding at November 6, 2007 was 2,552,018.


	Page
PART I – FINANCIAL INFORMATION		1

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23

Item 3. Quantitative and Qualitative Disclosures about Market Risk		45

Item 4. Controls and Procedures		46

PART II. OTHER INFORMATION		47

Item 1. Legal Proceedings		47

Item 1A. Risk Factors		47

Item 6. Exhibits		47

SIGNATURE
CERTIFICATIONS
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Balance Sheets

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands)


	September 30,			December 31,
	2007			2006
	(Unaudited)			(Audited)
Assets

Cash	$	6,600		$	3,675
Accounts and other receivables, less allowance for doubtful accounts of $212 and $394		65,872			56,712
Product exchange receivables		11,143			7,076
Inventories		39,847			33,019
Due from affiliates		3,117			1,330
Other current assets		1,164			2,041

Total current assets		127,743			103,853


Property, plant and equipment, at cost		413,619			323,967
Accumulated depreciation		(92,032	)		(76,122	)

Property, plant and equipment, net		321,587			247,845


Goodwill		37,405			27,600
Investment in unconsolidated entities		74,042			70,651
Other assets, net		9,510			7,512

	$	570,287		$	457,461


Liabilities and Partners’ Capital

Current installments of long-term debt	$	40		$	74
Trade and other accounts payable		79,492			53,450
Product exchange payables		12,349			14,737
Due to affiliates		5,419			10,474
Income taxes payable		722			86
Other accrued liabilities		6,288			3,876

Total current liabilities		104,310			82,697


Long-term debt		210,000			174,021
Deferred income taxes		8,853			—
Other long-term obligations		3,774			2,218

Total liabilities		326,937			258,936


Partners’ capital		245,400			198,403
Accumulated other comprehensive income (loss)		(2,050	)		122

Total partners’ capital		243,350			198,525


Commitments and contingencies
	$	570,287		$	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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Revenues:
Terminalling and storage	$	7,570		$	6,163		$	21,558		$	17,511
Marine transportation		15,469			12,949			44,507			33,170
Product sales:
Natural gas services		120,994			102,217			328,103			288,199
Sulfur		19,632			13,716			51,715			46,729
Fertilizer		10,234			9,256			37,884			33,352
Terminalling and storage		10,951			3,204			19,193			8,418

		161,811			128,393			436,895			376,698

Total revenues		184,850			147,505			502,960			427,379


Costs and expenses:
Cost of products sold:
Natural gas services		115,112			98,639			312,823			278,239
Sulfur		13,850			8,496			35,881			30,668
Fertilizer		8,665			8,243			30,851			29,645
Terminalling and storage		10,004			2,550			16,936			6,866

		147,631			117,928			396,491			345,418

Expenses:
Operating expenses		21,528			17,470			61,184			45,751
Selling, general and administrative		2,890			2,810			8,355			7,801
Depreciation and amortization		6,236			4,577			16,598			12,784

Total costs and expenses		178,285			142,785			482,628			411,754

Other operating income		—			—			—			853

Operating income		6,565			4,720			20,332			16,478


Other income (expense):
Equity in earnings of unconsolidated entities		2,736			2,720			7,204			7,442
Interest expense		(3,640	)		(3,189	)		(9,956	)		(9,225	)
Debt prepayment premium		—			—			—			(1,160	)
Other, net		54			78			205			330

Total other income (expense)		(850	)		(391	)		(2,547	)		(2,613	)

Net income before taxes		5,715			4,329			17,785			13,865
Income taxes		212			—			552			—

Net income	$	5,503		$	4,329		$	17,233		$	13,865


General partner’s interest in net income	$	465		$	218		$	1,094		$	702
Limited partners’ interest in net income	$	5,038		$	4,111		$	16,139		$	13,163

Net income per limited partner unit — basic and diluted	$	0.35		$	0.32		$	1.17		$	1.05

Weighted average limited partner units — basic		14,532,826			12,682,342			13,845,573			12,555,968
Weighted average limited partner units — diluted		14,536,939			12,684,889			13,849,749			12,558,601

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)
(Dollars in thousands)


														Accumulated
	Partners’ Capital													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		—		9,635			—		3,528			702			—			13,865

Follow-on public offering		3,450,000		95,272			—		—			—			—			95,272

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

Unit-based compensation		3,000		17			—		—			—			—			17

Cash distributions		—		(16,987	)		—		(6,227	)		(830	)		—			(24,044	)

Change in other comprehensive income		—		—			—		—			—			(316	)		(316	)


Balances – September 30, 2006		9,282,652	$	188,143			3,402,690	$	(8,341	)	$	2,925		$	(316	)	$	182,411


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

Net Income		—		13,454			—		2,685			1,094			—			17,233

Follow-on public offering		1,380,000		55,933			—		—			—			—			55,933

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

Unit-based compensation		3,000		34			—		—			—			—			34

Cash distributions		—		(21,272	)		—		(4,900	)		(1,223	)		—			(27,395	)

Change in other comprehensive income		—		—			—		—			—			(2,172	)		(2,172	)


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

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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Net income	$	5,503		$	4,329		$	17,233		$	13,865
Changes in fair values of commodity cash flow hedges		(543	)		796			(900	)		244
Cash flow hedging gains (losses) reclassified to earnings		234			(39	)		(198	)		(3	)
Changes in fair value of interest rate cash flow hedges		(2,056	)		(1,554	)		(1,074	)		(557	)


Comprehensive income	$	3,138		$	3,532		$	15,061		$	13,549

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)
(Dollars in thousands)


	Nine Months Ended
	September 30,
	2007			2006
Cash flows from operating activities:
Net income	$	17,233		$	13,865

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		16,598			12,784
Amortization of deferred debt issuance costs		810			770
Deferred taxes		(111	)		—
Gain on involuntary conversion of property, plant and equipment		—			(853	)
Equity in earnings of unconsolidated entities		(7,204	)		(7,442	)
Distributions from unconsolidated entities		673			506
Distributions in-kind from equity investments		6,628			6,710
Non-cash derivatives (gain) loss		2,036			(154	)
Other		45			15
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		(4,899	)		18,695
Product exchange receivables		(4,067	)		(4,754	)
Inventories		(6,346	)		(5,830	)
Due from affiliates		(1,787	)		(312	)
Other current assets		(167	)		90
Trade and other accounts payable		22,429			(21,656	)
Product exchange payables		(2,388	)		4,903
Due to affiliates		(5,055	)		4,967
Income taxes payable		365			—
Other accrued liabilities		903			(5,747	)
Change in other non-current assets and liabilities		(94	)		(148	)

Net cash provided by operating activities		35,602			16,409


Cash flows from investing activities:
Payments for property, plant and equipment		(57,524	)		(53,511	)
Acquisitions, net of cash acquired		(37,344	)		(16,544	)
Proceeds from sale of property, plant and equipment		4			770
Insurance proceeds from involuntary conversion of property, plant and equipment		—			2,541
Return of investments from unconsolidated entities		2,642			330
Investments in unconsolidated entities		(6,130	)		(7,344	)

Net cash used in investing activities		(98,352	)		(73,758	)


Cash flows from financing activities:
Payments of long-term debt		(125,105	)		(105,810	)
Proceeds from long-term debt		161,050			84,619
Payments of debt issuance costs		—			(371	)
Net proceeds from follow on public offering		55,933			95,272
General partner contribution		1,192			2,052
Cash distributions paid		(27,395	)		(24,044	)

Net cash provided by financing activities		65,675			51,718


Net increase (decrease) in cash		2,925			(5,631	)
Cash at beginning of period		3,675			6,465

Cash at end of period	$	6,600		$	834

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 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 $8 and $7 for the three months ended September 30, 2007 and 2006, respectively, and $34 and $17 for the nine months ended September 30, 2007 and 2006, respectively. The Partnership’s general partner contributed cash of $2 in January 2006 and $3 in May 2007 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.

(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

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

quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months ended September 30, 2007 and 2006 the general partner received $362 and $134, respectively, in incentive distributions. For the nine months ended September 30, 2007 and 2006, the general partner received and $764 and $403, respectively, in incentive distributions.

(d) Net Income per Unit

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

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

The weighted average units outstanding for basic net income per unit were 14,532,826 and 12,682,342 for the three months ended September 30, 2007 and 2006, respectively, and 13,845,573 and 12,555,968 for the nine months ended September 30, 2007 and 2006, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 4,113 and 2,547 for the three months ended September 30, 2007 and 2006, respectively, and 4,176 and 2,633 for the nine months ended September 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)
September 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 two three-year non-competition agreements totaling $530 and goodwill of $1,020, was allocated as follows:


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

Total	$	4,738

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

(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 four two-year non-competition agreements and other intangibles reflected as other assets, was allocated as follows:


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

Total	$	32,606

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

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

(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

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

(“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 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 September 30, 2007 and December 31, 2006 were as follows:


	September 30,		December 31,
	2007		2006
Natural Gas Liquids	$	22,680	$	17,061
Sulfur		4,687		4,397
Fertilizer — raw materials and packaging		1,899		2,412
Fertilizer — finished goods		4,566		4,807
Lubricants		4,556		2,592
Other		1,459		1,750

	$	39,847	$	33,019

(4) Investment in Unconsolidated Partnerships and Joint Ventures

The Partnership, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”) 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 for approximately $196 a 20% ownership interest in a partnership 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. which is the 42.5% interest owner. This interest is accounted for under the equity method of accounting.

In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $147 and $444 for the

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

three months and nine months ended September 30, 2007, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $10,834 and $11,279 at September 30, 2007 and December 31, 2006, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in the first nine months of 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		(6,628	)		—			—			—			(6,628	)
Cash contributions		6,023			—			—			107			6,130
Cash distributions		(2,625	)		(565	)		(125	)		—			(3,315	)
Equity in earnings:
Equity in earnings (losses) from operations		7,205			464			78			(99	)		7,648
Amortization of excess investment		(412	)		(11	)		(21	)		—			(444	)


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


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

Distributions in kind		(6,710	)		—			—			—			(6,710	)
Cash contributions		7,148			—			—			196			7,344
Cash distributions		(149	)		(177	)		(510	)		—			(836	)
Equity in earnings:
Equity in earnings (losses) from operations		7,043			96			330			(27	)		7,442


Investment in unconsolidated entities, September 30, 2006	$	61,419		$	1,642		$	3,889		$	169		$	67,119

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


					Three Months Ended				Nine months ended
	As of September 30,				September 30,				September 30,
	Total		Partner’s				Net				Net
	Assets		Capital		Revenues		Income		Revenues		Income
2007
Waskom	$	64,191	$	53,400	$	21,293	$	5,808	$	54,466	$	14,410


	As of December 31,
2006
Waskom	$	53,260	$	45,450	$	18,654	$	5,453	$	52,924	$	14,533

(5) Commodity Cash Flow Hedges

The Partnership is exposed to market risks associated with commodity prices, counterparty credit and interest rates. Until December 2005, the Partnership had not engaged in commodity contract trading or hedging activities. However, in connection with the acquisition of Prism Gas at that time, the Partnership has established a hedging policy and monitors and manages the commodity market risk associated with the

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

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 September 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 nine months ended September 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 commodity 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					Nine Months
	Ended					Ended
	September 30					September 30
	2007			2006		2007			2006
Change in fair value of derivatives that do not qualify for hedge accounting	$	(454	)	$	753	$	(1,619	)	$	150
Ineffective portion of derivatives qualifying for hedge accounting		(199	)		39		(109	)		3
Gain (loss) on cash settlements of derivatives		(118	)		76		254			547


Change in fair value of derivatives in the Consolidated Statement of Operations	$	(771	)	$	868	$	(1,474	)	$	700

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


	September 30,			December 31,
	2007			2006
Fair value of derivative assets — current	$	104		$	882
Fair value of derivative assets — long term		1			221
Fair value of derivative liabilities — current		(1,336	)		—
Fair value of derivative liabilities — long term		(567	)		(74	)

Net fair value of derivatives	$	(1,798	)	$	1,029

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2007 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of September 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 nine months ended September 30, 2007, changes in

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

the fair value of the Partnership’s derivative contracts were recorded in both earnings and in other comprehensive income as a component of equity since the Partnership has designated a portion of its derivative instruments as hedges as of September 30, 2007.

September 30, 2007

Total

Transaction

Volume

Remaining Terms

Type

Per Month

Pricing Terms

of Contracts

Fair Value

Mark to Market Derivatives:

Ethane Swap

8,000 BBL

Fixed price of $28.04 settled against Mt. Belvieu Purity Ethane average monthly postings

October 2007 to December 2007

(232

)

Crude Oil swap

5,000 BBL

Fixed price of $65.95 settled against WTI NYMEX average monthly closings

October 2007 to December 2007

(219

)

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.

October 2007 to December 2007

104

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

(41

)

Crude Oil Swap

3,000 BBL

Fixed price of $70.75 settled against WTI NYMEX average monthly closings

January 2008 to December 2008

(211

)

Crude Oil Swap

3,000 BBL

Fixed price of $69.08 settled against WTI NYMEX average monthly closings

January 2009 to December 2009

(148

)

Crude Oil Swap

3,000 BBL

Fixed price of $70.90 settled against WTI NYMEX average monthly closings

January 2009 to December 2009

(91

)

Total swaps not receiving hedge accounting

(838

)

Cash Flow Hedges:

Crude Oil Swap

4,000 BBL

Fixed price of $72.35 settled against WTI NYMEX average monthly closings

October 2007 to December 2007

(35

)

Crude Oil Swap

5,000 BBL

Fixed price of $66.20 settled against WTI NYMEX average monthly closings

January 2008 to December 2008

(609

)

Ethane Swap

5,000 BBL

Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings

January 2008 to December 2008

(222

)

Crude Oil Swap

1,000 BBL

Fixed price of $70.45 settled against WTI NYMEX average monthly closings

January 2009 to December 2009

(35

)

Crude Oil Swap

2,000 BBL

Fixed price of $69.15 settled against WTI NYMEX average monthly closings

January 2010 to December 2010

(60

)

Crude Oil Swap

3,000 BBL

Fixed price of $72.25 settled against WTI NYMEX average monthly closings

January 2010 to December 2010

Total swaps receiving hedge accounting

(960

)

Total net fair value of derivatives

(1,798

)

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.

Through its Prism Gas subsidiary, the Partnership is exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales activities. Prism Gas gathering and processing revenues are earned under various contractual

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

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 September 30, 2007, Prism Gas had hedged approximately 50%, 50%, 22% and 16% 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 Gasoline	4,000 BBL/Month	Crude Oil Swap ($72.35)	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	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($72.25)	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 September 30, 2007 and 2006, net gains and losses on swap hedge contracts decreased crude revenue by $653 and increased crude revenue by $396, respectively. For the nine month periods ending September 30, 2007 and 2006 net gains and losses on swap hedge contracts decreased crude revenue by $1,004 and $158, respectively. As of September 30, 2007 an unrealized derivative fair value loss of $505, 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 2007, 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)
September 30, 2007
(Unaudited)

Natural Gas

For the three month periods ended September 30, 2007 and 2006, net gains and losses on swap hedge contracts increased gas revenue by $146 and $491, respectively. For the nine month periods ended September 30, 2007 and 2006, net losses and gains on swap hedge contracts decreased gas revenue by $96 and increased gas revenue by $921, respectively. As of September 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 September 30, 2007 and 2006, net gains and losses on swap hedge contracts decreased liquids revenue by $264 and $19, respectively. For the nine month periods ended September 30, 2007 and 2006, net gains and losses on swap hedge contracts decreased liquids revenue by $374 and $63, respectively. As of September 30, 2007 an unrealized derivative fair value loss of $222, 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 September 2007, the Partnership entered into a cash flow hedge agreement with a notional amount of $25,000 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 September 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 4.605% 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 November 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 November 2006, the Partnership entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006; therefore, hedge accounting was not utilized. The swap has been recorded at fair value at September 30, 2007 with an offset to current operations.

In March 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

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

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.

For the three months ended September 30, 2007, the Partnership recognized an increase in interest expense of $387 and for the nine months ended September 30, 2007, the Partnership recognized a decrease in interest expense of $44, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate hedges. During both the three and nine months ended September 30, 2006, we recognized increases in interest expense of less than $0.1 million related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps.

The net fair value of the interest rate swap agreements was recorded as a liability of approximately $(1,464) and $(83) at September 30, 2007 and December 31, 2006, respectively.

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


	September 30,			December 31,
	2007			2006
Fair value of derivative assets — current	$	110		$	377

Fair value of derivative assets — long term		—			112
Fair value of derivative liabilities — current		(168	)		—
Fair value of derivative liabilities — long term		(1,406	)		(572	)

Net fair value of derivatives	$	(1,464	)	$	(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				Nine months ended
	September 30,				September 30,
	2007		2006		2007		2006
Revenues:
Terminalling and storage	$	3,092	$	2,323	$	8,360	$	6,620
Marine transportation		5,409		3,592		18,096		9,201
Product sales:
Natural gas services		1,483		372		2,124		500
Sulfur		304		—		304		—
Fertilizer		289		—		388		24
Terminalling and storage		14		29		24		50

		2,090		401		2,840		574

	$	10,591	$	6,316	$	29,296	$	16,395


Costs and expenses:
Cost of products sold:
Natural gas services	$	15,857	$	13,826	$	41,713	$	41,768
Sulfur		1,483		1,510		3,731		4,571
Fertilizer		1,682		1,453		6,723		4,587
Terminalling and storage		—		—		—		1

	$	19,022	$	16,789	$	52,167	$	50,927


Expenses:
Operating expenses
Marine transportation	$	5,932	$	5,723	$	15,217	$	15,691

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


	Three Months Ended				Nine months ended
	September 30,				September 30,
	2007		2006		2007		2006
Natural gas services		365		372		1,128		1,180
Sulfur		307		215		826		567
Fertilizer		27		23		114		98
Terminalling and storage		1,437		1,050		3,612		2,890

	$	8,068	$	7,383	$	20,897	$	20,426


Selling, general and administrative:
Natural gas services	$	225	$	166	$	566	$	499
Sulfur		94		114		281		334
Fertilizer		283		288		880		853
Terminalling and storage		13		16		41		55
Indirect overhead allocation, net of reimbursement		326		326		978		978

	$	941	$	910	$	2,746	$	2,719

(8) Business Segments

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

The accounting policies of the operating segments are the same as those described in Note 19 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2006 filed with the SEC on March 5, 2007. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.


						Operating				Operating
						Revenues		Depreciation		Income (loss)
	Operating		Intersegment			after		and		after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Three months ended September 30, 2007
Terminalling and storage	$	18,788	$	(267	)	$	18,521	$	1,700	$	2,411		$	7,695
Natural gas services		120,994		—			120,994		970		1,676			1,444
Marine transportation		16,459		(990	)		15,469		2,377		944			8,361
Sulfur		20,283		(651	)		19,632		769		1,623			49
Fertilizer		10,413		(179	)		10,234		420		752			3,203
Indirect selling, general and administrative		—		—			—		—		(841	)		—


Total	$	186,937	$	(2,087	)	$	184,850	$	6,236	$	6,565		$	20,752


Three months ended September 30, 2006
Terminalling and storage	$	9,465	$	(98	)	$	9,367	$	1,224	$	2,398		$	3,637
Natural gas services		102,217		—			102,217		438		714			1,490
Marine transportation		13,100		(151	)		12,949		1,706		1,233			3,365
Sulfur		13,963		(247	)		13,716		801		963			2,639
Fertilizer		9,396		(140	)		9,256		408		206			4,627
Indirect selling, general and administrative		—		—			—		—		(794	)		—

Total	$	148,141	$	(636	)	$	147,505	$	4,577	$	4,720		$	15,758


						Operating				Operating
						Revenues		Depreciation		Income (loss)
	Operating		Intersegment			after		and		after		Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations		Expenditures
Nine months ended September 30, 2007
Terminalling and storage	$	41,252	$	(501	)	$	40,751	$	4,506	$	7,951	$	18,978
Natural gas services		328,103		—			328,103		2,271		4,084		3,038
Marine transportation		47,231		(2,724	)		44,507		6,280		3,347		24,004
Sulfur		52,944		(1,229	)		51,715		2,290		2,820		1,020
Fertilizer		38,621		(737	)		37,884		1,251		4,577		10,484

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


						Operating				Operating
						Revenues		Depreciation		Income (loss)
	Operating		Intersegment			after		and		after			Capital
	Revenues		Eliminations			Eliminations		Amortization		eliminations			Expenditures
Indirect selling, general and administrative		—		—			—		—		(2,447	)		—


Total	$	508,151	$	(5,191	)	$	502,960	$	16,598	$	20,332		$	57,524


Nine months ended September 30, 2006
Terminalling and storage	$	26,229	$	(300	)	$	25,929	$	3,393	$	7,475		$	10,179
Natural gas services		288,199		—			288,199		1,242		1,918			5,039
Marine transportation		34,030		(860	)		33,170		4,745		3,628			15,351
Sulfur		47,960		(961	)		46,729		2,189		4,514			12,161
Fertilizer		33,670		(318	)		33,352		1,215		1,303			10,781
Indirect selling, general and administrative		—		—			—		—		(2,360	)		—


Total	$	429,818	$	(2,439	)	$	427,379	$	12,784	$	16,478		$	53,511

The following table reconciles operating income to net income:


	Three Months Ended						Nine months ended
	September 30						September 30
	2007			2006			2007			2006
Operating income	$	6,565		$	4,720		$	20,332		$	16,478
Equity in earnings of unconsolidated entities		2,736			2,720			7,204			7,442
Interest expense		(3,640	)		(3,189	)		(9,956	)		(9,225	)
Debt prepayment premium		—			—			—			(1,160	)
Other, net		54			78			205			330
Income taxes		(212	)		—			(552	)		—

Net income	$	5,503		$	4,329		$	17,233		$	13,865

Total assets by segment are as follows:


	September 30,		December 31,
	2007		2006
Total assets:
Terminalling and storage	$	117,867	$	89,354
Natural gas services		239,018		184,464
Marine transportation		98,021		77,668
Sulfur		61,659		62,210
Fertilizer		53,722		43,765

Total assets	$	570,287	$	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 $55,933. The Partnership’s general partner contributed $1,190 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital.

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

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


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

Total proceeds received	$	59,495


*Use of Proceeds:*
Underwriter’s fees	$	2,107
Professional fees and other costs		265
Repayment of debt under revolving credit facility		55,850
Working capital		1,273

Total use of proceeds	$	59,495

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

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


	September 30,		December 31,
	2007		2006
*$120,000 Revolving loan facility at variable interest rate (6.91% weighted average at September 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	$	80,000	$	44,000
**$130,000 Term loan facility at variable interest rate (7.16% at September 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%		40		95

Total long-term debt		210,040		174,095
Less current installments		40		74

Long-term debt, net of current installments	$	210,000	$	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 prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. Effective October 1, 2007, the applicable margin for existing borrowings will decrease to 1.75%. As a result of our leverage ratio test, effective January 1, 2008, the applicable margin for existing borrowings will increase to 2.00%. The Partnership incurs a commitment fee on the unused portions of the credit facility.

**		Effective September, 2007, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in September, 2010.

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

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

On 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, the Partnership increased its 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 September 30, 2007, the Partnership had $80,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of September 30, 2007, the Partnership had $39,880 available under its revolving credit facility.

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

The Partnership’s obligations under the credit facility are secured by substantially all of the

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

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 with the debt covenants contained in credit facility for the year ended December 31, 2006 and as of September 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 September 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 September 30, 2007, the Partnership had $39,880 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 L.P. (“CF Martin Sulphur”). The outstanding balance as of December 31, 2005 was $9,104. These bonds were payable in equal semi-annual installments of $291, and were secured by certain marine vessels owned by CF Martin Sulphur. Pursuant to the terms of an amendment to the Partnership’s credit facility that it entered into in connection with the acquisition of CF Martin Sulphur, the Partnership was obligated to repay these bonds by March 31, 2006. The Partnership redeemed these bonds on March 6, 2006 with available cash and borrowings from its credit facility. Also, at redemption, a pre-payment premium was paid in the amount of $1,160.

The Partnership paid cash interest in the amount of $2,777 and $2,874 for the three months ended September 30, 2007 and 2006, respectively, and $8,722 and $9,135 for the nine months ended September 30, 2007 and 2006, respectively. Capitalized interest was $826 and $300 for the three months ended

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

September 30, 2007 and 2006, respectively, and $2,171 and $970 for the nine months ended September 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 were $100 and $114 for the three and nine month periods ended September 30, 2007, respectively. In connection with the Woodlawn acquisition, the Partnership also established deferred taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment. A deferred tax benefit related to these basis differences of $43 and $111 was recorded for the three and nine month periods ended September 30, 2007, respectively, and a deferred tax liability of $8,853 related to the basis differences existing at September 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 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 $0 and $173 resulting from the liquidation were recorded in current year income tax expense for the three and nine months ending September 30, 2007, respectively.

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 $143 and $412 were recorded in current year income tax expense for the three and nine months ending September 30, 2007.

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

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

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


	Three Months			Nine Months
	Ended			Ended
	2007			2007
Current:
Federal	$	80		$	237
State		175			426

	$	254		$	662

Deferred:
Federal	$	(43	)	$	(111	)

	$	212		$	552

(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 September 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 collectability of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and historical collection experience. Based on these assessments, we record specific 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 $13.6 million of direct costs and expenses for the three months ended September 30, 2007 compared to $12.9 million for the three months ended September 30, 2006. We reimbursed Martin Resource Management for $38.9 million of direct costs and expenses for the nine months ended September 30, 2007 compared to $37.4 million for the nine months ended September 30, 2006. In addition, the Partnership purchased NGL’s from Waskom Gas Processing totaling $14.1 million for the three months ended September 30, 2007 compared to $11.8 million for the three months ended September 30, 2006; and approximately $35.9 million for the nine months ended September 30, 2007 compared to $35.7 million for the nine months ended September 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 November 6, 2007, we have not increased this cap. We reimbursed Martin Resource Management for $0.3 million of indirect expenses for both the three months ended September 30, 2007 and 2006. We reimbursed Martin Resource Management for $1.0 million of indirect expenses for both the nine months ended September 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 1.5 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

In the aggregate, our purchases of land transportation services, NGL storage services, sulfuric acid and lube oil product purchases and sulfur and fertilizer payroll reimbursements from Martin Resource Management accounted for approximately 13% and 14% of our total cost of products sold during the three months ended September 30, 2007 and 2006, respectively; and approximately 13% and 15% of our total cost of products sold

during the nine months ended September 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 September 30, 2007 and 2006, respectively. Our sales to Martin Resource Management accounted for approximately 6% and 4% of our total revenues for the nine months ended September 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 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 nine months ended September 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 nine months ended September 30, 2007 and 2006. The results of operations for the first nine months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.


											Operating			Operating
			Revenues			Operating					Income			Income (loss)
	Operating		Intersegment			Revenues		Operating			Intersegment			after
	Revenues		Eliminations			after Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)
Three months ended September 30, 2007
Terminalling and storage	$	18,788	$	(267	)	$	18,521	$	2,631		$	(220	)	$	2,411
Natural gas services		120,994		—			120,994		1,547			129			1,676
Marine transportation		16,459		(990	)		15,469		1,805			(861	)		944
Sulfur		20,283		(651	)		19,632		1,304			319			1,623
Fertilizer		10,413		(179	)		10,234		119			633			752
Indirect selling, general and administrative		—		—			—		(841	)		—			(841	)

Total	$	186,937	$	(2,087	)	$	184,850	$	6,565		$	—		$	6,565


											Operating			Operating
			Revenues			Operating					Income			Income (loss)
	Operating		Intersegment			Revenues		Operating			Intersegment			after
	Revenues		Eliminations			after Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)
Three months ended September 30, 2006
Terminalling and storage	$	9,465	$	(98	)	$	9,367	$	2,451		$	(53	)	$	2,398
Natural gas services		102,217		—			102,217		714			—			714
Marine transportation		13,100		(151	)		12,949		1,384			(151	)		1,233
Sulfur		13,963		(247	)		13,716		923			40			963
Fertilizer		9,396		(140	)		9,256		42			164			206
Indirect selling, general and administrative		—		—			—		(794	)		—			(794	)


Total	$	148,141	$	(636	)	$	147,505	$	4,720		$	—		$	4,720


						Operating					Operating			Operating
			Revenues			Revenues					Income			Income (loss)
	Operating		Intersegment			after		Operating			Intersegment			after
	Revenues		Eliminations			Eliminations		Income (loss)			Eliminations			Eliminations
	(In thousands)
Nine months ended September, 2007
Terminalling and storage	$	41,252	$	(501	)	$	40,751	$	8,128		$	(177	)	$	7,951
Natural gas services		328,103		—			328,103		3,955			129			4,084
Marine transportation		47,231		(2,724	)		44,507		5,889			(2,542	)		3,347
Sulfur		52,944		(1,229	)		51,715		1,468			1,352			2,820
Fertilizer		38,621		(737	)		37,884		3,339			1,238			4,577
Indirect selling, general and administrative		—		—			—		(2,447	)		—			(2,447	)


Total	$	508,151	$	(5,191	)	$	502,960	$	20,332		$	—		$	20,332


Nine months ended September 30, 2006
Terminalling and storage	$	26,229	$	(300	)	$	25,929	$	7,598		$	(123	)	$	7,475
Natural gas services		288,199		—			288,199		1,918			—			1,918
Marine transportation		34,030		(860	)		33,170		4,488			(860	)		3,628
Sulfur		47,690		(961	)		46,729		3,804			710			4,514
Fertilizer		33,670		(318	)		33,352		1,030			273			1,303
Indirect selling, general and administrative		—		—			—		(2,360	)		—			(2,360	)


Total	$	429,818	$	(2,439	)	$	427,379	$	16,478		$	—		$	16,478

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

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

Our total revenues before eliminations were $186.9 million for the three months ended September 30, 2007 compared to $148.1 million for the three months ended September 30, 2006, an increase of $38.8 million, or 26%. Our operating income before eliminations was $6.6 million for the three months ended September 30, 2007 compared to $4.7 million for the three months ended September 30, 2006, an increase of $1.9 million, or 40%.

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

Terminalling and Storage Segment

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


	Three Months Ended
	September 30,
	2007		2006
	(In thousands)
Revenues:
Services	$	7,570	$	6,163
Products		11,218		3,302

Total revenues		18,788		9,465

Cost of products sold		10,003		2,595
Operating expenses		4,406		3,164
Selling, general and administrative expenses		48		31
Depreciation and amortization		1,700		1,224

		2,631		2,451

Other operating income		—		—

Operating income	$	2,631	$	2,451

Revenues. Our terminalling and storage revenues increased $9.3 million, or 98%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. Service revenue accounted for $1.4 million of this increase due to new capital projects being placed into service during 2007. Product revenue increased $7.9 million primarily due to our acquisition of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) and an increase in product cost that was able to be passed along to our customers.

Cost of products sold. Our cost of products sold increased $7.4 million, or 285%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. This increase was due to our Mega Lubricants acquisition and an increase in product cost.

Operating expenses. Operating expenses increased $1.2 million, or 39%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. The increase was due primarily to $0.4 million of additional operating expenses from the acquisition of our Mega Lubricants terminal and increased salaries, property and liability premiums, product handling costs and repairs and maintenance related to increased activity at our existing terminals.

Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for both three month periods ended September 30, 2007 and 2006.

Depreciation and amortization. Depreciation and amortization increased $0.5 million, or 39%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. The increase was primarily a result of our Mega Lubricants acquisition and other capital expenditures.

In summary, our terminalling operating income increased $0.2 million, or 7%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006.

Natural Gas Services Segment

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


	Three Months Ended
	September 30,*
	2007			2006
	(In thousands)
Revenues:
NGLs	$	109,822		$	97,522
Natural gas		11,352			3,348
Non-cash mark to market adjustment of commodity derivatives		(653	)		792
Gain (loss) on cash settlements of commodity derivatives		(118	)		76
Other operating fees		591			479

Total revenues		120,994			102,217


	Three Months Ended
	September 30,*
	2007		2006
	(In thousands)
Cost of products sold:
NGLs		104,469		95,639
Natural gas		10,771		3,000

Total cost of products sold		115,240		98,639

Operating expenses		1,968		1,240
Selling, general and administrative expenses		1,269		1,186
Depreciation and amortization		970		438

Operating income	$	1,547	$	714


NGLs Volumes (Bbls)		1,870		1,839

Natural Gas Volumes (Mmbtu)		1,897		548


*Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments which are included in Equity in Earnings of Unconsolidated Entities detailed below.

Equity in Earnings of Unconsolidated Entities	$	2,736	$	2,720


Waskom:
Plant Inlet Volumes (Mmcf/d)		252		194

Frac Volumes (Bbls/d)		9,301		7,908

Revenues. Our natural gas services revenues increased $18.8 million, or 18% for the three months ended September 30, 2007 compared to this same period of 2006 due to increased natural gas and NGL volumes, in addition to higher commodity prices.

For the three months ended September 30, 2007, NGL revenues increased $12.3 million, or 13% and natural gas revenues increased $8.0 million, or 239%, compared to three months ended September 30, 2006. NGL sales volumes for the three months of 2007 increased 2% and natural gas volumes increased 246% compared to the same period of 2006. During the third quarter of 2007, our NGL average sales price per barrel increased $5.70, or 11%, and our natural gas average sales price per Mmbtu decreased $0.13, or 2%, compared to the same period of 2006. The increase in NGL volumes is primarily due to increased industrial demand experienced during the third quarter of 2007 and the increase in natural gas volumes is primarily due to the Woodlawn acquisition.

Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the third quarter of 2007, 46% of our total natural gas volumes and 53% of our total NGL volumes were hedged as compared to 53% and 64%, respectively, in 2006. The impact of price risk management and marketing activities decreased total natural gas and NGL revenues $0.8 million during the third quarter of 2007 compared to a net increase of $0.9 million in the same period of 2006.

Costs of product sold. Our cost of products increased $16.6 million, or 17%, for the third quarter of 2007 compared to the same period of 2006. Of the increase, $8.8 million relates to NGLs and $7.8 million relates to natural gas. The increase of $8.8 million in NGLs was less than our percentage increase in NGL revenues as a result of our NGL per barrel margins increasing $1.84 per barrel, or 180%, primarily due to the terms of Woodlawn’s producer contracts stemming from the Woodlawn acquisition and continued rising NGL prices in 2007. The remaining increase of $7.8 million relating to natural gas is greater than our percentage of natural gas revenue increase and is primarily due to the Woodlawn acquisition which contributed to a per Mmbtu margin decrease of 52% related to the terms of Woodlawn’s producer contracts compared to our historical producer contracts.

Operating expenses. Operating expenses increased $0.7 million, or 59%, for the third quarter of 2007 compared to the same period of 2006. This increase is primarily due to the Woodlawn acquisition.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.08 million, or 7%, for the three months ended September 30, 2007 compared to the same period of 2006.

This increase primarily is primarily due to the Woodlawn acquisition.

Depreciation and amortization. Depreciation and amortization increased $0.5 million, or 122%, for the three months ended September 30, 2007 compared to the same period of 2006. This increase was primarily a result of the Woodlawn acquisition.

In summary, our natural gas services operating income increased $0.8 million, or 117%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities for the three months ended September 30, 2007 and 2006 were flat. 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, we, through our Prism Gas subsidiary, acquired a 20% ownership interest in a partnership that owns the lease rights to 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
	September 30,
	2007		2006
	(In thousands)
Revenues	$	16,459	$	13,100
Operating expenses		12,141		9,861
Selling, general and administrative expenses		136		149
Depreciation and amortization		2,377		1,706

Operating income	$	1,805	$	1,384

Revenues. Our marine transportation revenues increased $3.4 million, or 26%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. Our inland marine operations generated an additional $2.7 million in revenue from increased utilization of our fleet as a result of a geographical redistribution of our assets on the gulf coast and increased contract rates. Our offshore revenues increased $0.5 million.

Operating expenses. Operating expenses increased $2.3 million, or 23%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. We experienced increases in operating costs from repairs and maintenance and crew wages and the related salary burden.

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

Depreciation and Amortization. Depreciation and amortization increased $0.7 million, or 39%, for the three months ended September 30, 2007 compared to the three months ended September 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 $0.4 million, or 30%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006.

Sulfur Segment

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


	Three Months Ended
	September 30,
	2007		2006
	(In thousands)
Revenues	$	20,283	$	13,963
Cost of products sold		14,029		8,685
Operating expenses		3,982		3,303
Selling, general and administrative expenses		199		251
Depreciation and amortization		769		801

Operating income	$	1,304	$	923


Sulfur Volumes (long tons)		271.3		189.9

Revenues. Our sulfur revenues increased $6.3 million, or 45%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. This increase resulted from a 43% increase in sales volume. The sales volume increase was due to a new sales contract negotiated in 2007.

Cost of products sold. Our cost of products sold increased $5.3 million, or 62%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. This percentage increase was more than our sales revenue percentage increase as our margin per ton fell due to competitive pressure.

Operating expenses. Our operating expenses increased $0.7 million, or 21%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. This increase was a result of increased marine transportation costs. These marine transportation cost increases related to crew wages and related salary burden and outside towing expenses for leased vessels.

Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.1 million, or 21%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006.

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

In summary, our sulfur operating income increased $0.4 million, or 41%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006.

Fertilizer Segment

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


	Three Months Ended
	September 30,
	2007		2006
	(In thousands)
Revenues	$	10,413	$	9,396
Cost of products sold and operating expenses		9,478		8,547
Selling, general and administrative expenses		396		399
Depreciation and amortization		420		408

Operating income	$	119	$	42


Fertilizer Volumes (tons)		55.9		34.9

Revenues. Our fertilizer revenues increased $1.0 million, or 11%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. Our sales volume increased 60% due to increased demand from our customers. This increased demand was driven by higher commodity prices in the agricultural markets we serve. Our margin per ton fell 31% from higher priced products sales that fell in the third quarter last year. We anticipate that comparable higher priced product sales will occur in the fourth quarter of 2007.

Cost of products sold and operating expenses. Our cost of products sold and operating expenses increased $0.9 million, or 11%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. Our margin per ton fell 31%. This was a result of selling our higher margin products in the third quarter of 2006. We anticipate that comparable sales will occur in the fourth quarter of 2007.

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

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

In summary our fertilizer operating income increased $0.1 million, or 183%, for the three months ended September 30, 2007 compared to the three months ended September 30, 2006.

Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006

Our total revenues before eliminations were $508.2 million for the nine months ended September 30, 2007 compared to $429.8 million for the nine months ended September 30, 2006, an increase of $78.4 million, or 18%. Our operating income before eliminations was $20.3 million for the nine months ended September 30, 2007 compared to $16.5 million for the nine months ended September 30, 2006, an increase of $3.8 million, or 23%.

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

Terminalling and Storage Segment

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


	Nine Months Ended
	September 30,
	2007		2006
	(In thousands)
Revenues:
Services	$	21,559	$	17,511
Products		19,693		8,718

Total revenues		41,252		26,229

Cost of products sold		17,107		7,043
Operating expenses		11,403		8,968
Selling, general and administrative expenses		108		80
Depreciation and amortization		4,506		3,393

		8,128		6,745

Other operating income		—		853

Operating income	$	8,128	$	7,598

Revenues. Our terminalling and storage revenues increased $15.0 million, or 57%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. Service revenue accounted for $4.0 million of this increase due to recent acquisitions and new capital projects being placed into service during the end of 2006 and the beginning of 2007. Product revenue increased $11.0 million primarily due to our Mega Lubricants acquisition and an increase in product cost that was able to be passed along to our customers.

Cost of products sold. Our cost of products increased $10.0 million, or 143%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. This increase was due to our Mega Lubricants acquisition and an increase in product cost.

Operating expenses. Operating expenses increased $2.4 million, or 27%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. The increase was due primarily to $1.2 million of additional operating expenses from the acquisitions of the Corpus Christi terminal and our Mega Lubricants terminal and increased salaries, property and liability premiums, product handling costs and repairs and maintenance related to increased activity at our existing terminals.

Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for both nine months periods.

Depreciation and amortization. Depreciation and amortization increased $1.1 million, or 33%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. The increase was primarily a result of recent acquisitions and capital expenditures.

Other operating income. Other operating income for the nine months ended September 30, 2006 consisted solely of a gain of $0.9 million related to an involuntary conversion of assets. This gain resulted from insurance proceeds which were greater than the impairment of assets destroyed by hurricanes Katrina and Rita.

In summary, terminalling and storage operating income increased $0.5 million, or 7%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.

Natural Gas Services Segment

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


	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)
Revenues:
NGLs	$	302,840		$	275,668
Natural gas		24,839			10,539
Non-cash mark to market adjustment of commodity derivatives		(1,728	)		153
Gain (loss) on cash settlements of commodity derivatives		254			547
Other operating fees		1,898			1,292

Total revenues		328,103			288,199

Cost of products sold:
NGLs		289,449			268,821
Natural gas		23,502			9,418

Total cost of products sold		312,951			278,239

Operating expenses		5,103			3,805
Selling, general and administrative expenses		3,823			2,995
Depreciation and amortization		2,271			1,242

Operating income	$	3,955		$	1,918


NGLs Volumes (Bbls)		5,742			5,623

Natural Gas Volumes (Mmbtu)		3,792			1,585


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

Equity in Earnings of Unconsolidated Entities	$	7,204		$	7,442


Waskom:
Plant Inlet Volumes (Mmcf/d)		222			187

Frac Volumes (Bbls/d)		8,258			8,159

Revenues. Our natural gas services revenues increased $39.9 million, or 14%, for the nine months ended September 30, 2007 compared to this same period of 2006 due to increased natural gas and NGL volumes, in addition to higher net commodity prices.

For the nine months ended September 30, 2007, NGLs revenues increased $27.1 million, or 9.9%, and natural gas revenues increased $14.3 million, or 136%, compared to the nine months ended September 30, 2006. NGLs sales volumes for the nine months of 2007 increased 2% and natural gas volumes increased 139% compared to the same period of 2006. During the first nine months of 2007, our NGLs average sales price per

barrel increased $3.30, or 7%, and our natural gas average sales price per Mmbtu decreased $0.10, or 2%, compared to the same period of 2006. The increase in NGL volumes is primarily due to increased industrial demand experienced during the first nine months of 2007 and the increase in natural gas volumes is primarily due to the Woodlawn acquisition.

Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the first nine months of 2007, 46% of our total natural gas volumes and 53% of our total NGL volumes were hedged as compared to 53% and 64%, respectively in 2006. The impact of price risk management and marketing activities decreased total natural gas, and NGLs revenues $1.5 million during the first nine months of 2007 compared to a net increase of $0.7 million in the same period of 2006.

Costs of product sold. Our cost of products increased $34.7 million, or 13%, for the nine months ended September 30, 2007 compared to the same period of 2006. Of the increase, $20.6 million relates to NGLs and $14.1 million relates to natural gas. The percentage increase in NGL cost of products sold is less than our percentage increase in NGL revenues as our NGL per barrel margins increased $1.11 per barrel, or 92%, primarily due to continued rising NGL prices in 2007. The percentage increase relating to natural gas cost of products sold is greater than the percentage increase in natural gas revenues which caused our Mmbtu margins to decrease by 50%, as a result of the terms of Woodlawn’s producer contracts compared to our historical producer contracts.

Operating expenses. Operating expenses increased $1.3 million, or 34%, for the nine months ended September 30, 2007 compared to the same period of 2006. This increase is primarily due to the Woodlawn acquisition.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.8 million, or 28%, for the nine months ended September 30, 2007 compared to the nine months same period of 2006. This increase primarily is primarily due to the Woodlawn acquisition.

Depreciation and amortization. Depreciation and amortization increased $1.0 million, or 83%, for the nine months ended September 30, 2007 compared to the same period of 2006. This increase was primarily a result of the Woodlawn acquisition.

In summary, our natural gas services operating income increased $2.0 million, or 106%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $7.2 and $7.4 million, for the nine months ended September 30, 2007 and 2006, respectively, a decrease of 3%. 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, we, through our Prism Gas subsidiary, acquired a 20% ownership interest in a partnership that owns the lease rights to 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.


	Nine Months Ended
	September 30,
	2007		2006
	(In thousands)
Revenues	$	47,231	$	34,030
Operating expenses		34,843		24,374
Selling, general and administrative expenses		219		423
Depreciation and amortization		6,280		4,745

Operating income	$	5,889	$	4,488

Revenues. Our marine transportation revenues increased $13.2 million, or 39%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. Our inland marine operations generated an additional $10.7 million in revenue from increased utilization of our fleet as a result of a geographical redistribution of our assets on the gulf coast, increased contract rates and operation of an additional number of leased vessels. Our offshore revenues increased $2.0 million primarily from the acquisition of two integrated tug barge units.

Operating expenses. Operating expenses increased $10.5 million, or 43%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. We experienced increases in operating costs from our outside towing expense for leased vessels, repairs and maintenance, and crew wages and related salary burden.

Selling, general, and administrative expenses. Selling, general and administrative expenses decreased $0.2 million, or 48%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.

Depreciation and Amortization. Depreciation and amortization increased $1.5 million, or 32%, for the nine months ended September 30, 2007 compared to the nine months ended September 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 $1.4 million, or 31%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.

Sulfur Segment

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


	Nine Months Ended
	September 30,
	2007		2006
	(In thousands)
Revenues	$	52,944	$	47,690
Cost of products sold		36,448		31,572
Operating expenses		12,185		9,372
Selling, general and administrative expenses		553		753
Depreciation and amortization		2,290		2,189

Operating income	$	1,468	$	3,804


Sulfur Volumes (long tons)		861.4		617.8

Revenues. Our sulfur revenues increased $5.3 million, or 11%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. This increase resulted from a 39% increase in sales volume offset by a 20% decrease in sales price. The sales volume increase was due to a new sales contract negotiated in 2007. The sales price decrease was a result of a change in the mix of the geographic locations in which we sell.

Cost of products sold. Our cost of products sold increased $4.9 million, or 15%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. This percentage increase was more than our sales revenue percentage increase as our margin per ton fell due to competitive pressure.

Operating expenses. Our operating expenses increased $2.8 million, or 30%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. This increase was a result of increased marine transportation costs. These marine transportation cost increases relate to crew wages and related salary burden due to two pay increases since June 2006, to outside towing expense incurred for leased vessels due to down time of owned vessels and increased demand for new vessels due to a new contract, and to repairs and maintenance on owned vessels to bring them up to higher quality standards adopted by our marine transportation group.

Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.2 million, or 27%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.

Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 5%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. This is attributable to the Neches priller conveyor system which was completed in August 2006.

In summary, our sulfur operating income decreased $2.3 million, or 61%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.

Fertilizer Segment

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


	Nine Months Ended
	September 30,
	2007		2006
	(In thousands)
Revenues	$	38,621	$	33,670
Cost of products sold and operating expenses		32,826		30,236
Selling, general and administrative expenses		1,205		1,188
Depreciation and amortization		1,251		1,216

Operating income	$	3,339	$	1,030


Fertilizer Volumes (tons)		202.3		163.3

Revenues. Our fertilizer revenues increased $5.0 million, or 15%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. Our sales volume increased 24% due to increased demand from our customers. Our price per ton fell 7% due to higher margin product sales in the third quarter of 2006. We anticipate that comparable higher priced product sales will occur in the fourth quarter of 2007.

Cost of products sold and operating expenses. Our cost of products sold and operating expenses increased $2.6 million, or 9%, for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. As demand for our products increased, we were able to spread our margins resulting in an increased margin per ton.

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

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

In summary our fertilizer operating income increased $2.3 million, or 224%, for the nine months ended September 30, 2007 compared to the nine months ended September 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 nine months ended September 30, 2007 and 2006 are as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Revenues		100	%		100	%		100	%		100	%
Cost of products sold		80	%		80	%		79	%		81	%
Operating expenses		12	%		12	%		13	%		11	%
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 nine months ended September 30, 2007 and 2006 equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom, Matagorda and PIPE. Also, included is equity in earnings of our unconsolidated interest in BCP for the three and nine months ended September 30, 2007.

Equity in earnings of unconsolidated entities was $2.7 million for both the three months ended September 30, 2007 and 2006.

Equity in earnings of unconsolidated entities was $7.2 million for the nine months ended September 30, 2007 compared to $7.4 million for the nine months ended September 30, 2006, a decrease of $0.2 million.

Interest Expense

Our interest expense for all operations was $3.6 million for the three months ended September 30, 2007 compared to the $3.2 million for the three months ended September 30, 2006, an increase of $0.4 million, or 13%. This increase was primarily due to an increase in average debt outstanding and a mark to market charge on interest rate swaps of $0.5 million which was offset by a decrease in interest rates in the three months of 2007 compared to the same period in 2006.

Our interest expense for all operations was $10.0 million for the nine months ended September 30, 2007 compared to the $9.2 million for the nine months ended September 30, 2006, an increase of $0.8 million, or 9%. This increase was primarily due to an increase in average debt outstanding and a mark to market charge on interest rate swaps of $0.3 million which was offset by a decrease in interest rates in the first nine months of 2007 compared to the same period in 2006.

Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses were $0.8 million and $2.4 million for both the three and nine months ended September 30, 2007 and 2006, respectively.

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 allocating 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 allocating 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. As of November 6, 2007, we have not increased this cap. Martin Resource Management allocated indirect selling, general and administrative expenses of $0.3 million for both three months ended September 30, 2007 and 2006. Martin Resource Management allocated indirect selling, general and administrative expenses of $1.0 million for both nine months ended September 30, 2007 and 2006.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

For the nine months ended September 30, 2007, cash increased $2.9 million as a result of $35.6 million provided by operating activities, $98.4 million used in investing activities and $65.7 million provided by financing activities. For the nine months ended September 30, 2006, cash decreased $5.6 million as a result of $16.4 million provided by operating activities, $73.8 million used in investing activities and $51.7 million provided by financing activities.

For the nine months ended September 30, 2007 our investing activities of $98.4 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, and investments in and returns of investments from unconsolidated partnerships. For the nine months ended September 30, 2006 our investing activities of $73.8 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, plant and equipment, insurance proceeds from involuntary conversion of property, plant and equipment, and investments in and returns of investments from unconsolidated partnerships.

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

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

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

For the nine months ended September 30, 2007 and 2006, our capital expenditures for property, plant and equipment were $89.7 million and $70.1 million, respectively.

As to each period:

	•		For the nine months ended September 30, 2007, we spent $82.9 million for expansion and $6.8 million for maintenance. Our expansion capital expenditures were made in connection with assets acquired in the Woodlawn and Mega Lubricants acquisitions, marine vessel purchases and conversions, construction projects associated with our terminalling business, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and include $0.2 million spent in connection with the restoration of vessels destroyed in hurricanes Rita and Katrina.

	•		For the nine months ended September 30, 2006, we spent $59.7 million for expansion and $10.4 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 $4.2 million in maintenance capital expenditures was spent in connection with restoration of assets destroyed in Hurricanes Rita and Katrina.

For the nine months ended September 30, 2007, our financing activities of $98.4 million consisted of cash distributions paid to common and subordinated unit holders of $27.4 million, net proceeds from a follow on equity offering of $55.9 million, payments of long term debt to financial lenders of $125.1 million, borrowings of long-term debt under our credit facility of $161.1 million and contributions of $1.2 million from our general partner.

For the nine months ended September 30, 2006, our financing activities consisted of cash distributions paid to common and subordinated unit holders of $24.0 million, net proceeds from a follow on equity offering of $95.3 million, payments of long term debt to financial lenders of $105.8 million, borrowings of long-term debt under our credit facility of $84.6 million, contributions of $2.1 million from our general partner and payments of debt issuance costs of $0.4 million.

We made investments in unconsolidated entities of $6.1 million and $7.3 million during the nine months ended September 30, 2007 and 2006, respectively. The net investment in unconsolidated entities includes $7.0 million and $5.8 million of expansion capital expenditures in the nine months ended September 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 September 30, 2007, we had $210.0 million of outstanding indebtedness, consisting of outstanding borrowings of $80.0 million under our revolving credit facility and $130.0 million under our term loan facility.

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

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

In 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” in our Form 10-K for the year ended December 31, 2006 filed with the SEC on March 5, 2007 for a discussion of such risks.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 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	$	80,000	$	—	$	—	$	80,000	$	—
Term loan facility		130,000		—		—		130,000		—
Other		40		40		—		—		—
Non-competition agreements		800		250		350		100		100
Operating leases		29,074		3,624		9,670		5,457		10,323
Interest expense(1)
Revolving Credit Facility		16,579		5,329		10,658		592		—
Term loan facility		27,943		8,982		17,963		998		—
Other		3		3		—		—		—


Total contractual cash obligations	$	284,439	$	18,228	$	38,641	$	217,147	$	10,423


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

Letter of Credit At September 30, 2007, we had an outstanding irrevocable letter of credit in the amount of $0.1 million which was issued under our revolving credit facility. This letter of credit was issued to the Texas Commission on Environmental Quality to provide financial assurance for our used oil handling program.

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

Description of Our Credit Facility

On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of credit sub-limit. Our credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25.0 million resulting in a committed $120.0 million revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of September 30, 2007, we had $80.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of September 30, 2007, we had $39.9 million available under our revolving credit facility.

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

Draws made under our credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on our credit facilities have ranged from a low of $170.6

million to a high of $226.9 million. As of September 30, 2007, we had $39.9 million available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility.

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

Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. Effective October 1, 2007, the applicable margin for existing borrowings will decrease to 1.75%. As a result of our leverage ratio test, effective January 1, 2008, the applicable margin for existing borrowings will increase to 2.00%. We incur a commitment fee on the unused portions of the credit facility.

Effective September 2007, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed rate. The fixed rate cost is 4.605% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in September, 2010 is accounted for using hedge accounting.

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

Effective November 2006, we entered into an interest rate swap that swaps $30.0 million of floating rate to fixed rate. The fixed rate cost is 4.765% plus our applicable LIBOR borrowing spread. This interest rate swap, which matures in March, 2010, is not accounted for using hedge accounting.

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

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

The credit facility also contains covenants, which, among other things, require us to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (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 November 5, 2007, our outstanding indebtedness includes $222.5 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 September 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 nine months ended September 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 September 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 September 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 September 30, 2007, Prism Gas had hedged approximately 50%, 50%, 22% and 16% 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 Gasoline	4,000 BBL/Month	Crude Oil Swap ($72.35)	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	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($72.25)	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 September 30, 2007. We had a total of $210.0 million of indebtedness outstanding under our credit facility as of the date hereof of which $40.0 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on September 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: November 6, 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 September 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).

3.2		First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 6, 2002 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).

3.3		Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 2, 2007, and incorporated herein by reference).

3.4		Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated September 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).

3.5		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).

3.6		Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated September 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).

3.7		Limited Liability Company Agreement of the General Partner, dated September 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).

3.8		Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated September 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).

3.9		Limited Liability Company Agreement of the Operating General Partner, dated September 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).

4.1		Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).

4.2		Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference).

31.1*		Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”

32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”

99.1*		Balance Sheets as of December 31, 2006 (audited) and March 31, 2007 (unaudited) of Martin Midstream GP LLC.


*		Filed or furnished herewith