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, 2006


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 9, 2006 was 9,282,652. The number of the registrant’s subordinated units outstanding at November 9, 2006 was 3,402,690.

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,
	2006			2005
	(Unaudited)			(Audited)
Assets
Cash	$	834		$	6,465
Accounts and other receivables, less allowance for doubtful accounts of $297 and $140		51,779			72,162
Product exchange receivables		6,895			2,141
Inventories		39,739			33,909
Due from affiliates		1,787			1,475
Other current assets		1,787			1,420

Total current assets		102,821			117,572


Property, plant and equipment, at cost		304,365			235,218
Accumulated depreciation		(71,657	)		(59,505	)

Property, plant and equipment, net		232,708			175,713


Goodwill		27,600			27,600
Investment in unconsolidated entities		67,119			59,879
Other assets, net		7,594			8,280

	$	437,842		$	389,044


Liabilities and Partners’ Capital

Current installments of long-term debt	$	73		$	9,104
Trade and other accounts payable		45,731			67,387
Product exchange payables		14,527			9,624
Due to affiliates		8,459			3,492
Income taxes payable		209			6,345
Other accrued liabilities		3,974			3,617

Total current liabilities		72,973			99,569


Long-term debt		180,040			192,200
Other long-term obligations		2,418			1,710

Total liabilities		255,431			293,479


Partners’ capital		182,727			95,565
Accumulated other comprehensive income		(316	)		—

Total partners’ capital		182,411			95,565


Commitments and contingencies
	$	437,842		$	389,044

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,
	2006			2005			2006			2005
Revenues:
Terminalling and storage	$	6,163		$	5,782		$	17,511		$	16,858
Marine transportation		12,949			8,578			33,170			26,634
Product sales:
Natural gas/LPG services		102,217			71,732			288,199			199,487
Sulfur		13,716			16,803			46,729			17,743
Fertilizer		9,256			7,565			33,352			25,980
Terminalling and storage		3,204			2,320			8,418			7,114

		128,393			98,420			376,698			250,324

Total revenues		147,505			112,780			427,379			293,816


Costs and expenses:
Cost of products sold:
Natural gas/LPG services		98,639			68,140			278,239			192,187
Sulfur		8,496			11,331			30,668			12,030
Fertilizer		8,243			6,343			29,645			21,955
Terminalling and storage		2,550			1,950			6,866			5,969

		117,928			87,764			345,418			232,141
Expenses:
Operating expenses		17,470			13,423			45,751			32,778
Selling, general and administrative		2,810			1,848			7,801			5,420
Depreciation and amortization		4,577			3,312			12,784			8,672

Total costs and expenses		142,785			106,347			411,754			279,011

Other operating income		—			—			853			—

Operating income		4,720			6,433			16,478			14,805


Other income (expense):
Equity in earnings of unconsolidated entities		2,720			27			7,442			222
Interest expense		(3,189	)		(1,639	)		(9,225	)		(3,834	)
Debt prepayment premium		—			—			(1,160	)		—
Other, net		78			25			330			127

Total other income (expense)		(391	)		(1,587	)		(2,613	)		(3,485	)


Net income	$	4,329		$	4,846		$	13,865		$	11,320


General partner’s interest in net income	$	218		$	97		$	702		$	226
Limited partners’ interest in net income	$	4,111		$	4,749		$	13,163		$	11,094

Net income per limited partner unit — basic and diluted	$	0.32		$	0.56		$	1.05		$	1.31

Weighted average limited partner units — basic		12,682,342			8,475,862			12,555,968			8,475,862
Weighted average limited partner units — diluted		12,684,889			8,475,862			12,558,601			8,475,862

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)


	Partners’ Capital

														Accumulated
														Other
											General			Comprehensive
	Common					Subordinated					Partner			Income
	Units		Amount			Units		Amount			Amount			Amount			Total
Balances – January 1, 2005		4,222,500	$	79,680			4,253,362	$	(4,772	)	$	626		$	—		$	75,534

Net Income		—		5,527			—		5,567			226			—			11,320

Cash distributions		—		(6,841	)		—		(6,890	)		(280	)		—			(14,011	)


Balances – September 30, 2005		4,222,500	$	78,366			4,253,362	$	(6,095	)	$	572		$	—		$	72,843


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	)

Commodity hedging gains reclassified to earnings		—		—			—		—			—			(3	)		(3	)

Adjustment in fair value of derivatives		—		—			—		—			—			(313	)		(313	)


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

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
	2006			2005
Cash flows from operating activities:
Net income	$	13,865		$	11,320

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		12,784			8,672
Amortization of deferred debt issuance costs		770			396
Gain on involuntary conversion of property, plant and equipment		(853	)		—
Equity in earnings of unconsolidated entities		(7,442	)		(222	)
Non-cash mark-to-market on derivatives		(154	)		—
Distributions in-kind from equity investments		6,710			—
Other		15			—
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:

Accounts and other receivables		18,695			261
Product exchange receivables		(4,754	)		(3,565	)
Inventories		(5,830	)		(6,454	)
Due from affiliates		(312	)		794
Other current assets		90			200
Trade and other accounts payable		(21,656	)		11,495
Product exchange payables		4,903			626
Due to affiliates		4,967			787
Other accrued liabilities		(5,747	)		412
Change in other non-current assets and liabilities		(148	)		(446	)

Net cash provided by operating activities		15,903			24,276


Cash flows from investing activities:
Payments for property, plant and equipment		(53,511	)		(12,264	)
Acquisitions, net of cash acquired		(16,544	)		(29,227	)
Proceeds from sale of property, plant and equipment		770			46
Insurance proceeds from involuntary conversion of property, plant and equipment		2,541			—
Escrow deposit for acquisition		—			(5,000	)
Investments in unconsolidated entities		(7,344	)		—
Distributions from unconsolidated entities		836			—

Net cash used in investing activities		(73,252	)		(46,445	)


Cash flows from financing activities:
Payments of long-term debt		(105,810	)		(16,691	)
Proceeds from long-term debt		84,619			53,200
Net proceeds from follow on public offering		95,272			—
Payments of debt issuance costs		(371	)		(397	)
General partner contribution		2,052			—
Cash distributions paid		(24,044	)		(14,011	)

Net cash provided by financing activities		51,718			22,101


Net decrease in cash and cash equivalents		(5,631	)		(68	)

Cash at beginning of period		6,465			3,184


Cash at end of period	$	834		$	3,116

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, 2006

(Unaudited)

(1) Organization and Description of Business

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 gathering, processing and LPG distribution, marine transportation services for petroleum products and by-products, sulfur gathering, processing and distribution and fertilizer manufacturing and marketing.

In April 2005, the Partnership began another primary line of business for sulfur marketing and distribution through the acquisition of the operating assets of Bay Sulfur Company, including a sulfur priller in Stockton, California. In January, 2006, an additional sulfur priller began production at the Partnership’s Neches facility in Beaumont, Texas. On July 15, 2005 the Partnership acquired all of the outstanding partnership interests of CF Martin Sulphur, L.P. (“CF Martin Sulphur”) not owned by the Partnership. As a result, CF Martin Sulphur has been consolidated in the Partnership’s consolidated financial statements and in the Partnership’s sulfur segment. Prior to the acquisition, the Partnership owned an unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur. The sulfur segment includes the marketing, transportation, terminalling and storage, processing and distribution of molten and pelletized sulfur.

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

The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry.

(2) Significant Accounting Policies

In addition to matters discussed below in this note, the Partnership’s significant accounting policies are detailed in the audited consolidated financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2005 filed with the Securities and Exchange Commission (the “SEC”) on March 14, 2006.

(a) Principles of Presentation and Consolidation

The balance sheets as of September 30, 2006 and December 31, 2005, statements of capital and cash flows for the nine months ended September 30, 2006 and 2005, and the statements of operations and comprehensive income for the three and nine months ended September 30, 2006 and 2005 are presented on a consolidated basis and include the operations of the Partnership and its wholly-owned subsidiaries and equity method investees.

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, 2005 filed with the SEC on March 14, 2006. 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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

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 the three and nine months ended September 30, 2006 are not necessarily indicative of the results of operations for the full year.

(b) Derivative Instruments and Hedging Activities

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, 2006, 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.

(c) Comprehensive Income

Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the partnership includes unrealized gains and losses on derivative financial instruments. In accordance with SFAS No. 133, the partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

(d) Unit Grants

In January 2006, the Partnership issued 1,000 restricted units to each of its three independent, non-employee directors under its long-term incentive plan. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010. The 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 $7 and $17 for the three months and nine months ended September 30, 2006. The Partnership’s general partner contributed $2 in cash to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.

(e) 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 unit holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months and nine months ended September 30, 2006, the general partner received $134 and $403 in incentive distributions.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

(f) 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 12,682,342 and 8,475,862 for the three months ended September 30, 2006 and 2005 and were 12,555,968 and 8,475,862 for the nine months ended September 30, 2006 and 2005, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 2,547 and 2,633 for the three months and nine months ended September 30, 2006, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(g) Impact of Recently Issued Accounting Standards

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

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No.108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”, (SAB 108). SAB 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to quantify misstatements using a balance sheet approach and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of the relevant quantitative and qualitative factors. SAB 108 is effective for fiscal years ending on or after November 15, 2006. The Partnership is currently evaluating the impact of adopting SAB 108 but does not expect that it will have a material adverse effect on its consolidated financial statements.

In September 2006, the FASB issued FAS 157, which will become effective for the Partnership on January 1, 2008. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the Partnership from the adoption of FAS 157 in 2008 will depend on the Partnership’s assets and liabilities at that time that are required to be measured at fair value.

(3) Subsequent Event

In October 2006, the Waskom plant was shutdown for a period of nine days in order to upgrade its assets to prepare for plant expansions which the Partnership anticipates will be completed in the first and second quarters of 2007. In addition, the Waskom fractionator was shutdown for most of October to facilitate a 100 million cubic feet per day expansion which the Partnership anticipates will be completed in early November, 2006.

(4) Acquisitions

(a) Corpus Christi Barge Terminal

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

(b) Marine Vessel Acquisitions

In January 2006, the Partnership acquired the Texan, an offshore tug, and the Ponciana, an offshore LPG barge, for $5,850 from Martin Resource Management Corporation (“MRMC”). The acquisition price was based on a third-party appraisal and was approved by the Partnership’s conflicts committee. 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 charter with an affiliate of MRMC.

(5) Inventories

Components of inventories at September 30, 2006 and December 31, 2005 were as follows:


	September 30,		December 31,
	2006		2005
Liquefied petroleum gas	$	24,385	$	18,405
Sulfur		4,277		3,485
Fertilizer — raw materials and packaging		2,348		2,617
Fertilizer — finished goods		4,216		5,803
Lubricants		2,624		2,035
Other		1,889		1,564

	$	39,739	$	33,909

(6) Investment in Unconsolidated Partnerships and Joint Ventures

In July 2005, the Partnership acquired all of the outstanding partnership interests in CF Martin Sulphur not owned by the Partnership from CF Industries, Inc. and certain subsidiaries of MRMC. Prior to this transaction, the Partnership owned an unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur, which was accounted for using the equity method of accounting. Subsequent to the acquisition, CF Martin Sulphur was a wholly-owned subsidiary included in the Partnership’s consolidated financial statements and in the Partnership’s sulfur segment. Effective March 30, 2006, CF Martin Sulphur was merged into the Partnership.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

On November 10, 2005, the Partnership acquired Prism Gas which is engaged in the gathering, processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana. Through the acquisition of Prism Gas, the Partnership also acquired 50% ownership interests in Waskom, Matagorda and PIPE. Each of the interests referenced above are accounted for under the equity method of accounting.

On June 30, 2006, the Partnership, through its Prism Gas subsidiary, acquired a 20% ownership interest in a partnership for approximately $196, which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). BCP is an approximate 80 mile pipeline located in the Barnett Shale extension. The pipeline traverses four counties with the most concentrated drilling occurring in Bosque County. BCP is operated by Panther Pipeline Ltd. who is the 42.5% interest owner. This interest is accounted for under the equity method of accounting.

Certain financial information related to the Partnership’s investments and equity in earnings of the unconsolidated equity method investees is shown below:


	Investments
	As of		As of
	September 30,		December 31,
	2006		2005
Waskom	$	61,419	$	54,087
Matagorda		3,889		4,069
PIPE		1,642		1,723
BCP		169		—

	$	67,119	$	59,879


	Equity in Earnings
	Three months ended					Nine months ended
	September 30,					September 30,
	2006			2005		2006			2005
Waskom	$	2,663		$	—	$	7,043		$	—
Matagorda		86			—		330			—
PIPE		(2	)		—		96			—
BCP		(27	)		—		(27	)		—
CF Martin Sulphur		—			27		—			222

	$	2,720		$	27	$	7,442		$	222

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. Distributions in kind were received for the three months and nine months ended September 30, 2006 of $2,795 and $6,710, respectively. In addition, cash distributions were received during the three months and nine months ended September 30, 2006 from PIPE of $38 and $176, Matagorda of $112 and $510, and Waskom of $0 and $150, respectively. The Partnership made additional net investments in Waskom of $6,008 and $7,148 during the three month and nine months ended September 30, 2006, respectively. The net investment in Waskom includes $3,443 and $5,565 of expansion capital expenditures, other cash contributions of $3,170 and $4,245 as offset by non-cash processing fees of $605 and $2,662 during the three months and nine months ended September 30, 2006, respectively. In total, the Partnership invested $3,443 and $5,762 in expansion capital expenditures in unconsolidated entities for the three months and nine months ended September 30, 2006, respectively. Other cash contributions include $2,500 of working capital for Waskom for both the three months and nine months ended September 30, 2006.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

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


	Three months ended					Nine months ended
	September 30,					September 30,
	2006		2005			2006		2005
Waskom
Revenues	$	18,654	$	—		$	52,924	$	—
Costs and expenses		13,201		—			38,391		—

Net income	$	5,453	$	—		$	14,533	$	—


CF Martin (Prior to July 15, 2005)
Revenues	$	—	$	2,549		$	—	$	33,900
Costs and expenses		—		2,502			—		33,570

Operating income		—		47			—		330
Interest expense		—		(31	)		—		(451	)

Net loss	$	—	$	16		$	—	$	(121	)


	As of the period ended
	September 30,		December 31,
	2006		2005
Waskom
Total assets	$	47,424	$	28,369
Partners’ capital		37,760		22,650

The unamortized portion of the excess of cost over the Partnership’s share of net assets of unconsolidated entities is $42,539 at September 30, 2006. In accordance with SFAS 142, this equity-method goodwill is not amortized; however, the investment is analyzed for impairment in accordance with APB Opinion 18.

(7) Commodity Cash Flow Hedges

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

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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

The components of gain/loss on derivatives qualifying for hedge accounting and those that do not are included in the revenue of the hedged item in the Consolidated and Condensed Statements of Operations and for the three and nine months ended September 30, 2006 they are as follows:


	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
Change in fair value of derivatives that do not qualify for hedge accounting	$	829	$	—	$	697	$	—
Ineffective portion of derivatives qualifying for hedge accounting		39		—		3		—

Change in fair value of derivatives in the Consolidated Statement of Operations	$	868	$	—	$	700	$	—

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


	September 30,			December 31,
	2006			2005
Fair value of derivative assets — current	$	900		$	523
Fair value of derivative assets — long term		190			—
Fair value of derivative liabilities — current		(56	)		(88	)
Fair value of derivative liabilities — long term		(204	)		—

Net fair value of derivatives	$	830		$	435

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2006 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of September 30, 2006, the remaining term of the contracts extend no later than December 2009, with no single contract longer than one year. The Partnership’s counterparties to the derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank. For the period ended September 30, 2006, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in other comprehensive income as a component of equity since the Partnership has designated a portion of its derivative instruments as hedges as of September 30, 2006.

September 30, 2006

Total

Volume

Remaining Terms

Transaction Type

Per Month

Pricing Terms

of Contracts

Fair Value

Mark to Market Derivatives::

Ethane swap

6,000 BBL

Fixed price of $29.09 settled against Mt. Belvieu OPIS average monthly postings

October 2006 to December 2006

Crude Oil swaps

5,000 BBL

Fixed price of $66.25, $65.10 and $66.80 settled against WTI NYMEX average monthly closings

October 2006 to December 2006

Natural Gas swaps

20,000 MMBTU

Fixed price of $9.03 and $9.54 settled against Houston Ship Channel average monthly postings

October 2006 to December 2006

258

Crude Oil swap

5,000 BBL

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

January 2007 to December 2007

(100

)

Natural Gas swap and Natural Gas basis swap

20,000 MMBTU

Combined fixed price of $8.54 settled against IF Centerpoint Energy Gas Transmission Co.

January 2007 to December 2007

319

Total swaps not designated as cash flow hedges

586

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

September 30, 2006

Total

Volume

Remaining Terms

Transaction Type

Per Month

Pricing Terms

of Contracts

Fair Value

Cash Flow Hedges:

Ethane Swap

8,000 BBL

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

January 2007 to December 2007

352

Crude Oil Swap

5,000 BBL

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

January 2008 to December 2008

(161

)

Crude Oil Swap

3,000 BBL

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

January 2009 to December 2009

Total swaps designated as cash flow hedges

244

Total net fair value of derivatives

830

On all transactions where the Partnership is exposed to counterparty risk, the Partnership has established a maximum credit limit threshold pursuant to its hedging policy. Under its hedging policy, the Partnership limits its counterparty risk to investment-grade counterparties.

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

Based on estimated volumes, as of September 30, 2006, Prism Gas had hedged approximately 63%, 60%, 22%, and 14% of its commodity risk by volume for 2006, 2007, 2008, and 2009, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements. In addition, the Partnership will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil.

Hedging Arrangements in Place


Year	Commodity Hedged	Volume	Type of Derivative	Basis Reference
2006	Ethane	6,000 BBL/Month	Ethane Swap ($29.09)	Mt. Belvieu
2006	Condensate & Natural Gasoline	2,000 BBL/Month	Crude Oil Swap ($66.80)	NYMEX
2006	Condensate & Natural Gasoline	2,000 BBL/Month	Crude Oil Swap ($66.25)	NYMEX
2006	Condensate & Natural Gasoline	1,000 BBL/Month	Crude Oil Swap ($65.10)	NYMEX
2006	Natural Gas	10,000 MMBTU/Month	Natural Gas Swap ($9.03)	Houston Ship Channel
2006	Natural Gas	10,000 MMBTU/Month	Natural Gas Swap ($9.54)	Houston Ship Channel
2007	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($65.95)	NYMEX
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Swap ($9.14)	Henry Hub
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Basis Swap (-$0.60)	Henry Hub to Centerpoint East
2007	Ethane	8,000 BBL/Month	Ethane Swap ($28.04)	Mt. Belvieu
2008	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($66.20)	NYMEX
2009	Condensate & Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($69.08)	NYMEX

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

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 and nine month periods ended September 30, 2006, net gains and losses on swap hedge contracts increased crude revenue by $396 and decreased crude revenue by $158, respectively. As of September 30, 2006 an unrealized derivative fair value loss of $97, related to cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). A fair value loss of $150 is expected to be reclassified into earnings in 2008. A fair value gain of $53 is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

Natural Gas

For the three month and nine month periods ended September 30, 2006, net gains on swap hedge contracts increased gas revenue by $491 and $921, respectively.

Natural Gas Liquids

For the three and nine month periods ended September 30, 2006, net losses on swap hedge contracts decreased liquids revenue by $19 and $63 respectively. As of September 30, 2006, an unrealized derivative fair value gain of $338 related to cash flow hedges of ethane price risk was recorded in other comprehensive income (loss). This fair value gain is expected to be reclassified into earnings in 2007. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

(8) Related Party Transactions

Included in the financial statements for the three and nine months ended September 30, 2006 and 2005, are various related party transactions and balances primarily with MRMC and its affiliates, CF Martin Sulphur and Waskom. More information concerning these transactions is set forth elsewhere in this quarterly report and in the Partnership’s annual report on Form 10-K for the year ended December 31, 2005 filed with the SEC on March 14, 2006.

Significant transactions with these related parties are reflected in the financial statements as follows:

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

MRMC and Affiliates


	Three Months						Nine Months
	Ended						Ended
	September 30						September 30
	2006			2005			2006			2005
LPG product sales (Natural Gas/LPG revenues)	$	372		$	33		$	499		$	33
Marine transportation revenues (Marine transportation)		3,592			1,884			9,200			6,200
Terminalling and storage revenue and wharfage fees (Terminalling and storage revenues)		2,323			2,256			6,619			6,288
Lube oil product sales (Terminalling and storage product sales revenues)		29			1			50			2
Fertilizer product sales (Fertilizer revenues)		—			21			24			32
LPG storage and throughput expenses (Natural Gas/LPG cost of products sold)		42			119			193			291
Land transportation hauling costs (Natural Gas/LPG/Sulfur/Fertilizer cost of products sold)		3,867			2,760			11,289			7,087
Sulfuric acid product purchases/plant equipment lease rental (Fertilizer cost of products sold)		100			103			744			2,439
Fertilizer salaries and benefits (Fertilizer cost of products sold)		871			681			2,550			2,071
Sulfur salaries and benefits (Sulfur cost of products sold)		146			75			492			126
Lube oil product purchases (Terminalling and storage cost of products sold)		—			—			—			30
Marine fuel purchases (Operating expenses)		2,988			2,587			7,742			5,193
Marine towing expense (Operating expenses)		—			184			—			546
LPG truck loading costs (Operating expenses)		125			100			375			300
Marine transportation salaries and benefits (Operating expenses)		2,735			2,058			7,949			6,058
LPG salaries and benefits (Operating expenses)		247			226			806			606
Fertilizer salaries and benefits (Operating expenses)		23			11			98			11
Sulfur salaries and benefits (Operating expenses)		215			115			567			115
Terminalling and storage handling fees/Lube land transportation hauling costs (Operating expenses)		408			326			1,153			1,059
Terminalling and storage salaries and benefits (Operating expenses)		642			538			1,738			1,525
Reimbursement of overhead (Offset to Selling, general and administrative expenses)		(47	)		(30	)		(141	)		(90	)
Terminalling and storage salaries and benefits (Selling, general and administrative expense)		16			18			55			55
LPG payroll (Selling, general and administrative expenses)		166			148			499			503
Fertilizer salaries and benefits (Selling, general and administrative expenses)		288			246			852			877
Sulfur salaries and benefits (Selling, general and administrative expenses)		114			76			334			76
Indirect overhead allocation expenses (Selling, general and administrative expenses)		373			363			1,120			975

CF Martin Sulphur


	Three Months					Nine Months
	Ended September					Ended September
	30,					30,
	2006		2005			2006		2005
Marine transportation revenues (Marine transportation revenues)		—	$	225			—	$	3,131
Lube oil product sales (Terminalling product sales revenues)		—		—			—		2
Fertilizer handling fee (Fertilizer revenues)		—		19			—		187
Product purchase settlements (Fertilizer cost of products sold)		—		18			—		258
Marine tug lease (Operating expenses)		—		—			—		9
Marine crew charge reimbursement (Offset to operating expenses)		—		(47	)		—		(653	)
Reimbursement of overhead (Offset to Selling, general and administrative expenses)		—		(8	)		—		(108	)

Waskom


	Three Months				Nine Months
	Ended September				Ended September
	30,				30,
	2006		2005		2006		2005
Product purchases and processing fees (Natural Gas/LPG services cost of products sold)	$	11,736	$	—	$	35,565	$	—
LPG fractionation costs (Natural Gas/LPG cost of products sold)		28		—		93		—

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

(9) Business Segments

The Partnership has five reportable segments: terminalling and storage, natural gas/LPG services, marine transportation, sulfur, which was added in 2005, 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 2 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2005 filed with the SEC on March 14, 2006. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.


						Operating		Depreciation		Operating
	Operating		Intersegment			Revenues after		and		Income			Capital
	Revenues		Eliminations			Eliminations		Amortization		(loss)			Expenditures
Three months ended September 30, 2006
Terminalling and storage	$	9,465	$	(98	)	$	9,367	$	1,224	$	2,398		$	3,637
Natural gas/LPG 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		9,398		(142	)		9,256		408		206			4,627
Indirect selling, general and administrative		—		—			—		—		(794	)		—

Total	$	148,143	$	(638	)	$	147,505	$	4,577	$	4,720		$	15,758


Three months ended September 30, 2005
Terminalling and storage	$	8,113	$	(11	)	$	8,102	$	1,096	$	1,821		$	619
Natural gas/LPG services		71,732		—			71,732		55		2,663			200
Marine transportation		9,894		(1,316	)		8,578		1,237		450			949
Sulfur		16,906		(103	)		16,803		642		1,794			4,578
Fertilizer		7,565		—			7,565		282		561			744
Indirect selling, general and administrative		—		—			—		—		(856	)		—


Total	$	114,210	$	(1,430	)	$	112,780	$	3,312	$	6,433		$	7,090


						Operating		Depreciation		Operating
	Operating		Intersegment			Revenues after		and		Income			Capital
	Revenues		Eliminations			Eliminations		Amortization		(loss)			Expenditures
Nine months ended September 30, 2006
Terminalling and storage	$	26,229	$	(300	)	$	25,929	$	3,393	$	7,475		$	10,179
Natural gas/LPG 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		47,824		(1,095	)		46,729		2,189		4,514			12,161
Fertilizer		33,741		(389	)		33,352		1,215		1,303			10,781
Indirect selling, general and administrative		—		—			—		—		(2,360	)		—


Total	$	430,023	$	(2,644	)	$	427,379	$	12,784	$	16,478		$	53,511


Nine months ended September 30, 2005
Terminalling and storage	$	24,029	$	(57	)	$	23,972	$	3,311	$	6,274		$	1,391
Natural gas/LPG services		199,487		—			199,487		165		4,675			583
Marine transportation		28,065		(1,431	)		26,634		3,666		2,465			3,477
Sulfur		17,846		(103	)		17,743		686		1,991			5,979
Fertilizer		25,980		—			25,980		844		1,924			834
Indirect selling, general and administrative		—		—			—		—		(2,524	)		—


Total	$	295,407	$	(1,591	)	$	293,816	$	8,672	$	14,805		$	12,264

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

The following table reconciles operating income to net income:


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating income	$	4,720		$	6,433		$	16,478		$	14,805
Equity in earnings of unconsolidated entities		2,720			27			7,442			222
Interest expense		(3,189	)		(1,639	)		(9,225	)		(3,834	)
Debt prepayment premium		—			—			(1,160	)		—
Other, net		78			25			330			127

Net income	$	4,329		$	4,846		$	13,865		$	11,320

Total assets by segment are as follows:


	September 30,		December 31,
	2006		2005
Total assets:
Terminalling and storage	$	82,182	$	68,429
Natural gas/LPG services		179,918		180,464
Marine transportation		73,464		54,772
Sulfur		63,044		55,367
Fertilizer		39,234		30,012

Total assets	$	437,842	$	389,044

(10) Subsequent Public Offering

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

A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows:


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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

(11) Long-term Debt

At September 30, 2006 and December 31, 2005, long-term debt consisted of the following:


	September		December 31,
	30, 2006		2005
$120,000 Revolving loan facility at variable interest rate (7.44%* weighted average at September 30, 2006), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries	$	50,000	$	62,200
*$130,000 Term loan facility at variable interest rate (7.34% at September 30, 2006), 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
***United States Government Guaranteed Ship Financing Bonds		—		9,104
Other secured debt maturing in 2008, 7.25%		113		—

Total long-term debt		180,113		201,304
Less current installments		73		9,104

Long-term debt, net of current installments	$	180,040	$	192,200


*		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 January 1, 2007, this margin will increase to 2.50% We incur a commitment fee on the unused portions of the credit facility.

**		Effective April 13, 2006, the Partnership entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010.

***		The Partnership’s credit facility required it to redeem the U.S. Government Guaranteed Ship Financing Bonds by March 31, 2006. The Partnership redeemed these bonds on March 6, 2006 with available cash and borrowings from its credit facility.

On July 13, 2006, the Partnership purchased certain terminalling assets and assumed associated long-term debt of $113 with a fixed rate cost of 7.25%.

On November 10, 2005, the Partnership entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of September 30, 2006, we had $50,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of September 30, 2006, we had $69,880 available under our revolving credit facility.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

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

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

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

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

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. 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, growth capital expenditures and for working capital requirements. During the current fiscal year, draws on the Partnership’s credit facility have ranged from a low of $130,000 to a high of $197,700. As of September 30, 2006, the Partnership had $69,880 available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility.

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

The Partnership paid cash interest in the amount of $2,874 and $1,185 for the three months ended September 30, 2006 and 2005, respectively, and $9,135 and $2,987 for the nine months ended September 30, 2006 and 2005, respectively. Capitalized interest for the three months ended September 30, 2006 and 2005 was $300 and $0, respectively, and $970 and $0 for the nine months ended September 30, 2006 and 2005, respectively.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2006
(Unaudited)

(12) Interest Rate Cash Flow Hedge

In April, 2006, we entered into an interest rate swap agreement with a notional amount of $75.0 million to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. This interest rate swap matures in November 2010. We designated this swap agreement as a cash flow hedge. Under the swap agreement, we pay a fixed rate of interest of 5.25% and receive a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this swap 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. 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 total fair value of this interest rate swap agreement was a liability of approximately $557 at September 30, 2006.

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


	September 30,
	2006
Fair value of derivative assets — current	$	80
Fair value of derivative liabilities — long term		(637	)

Net fair value of derivatives	$	(557	)

(13) Gain on Involuntary Conversion of Assets

During the third quarter of 2005, the Partnership experienced a casualty loss caused by two major storms, Hurricane Katrina and Hurricane Rita. Physical damage to the Partnership’s assets caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a deductible. Based on commitments from our insurance underwriters, 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.

(14) Income Taxes

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, we believe the margin tax is 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 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. There was no income tax expense recorded for the three or nine month periods ended September 30, 2006. Beginning 2007, the Partnership anticipates it will incur tax expense related to this new Texas margin tax.

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

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

Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Item 1A. Risks Factors” of our Form 10-K for the year ended December 31, 2005 filed with the SEC on March 14, 2006.

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/LPG 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 37.2% of our limited partnership interests. 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/LPG 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 2, “Significant Accounting Policies” in Notes to Consolidated and Condensed Financial Statements contained in this quarterly report and the similar note in the consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2005 filed with the Securities and Exchange Commission (the “SEC”) on March 14, 2006 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 are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of September 30, 2006, 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 LPGs and sulfur with third parties. We record the balance of LPGs due to other companies under these agreements at quoted market product prices and the balance of LPGs due from other companies at the lower of cost or market. We record the balance of sulfur due to and due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) 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. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

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

Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip. For time charters, revenue is recognized based on a per day rate.

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

Equity Method Investment

On July 15, 2005, we acquired the remaining interests in CF Martin Sulphur, L.P. (“CF Martin Sulphur”) not previously owned by us from CF Industries, Inc. and certain subsidiaries of Martin Resource Management. Subsequent to the acquisition, CF Martin Sulphur is included in the consolidated financial presentation of our sulfur segment. Prior to the acquisition, we used the equity method of accounting for our interest in CF Martin Sulphur because we owned an unconsolidated non-controlling 49.5% limited partner interest in this entity. Effective March 30, 2006, CF Martin Sulphur was merged into us.

Following our acquisition of Prism Gas Systems I, L.P. (“Prism Gas”) in November 2005, 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”). As a result, they are accounted for by the equity method 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 which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). This interest is accounted for under the equity method of accounting.

Goodwill

Goodwill is subject to a fair-value based impairment test on an annual basis. We are required to identify our reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. We are required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, we would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.

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

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

Environmental Liabilities

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

Allowance for Doubtful Accounts

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

Asset Retirement Obligation

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), we recognize and measure our asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset. Subsequent measurement and accounting provisions are in accordance with SFAS 143.

On March 31, 2005, the Financial Accounting Standards Board issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143. FIN 47, which was effective for fiscal years ending after December 15, 2005, clarifies that the recognition and measurement provisions of SFAS 143 apply to asset retirement obligations in which the timing or method of settlement may be conditional on a future event that may or may not be within the control of the entity. No additional asset retirement obligations were required under FIN 47.

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, 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 an underground LPG 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 LPG 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 currently owns approximately 37.2% of our outstanding limited partnership interests. Martin Resource Management also owns our general partner which holds a 2.0% general partner interest and 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.

We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires us to reimburse Martin Resource Management for all direct and indirect expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $12.9 million of direct costs and expenses for the three months ended September 30, 2006 compared to $10.3 million for the three months ended September 30, 2005. We reimbursed Martin Resource Management for $37.3 million of direct costs and expenses for the nine months ended September 30, 2006 compared to $28.9 million for the nine months ended September 30, 2005. 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, 2004. 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. Effective January 2004, the cap was increased from $1.0 million to $2.0 million to account for the additional operations acquired in recent acquisitions. We reimbursed Martin Resource Management for $0.4 million of indirect expenses for the three months ended September 30, 2006 compared to $0.4 million for the three months ended September 30, 2005. We reimbursed Martin Resource Management for $1.1 million of indirect expenses for the nine months ended September 30, 2006 compared to $1.0 million for the nine months ended September 30, 2005. 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.

Martin Resource Management also licenses certain of its trademarks and trade names to us under this omnibus agreement.

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 LPG distribution operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 65 million gallons. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

In the aggregate, our purchases of land transportation services, LPG storage services, sulfuric acid and lube oil product purchases and sulfur and fertilizer payroll reimbursements from Martin Resource Management accounted for approximately 5% and 4% of our total cost of products sold during the three months ended September 30, 2006 and 2005, respectively, and approximately 5% of our total cost of products sold during both nine months ended September 30, 2006 and 2005. 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 LPG distribution services for its operations. Martin Resource Management is also a significant customer of fertilizer products and 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 4% of our total revenues during the three months and nine months ended September 30, 2006 and 2005. In connection with the closing of the acquisition of the marine services assets from Tesoro Marine Services, L.L.C., we entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel provides terminal services to us to handle lubricants, greases and drilling fluids.

Omnibus Agreement

We are a party to an omnibus agreement with Martin Resource Management. In this agreement:

	•		Martin Resource Management agreed to not compete with us in the terminalling and storage, marine transportation, natural gas/LPG distribution and fertilizer businesses, subject to the exceptions described more fully in “Item 13. Certain Relationships and Related Transactions — Agreements — Omnibus Agreement” of our annual report on Form 10-K for the year ended December 31, 2005 filed with the SEC on March 14, 2006.

	•		Martin Resource Management agreed to indemnify us for a period of five years for environmental losses arising prior to our initial public offering, which we closed in November 2002, as well as preexisting litigation and tax liabilities.

	•		We agreed to reimburse Martin Resource Management for the provision of general and administrative services under our partnership agreement, provided that the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million for the year ending October 31, 2004. 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 9, 2006, we have not increased this cap. In addition, our general partner has the right to agree to further increases in connection with expansions of our operations through the construction of new assets or businesses. This limitation does not apply to the cost of any third party legal, accounting or advisory services received, or the direct expenses of Martin Resource Management incurred, in connection with acquisition or business development opportunities evaluated on our behalf.

	•		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.

Motor Carrier Agreement

Effective January 1, 2006, we entered into a new agreement for the provision of land transportation services with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management. This agreement replaced a prior agreement in place between us and Martin Transport, Inc. This new agreement has a term that expires December 31, 2006, and will automatically renew for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. We have the right to terminate this agreement at any time with 90 days prior notice. Under this agreement, Martin Transport transports our LPG shipments as well as other liquid products. Our shipping rates are fixed for the first year of the agreement, subject to certain cost adjustments. These rates are subject to any adjustment to which we mutually agree or in accordance with a price index after the first year of its term. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list.

Other Agreements

We are also party to the following:

	•		Specialty Petroleum Terminal Services Agreement — under which we provide terminalling and storage services to Martin Resource Management at a set rate. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The fees we charge under this agreement are adjusted annually based on a price index.

	•		Marine Transportation Agreement — under which we provide marine transportation services to Martin Resource Management on a spot-contract basis. Effective January 1, 2006 we entered into a new agreement to provide marine transportation services on a spot-contract basis. This agreement replaced a prior agreement in place between us and Martin Resource Management, which expired on November 1, 2005. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by providing the other party with written notice at least 60 days prior to the expiration of the then applicable term. The rates to be charged under this agreement are based on market rates and were established at the onset of this agreement for the first one-year term.

	•		Product Storage Agreement — under which Martin Resource Management provides us underground storage for LPGs. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Our per-unit cost under this agreement is adjusted annually based on a price index.

	•		Product Supply Agreements — under which Martin Resource Management provides us with marine fuel and sulfuric acid. Effective each November 1, these agreements automatically renew for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. We purchase products at a set margin above Martin Resource Management’s cost for such products during the term of the agreements.

	•		Throughput Agreement — under which Martin Resource Management agrees to provide us with sole access to and use of a LPG truck loading and unloading and pipeline distribution terminal located at Mont Belvieu, Texas. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Our throughput fee is adjusted annually based on a price index.

	•		Terminal Services Agreement — under which we provide terminalling services to Martin Resource Management. Effective each December 1, this agreement will automatically renew on a month-to-month basis until either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term. The per gallon throughput fee we charge under this agreement is adjusted annually based on a price index.

	•		Transportation Services Agreement — under which we provide marine transportation services to Martin Resource Management. This agreement has a three-year term, which began in December 2003, and will automatically renew for successive one-year terms unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. In addition, within 30 days of the expiration of the then-applicable term, both parties have the right to renegotiate the rate for the use of our vessels. If no agreement is reached as to a new rate by the end of the then-applicable term, the agreement will terminate. The hourly rate we charge under this agreement is adjusted annually based upon mutual agreement of the parties or in accordance with a price index.

•

Lubricants and Drilling Fluids Terminal Services Agreement — under which Martin Resource Management provides terminal services to us. Effective each November 1, this agreement automatically renews for successive one-year terms until either party terminates the agreement by giving written notice to the other party at least 60 days prior to the end of the then-applicable term. The per gallon handling fee and the percentage of our commissions we are charged under this agreement is adjusted annually based on a price index.

Finally, Martin Resource Management also granted us a perpetual, non-exclusive use, ingress-egress and utility facilities easement in connection with the transfer of our Stanolind terminal assets to us.

Further information concerning our relationship with Martin Resource Management and its affiliates is set forth in our annual report on Form 10-K for the year ended December 31, 2005 filed with the SEC on March 14, 2006.

Our Relationship with CF Martin Sulphur

On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin Sulphur from CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to this transaction, our unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur, was accounted for using the equity method of accounting. In addition, on July 15, 2005, we acquired all of the outstanding membership interests in CF Martin Sulphur’s general partner. Thus, we now control the management of CF Martin Sulphur and conduct its day-to-day operations. Subsequent to the acquisition, CF Martin Sulphur was a wholly owned partnership which is included in the consolidated financial presentation of our sulfur segment. Effective March 30, 2006, CF Martin Sulphur was merged into us.

Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin Sulphur. We chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a guaranteed daily rate, subject to certain adjustments. This charter, which had an unlimited term, was terminated on November 18, 2005. CF Martin Sulphur paid to have this tug/barge tanker unit reconfigured to carry molten sulfur. In the event CF Martin Sulphur terminated this charter agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such reconfiguration costs. As a result of the July 15, 2005 acquisition of all the outstanding interests in CF Martin Sulphur, this contingent obligation was terminated.

Further information concerning our relationship with CF Martin Sulphur is set forth in our annual report on Form 10-K for the year ended December 31, 2005 filed with the SEC on March 14, 2006.

Results of Operations

The results of operations for the three months and nine months ended September 30, 2006 and 2005 have been derived from our consolidated and condensed financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating income by segment, and equity in earnings of unconsolidated entities, for the three months and nine months ended September 30, 2006 and 2005. 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.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(In thousands)
Operating income:
Terminalling and storage	$	2,398		$	1,821		$	7,475		$	6,274
Natural gas/LPG services		714			2,663			1,918			4,675
Marine transportation		1,233			450			3,628			2,465
Sulfur		963			1,794			4,514			1,991
Fertilizer		206			561			1,303			1,924
Indirect selling, general and administrative expenses		(794	)		(856	)		(2,360	)		(2,524	)


Operating income	$	4,720		$	6,433		$	16,478		$	14,805


Equity in earnings of unconsolidated subsidiaries	$	2,720		$	27		$	7,442		$	222

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, 2006 Compared to the Three Months Ended September 30, 2005

Our total revenues were $147.5 million for the three months ended September 30, 2006 compared to $112.8 million for the three months ended September 30, 2005, an increase of $34.7 million, or 31%. Our cost of products sold was $117.9 million for the three months ended September 30, 2006 compared to $87.8 million for the three months ended September 30, 2005, an increase of $30.1 million, or 34%. Our total operating expenses were $17.5 million for the three months ended September 30, 2006 compared to $13.4 million for the three months ended September 30, 2005, an increase of $4.1 million, or 31%.

Our total selling, general and administrative expenses were $2.8 million for the three months ended September 30, 2006 compared to $1.8 million for the three months ended September 30, 2005, an increase of $1.0 million, or 56%. Total depreciation and amortization was $4.6 million for the three months ended September 30, 2006 compared to $3.3 million for the three months ended September 30, 2005, an increase of $1.3 million, or 39%. Our operating income was $4.7 million for the three months ended September 30, 2006 compared to $6.4 million for the three months ended September 30, 2005, a decrease of $1.7 million, or 27%.

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,
	2006		2005
	(In thousands)
Revenues:
Services	$	6,163	$	5,782
Products		3,204		2,320

Total revenues		9,367		8,102

Cost of products sold		2,550		1,950
Operating expenses		3,164		3,206
Selling, general and administrative expenses		31		29
Depreciation and amortization		1,224		1,096

		2,398		1,821

Other operating income		—		—

Operating income	$	2,398	$	1,821

Revenues. Our terminalling and storage revenues increased $1.3 million, or 16%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. Service revenue accounted for $0.4 million of this increase due to an increase in the number of drilling rigs working from our full service bases. Product revenue increased $0.9 million primarily due to 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 $0.6 million, or 31%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This increase was less than our product revenue increases as we were able to increase product margins.

Operating expenses. Operating expenses were approximately the same for both three month periods ended September 30, 2006 and 2005. During 2006, hurricane expenses decreased by $0.4 million, but were offset by an increase in activity at our terminals, which caused operating expenses to increase by $0.4 million.

Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for both three month periods ended September 30, 2006 and 2005.

Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 12%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. The increase was primarily due to the asset acquisition of our Corpus Christi Barge Terminal.

In summary, our terminalling operating income increased $0.6 million, or 32%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005.

Natural Gas/LPG Services Segment

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


	Three Months Ended
	September 30,
	2006		2005
	(In thousands)
Revenues	$	102,217	$	71,732
Cost of products sold		98,639		68,140
Operating expenses		1,240		591
Selling, general and administrative expenses		1,186		283
Depreciation and amortization		438		55

Operating income	$	714	$	2,663


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


LPG Volumes (gallons)		77,255		58,287

Revenues. Our natural gas/LPG services revenues increased $30.5 million, or 42%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. Of the increase, $6.4 million relates to sales in our historical LPG distribution segment. The increase of $6.4 million is primarily due from an increase in our average sales price per gallon of 9% in the third quarter of 2006 compared to this same period in 2005, as our sales volumes in the two periods remained approximately the same. This price increase was due to a general increase in the prices of LPG’s.

The remaining $24.1 million increase relates to increases in sales resulting from our acquisition of Prism Gas. These sales are comprised of $19.4 million of LPG sales, $3.3 million of natural gas sales and $0.5 million of gathering and processing fees. Also, included in revenue was $0.9 million of gains on derivative contracts.

Costs of product sold. Our cost of products increased $30.5 million, or 45%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. Of the increase, $8.8 million is related to costs in our historical LPG distribution segment. This increase was higher than the increase in our historical LPG revenues, as our per gallon margins fell 67%. For the three months ended September 30, 2005, our historical LPG distribution segment benefited from extraordinary market conditions due to gulf coast hurricanes. These market conditions resulted in a rapid increase in LPG prices allowing us to surpass our historical margins of approximately $0.025 per gallon and we experienced a margin of approximately $0.06 per gallon. For the three months ended September 30, 2006, in our historical LPG segment, we experienced margins of approximately $0.02 per gallon. The balance of the increase of $21.7 million relates to costs from our Prism Gas acquisition.

Operating expenses. Operating expenses increased $0.7 million, or 110%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. An increase of $0.2 million was a result of additional operating expenses incurred from our East Texas pipeline operations, and $0.5 million resulted from the Prism Gas acquisition.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.9 million, or 319%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This increase was primarily a result of the Prism Gas acquisition.

Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 698%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This increase was primarily a result of the Prism Gas acquisition.

In summary, our natural gas/LPG services operating income decreased $1.9 million, or 73%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. A portion of this decrease is related to an increase in selling, general and administrative expenses related to the Prism Gas acquisition. Prism Gas, as operator of Waskom, is required, per the Waskom partnership agreement, to perform certain services, including but not limited to accounting and engineering, for the Waskom partnership. While Prism Gas does receive an operator’s fee based on a percentage of Waskom’s operating costs, generally the expenses incurred are recovered in equity in earnings of unconsolidated entities.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $2.7 million for the three months ended September 30, 2006. 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 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,
	2006		2005
	(In thousands)
Revenues	$	12,949	$	8,578
Operating expenses		9,861		6,889
Selling, general and administrative expenses		149		2
Depreciation and amortization		1,706		1,237

Operating income	$	1,233	$	450

Revenues. Our marine transportation revenues increased $4.4 million, or 51%, for the three months ended September 30, 2006, compared to the three months ended September 30, 2005. Our offshore revenues increased $2.8 million primarily from the purchase of the Texan, an offshore tug, and the Ponciana, an offshore LPG barge. We also operated another offshore barge for the entire period that was recently upgraded to handle petroleum products and experienced increased utilizations from the entire offshore assets. The inland marine assets, coupled with leased inland marine assets, had increased revenues of $0.4 million.

For the three months ended September 30, 2006, intersegment sales to our sulfur, terminalling and storage, and fertilizer segments of $0.2 million were eliminated from our marine transportation segment reducing reported marine transportation revenue by this amount. Intersegment sales of $1.3 million were eliminated for the three months ended September 30, 2005.

Operating expenses. Operating expenses increased $3.0 million, or 43%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. The increase was a result of increased operating costs from the offshore marine vessel acquisitions, including costs associated with maintenance and repairs.

Selling, general, and administrative expenses. Selling, general & administrative expenses increased $0.1 million for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005.

Depreciation and Amortization. Depreciation and amortization increased $0.5 million, or 38%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This increase was the result of maintenance capital expenditures made in the last 12 months and offshore marine vessel acquisitions.

In summary, our marine transportation operating income increased $0.8 million, or 175%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005.

Sulfur Segment

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


	Three Months Ended
	September 30,
	2006		2005
	(In thousands)
Revenues	$	13,716	$	16,803
Cost of products sold		8,496		11,331
Operating expenses		3,205		2,737
Selling, general and administrative expenses		251		299
Depreciation and amortization		801		642

Operating income	$	963	$	1,794


Sulfur Volumes (long tons)		189.9		250.3

Revenues. Our sulfur revenues decreased $3.1 million, or 18%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This decrease in revenue primarily resulted from a 24% decrease in sales volume. We eliminated an offshore vessel from our sulfur segment in the fourth quarter of 2005. This capacity reduction contributed to the sales volume decrease.

Cost of products sold. Our cost of products sold decreased $2.8 million, or 25%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This decrease was less than our sales decrease as we were able to expand our sulfur margins.

Operating expenses. Our operating expenses increased $0.5 million, or 17%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. No intersegment expense was eliminated from operating expenses in the third quarter of 2006, compared to $1.3 million in the third quarter of 2005. This elimination reflects the charge from our marine transportation segment to our sulfur segment for an offshore vessel. This intersegment elimination reduced our sulfur operating expenses in the third quarter of 2005 by $1.3 million. We did not have this intersegement elimination in the third quarter of 2006 due to the elimination of the offshore vessel from our sulfur segment in the fourth quarter of 2005.

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 $0.2 million, or 25%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This increase is primarily attributable to our Neches priller which began operations in the first quarter of 2006.

In summary, our sulfur operating income decreased $0.8 million, or 46%, for the three months ended September 30, 2006, compared to the three months ended September 30, 2005.

Fertilizer Segment

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


	Three Months Ended
	September 30,
	2006		2005
	(In thousands)
Revenues	$	9,256	$	7,565
Cost of products sold and operating expenses		8,243		6,343
Selling, general and administrative expenses		399		379
Depreciation and amortization		408		282

Operating income	$	206	$	561


Fertilizer Volumes (tons)		34.9		26.1

Revenues. Our fertilizer revenues increased $1.7 million, or 22%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. Our sales volume increased 34% due to increased demand from our customers and new volume sales as a result of the acquisition of the assets of A&A Fertilizer Company (“A&A”), which closed in December 2005. Offsetting this volume increase was a decrease in our average sales price per ton of 9%. This decrease of our sales price per ton was a result of the A&A acquisition. Liquid sulfur product sales from this acquisition are at a lower sales price per ton than our historical dry sulfur product sales.

Cost of products sold and operating expenses. Our cost of products sold and operating expenses increased $1.9 million, or 30%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This increase was greater than our increase in sales, resulting in a decreased gross margin per ton. This was a result of competitive pricing pressure and increased freight costs that we were unable to pass through to our customers.

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 approximately $0.1 million, or 45%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. This increase was primarily due to the A&A acquisition.

In summary our fertilizer operating income decreased $0.4 million, or 63%, for the three months ended September 30, 2006 compared to the three months ended September 30, 2005.

Nine Months Ended September 30, 2006 Compared to the Nine Months Ended September 30, 2005

Our total revenues were $427.4 million for the nine months ended September 30, 2006 compared to $293.8 million for the nine months ended September 30, 2005, an increase of $133.6 million, or 45%. Our cost of products sold was $345.4 million for the nine months ended September 30, 2006 compared to $232.1 million for the nine months ended September 30, 2005, an increase of $113.3 million, or 49%. Our total operating expenses were $45.8 million for the nine months ended September 30, 2006 compared to $32.8 million for the nine months ended September 30, 2005, an increase of $13.0 million, or 40%.

Our total selling, general and administrative expenses were $7.8 million for the nine months ended September 30, 2006 compared to $5.4 million for the nine months ended September 30, 2005, an increase of $2.4 million, or 44%. Total depreciation and amortization was $12.8 million for the nine months ended September 30, 2006 compared to $8.7 million for the nine months ended September 30, 2005, an increase of $4.1 million, or 47%. Our operating income was $16.5 million for the nine months ended September 30, 2006 compared to $14.8 million for the nine months ended September 30, 2005, an increase of $1.7 million, or 11%.

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,
	2006		2005
	(In thousands)
Revenues:
Services	$	17,511	$	16,858
Products		8,418		7,114

Total revenues		25,929		23,972

Cost of products sold		6,866		5,969
Operating expenses		8,968		8,198
Selling, general and administrative expenses		80		220
Depreciation and amortization		3,393		3,311

		6,622		6,274

Other operating income		853		—

Operating income	$	7,475	$	6,274

Revenues. Our terminalling and storage revenues increased $2.0 million, or 8%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. Service revenue accounted for $0.7 million of this increase due to an increase in number of drilling rigs working from our bases. Product revenue increased $1.3 million primarily due to an increase in product cost that was able to be passed along to our customers.

Cost of products sold. Our cost of products increased $0.9 million, or 15%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. This increase was less than our product revenue increase as we were able to increase product margins.

Operating expenses. Operating expenses increased $0.8 million, or 9%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. The increase was a result of increased activity at our terminals, which caused operating expenses to increase $1.2 million offset by a decrease in hurricane expenses of $0.4 million.

Selling, general and administrative expenses. Selling, general & administrative expenses decreased $0.1 million, or 64%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005.

Depreciation and amortization. Depreciation and amortization increased $0.1 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. The increase was primarily due to the acquisition of our Corpus Christi barge terminal.

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 $1.2 million, or 19%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005.

Natural Gas/LPG Services Segment

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


	Nine Months Ended
	September 30,
	2006		2005
	(In thousands)
Revenues	$	288,199	$	199,487
Cost of products sold		278,239		192,187
Operating expenses		3,805		1,555
Selling, general and administrative expenses		2,995		905
Depreciation and amortization		1,242		165

Operating income	$	1,918	$	4,675


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


LPG Volumes (gallons)		236,163		185,927

Revenues. Our natural gas/LPG services revenues increased $88.7 million, or 44%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. Of the increase, $24.9 million relates to sales in our historical LPG distribution segment. The increase is primarily due from an increase in our average sales price per gallon of 17% in the first nine months of 2006 compared to the first nine months of 2005, as our sales volumes in the two periods remained approximately the same. This price increase was due to a general increase in the prices of LPG’s.

The remaining $63.8 million increase relates to increases in sales resulting from our acquisition of Prism Gas. These sales are comprised of $51.3 million of LPG sales, $10.5 million of natural gas sales and $1.3 million of gathering and processing fees. Also included in revenue was a $0.7 million of gains on derivative contracts.

Costs of product sold. Our cost of products increased $86.1 million, or 45%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. Of the increase, $27.4 million is related to costs in our historical LPG distribution segment. This increase was higher than the increase in our historical LPG revenues, as our per gallon margin decreased by 32%. For the nine months ended September 30, 2005, our historical LPG distribution segment benefited from extraordinary market conditions due to gulf coast hurricanes. These market conditions resulted in a rapid increase in LPG prices allowing us to surpass our historical margins of approximately $0.025 per gallon and we experienced a margin of approximately $0.04 per gallon. For the nine months ended September 30, 2006, in our historical LPG segment, we experienced margins of approximately $0.03 per gallon. The balance of the increase of $58.6 million relates to costs resulting from our Prism Gas acquisition.

Operating expenses. Operating expenses increased $2.3 million, or 145%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. An increase of $0.7 million was primarily a result of additional operating expenses incurred from our East Texas pipeline operations, and $1.6 million resulted from the Prism Gas acquisition.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $2.1 million, or 231%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. This increase was primarily a result of the Prism Gas acquisition.

Depreciation and amortization. Depreciation and amortization increased $1.1 million, or 653%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. This increase was primarily a result of the Prism Gas acquisition.

In summary, our natural gas/LPG services operating income decreased $2.8 million, or 59%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. A portion of this decrease is related to an increase in selling, general and administrative expenses related to the Prism Gas acquisition.

Prism Gas, as operator of Waskom, is required, per the partnership agreement, to perform certain services, including but not limited to accounting and engineering, for the Waskom partnership. While Prism Gas does receive an operator’s fee based on a percentage of Waskom’s operating costs, generally the expenses incurred are recovered in equity in earnings of unconsolidated entities.

Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $7.4 million for the nine months ended September 30, 2006. 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,
	2006		2005
	(In thousands)
Revenues	$	33,170	$	26,634
Operating expenses		24,374		20,288
Selling, general and administrative expenses		423		215
Depreciation and amortization		4,745		3,666

Operating income	$	3,628	$	2,465

Revenues. Our marine transportation revenues increased $6.5 million, or 25%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. Our offshore revenues increased $5.6 million primarily from the purchase of the Texan, an offshore tug, and the Ponciana, an offshore LPG barge. We also operated for the entire period another offshore barge that was upgraded at the beginning of 2006 to handle petroleum products and experienced increased utilizations from the entire offshore assets. Our inland marine assets, coupled with leased inland marine assets, had increased revenues of $0.3 million.

For the nine months ended September 30, 2006, inter-segment sales to our sulfur, terminalling and storage, and fertilizer segments of $0.9 million were eliminated from our marine transportation segment reducing reported marine transportation revenue by this amount. Inter-segment sales of $1.4 million were eliminated for the nine months ended September 30, 2005.

Operating expenses. Operating expenses increased $4.1 million, or 20%, for the nine months ended September 30, 2006 compared to nine months ended September 30, 2005. The increase was a result of increased operating costs from the offshore marine vessel acquisitions.

Selling, general, and administrative expenses. Selling, general & administrative expenses increased $0.2 million, or 97% for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005.

Depreciation and Amortization. Depreciation and amortization increased $1.1 million, or 29%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. This increase was the result of maintenance capital expenditures made in the last 12 months and offshore marine vessel acquisitions.

In summary, our marine transportation operating income increased $1.2 million, or 47%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005.

Sulfur Segment

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


	Nine Months Ended
	September 30,
	2006		2005
	(In thousands)
Revenues	$	46,729	$	17,743
Cost of products sold		30,668		12,030
Operating expenses		8,604		2,737
Selling, general and administrative expenses		754		299
Depreciation and amortization		2,189		686

Operating income	$	4,514	$	1,991


Sulfur Volumes (long tons)		617.8		261.0

Our sulfur operating segment was established in April 2005, as a result of the acquisition of the operating assets of Bay Sulfur Company and the beginning of construction of a sulfur priller at our Neches terminal. On July 15, 2005, we purchased the equity interests of CF Martin Sulphur not owned by us. Since that date, the results of CF Martin Sulphur have been added to the results reported in the above table. Prior to July 15, 2005, we owned an unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur, which was accounted for using the equity method of accounting. On July 15, 2005, CF Martin Sulphur became our wholly-owned subsidiary and all intercompany transactions were eliminated in consolidation.

The results of operations for the nine month period ending September 30, 2005, represents operations at the Stockton, California priller facility from April 2005 through September 2005 and CF Martin Sulphur from July 15, 2005 through September 2005.

Fertilizer Segment

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


	Nine Months Ended
	September 30,
	2006		2005
	(In thousands)
Revenues	$	33,352	$	25,980
Cost of products sold and operating expenses		29,645		21,955
Selling, general and administrative expenses		1,189		1,257
Depreciation and amortization		1,215		844

Operating income	$	1,303	$	1,924


Fertilizer Volumes (tons)		163.3		112.7

Revenues. Our fertilizer revenues increased $7.4 million, or 28%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. Our sales volume increased 45% due to increased demand from our customers and new volume sales as a result of the A&A acquisition, which closed in December 2005. Offsetting this volume increase was a decrease in our average sales price per ton of 11%. This decrease of our sales price per ton was a result of the A&A acquisition. Product sales from this acquisition are at a lower sales price per ton than our historical product sales.

Cost of products sold and operating expenses. Our cost of products sold and operating expenses increased $7.7 million, or 35%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. This increase was greater than our increase in sales, resulting in a decreased gross margin per ton. This was a result of competitive pricing pressure and increased freight costs that we were unable to pass through to our customers.

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

Depreciation and amortization. Depreciation and amortization increased approximately $0.4 million, or 44%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005. This increase was primarily due to the A&A acquisition.

In summary our fertilizer operating income decreased $0.6 million, or 32%, for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005.

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, 2006 and 2005 are as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Revenues		100	%		100	%		100	%		100	%
Cost of products sold		80	%		78	%		81	%		79	%
Operating expenses		12	%		13	%		11	%		11	%
Selling, general and administrative expenses		2	%		1	%		2	%		2	%
Depreciation and amortization		3	%		3	%		3	%		3	%

Equity in Earnings of Unconsolidated Entities

For the three months and nine months ended September 30, 2006 equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom, Matagorda and PIPE owned by Prism Gas since its acquisition on November 10, 2005, and for the three months and nine months ended September 30, 2005 equity in earnings of unconsolidated entities relates to our non-controlling 49.5% limited partner interest in CF Martin Sulphur prior to July 15, 2005.

Equity in earnings of unconsolidated entities was $2.7 million for the three months ended September 30, 2006 compared to the $0.0 million for the three months ended September 30, 2005, an increase of $2.7 million. These increases are related to earnings of Waskom, Matagorda and PIPE.

Equity in earnings of unconsolidated entities was $7.4 million for the nine months ended September 30, 2006 compared to the $0.2 million for the nine months ended September 30, 2005, an increase of $7.2 million. These increases are related to earnings of Waskom, Matagorda and PIPE.

Interest Expense

Interest expense for all operations was $3.2 million for the three months ended September 30, 2006 compared to the $1.6 million for the three months ended September 30, 2005, an increase of $1.6 million, or 100%. This increase was primarily due to an increase in average debt outstanding and an increase in interest rates in the third quarter of 2006 compared to the same period in 2005.

Interest expense for all operations was $9.2 million for the nine months ended September 30, 2006 compared to the $3.8 million for the nine months ended September 30, 2005, an increase of $5.4 million, or 142%. This increase was primarily due to an increase in average debt outstanding and an increase in interest rates in the first nine months of 2006 compared to the same period in 2005.

Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses were $0.8 million for the three months ended September 30, 2006 compared to $0.9 million for the three months ended September 30, 2005, a decrease of $0.1 million, or 11%. The decrease of $0.1 million was primarily due to a decrease of $0.1 million in legal fees.

Indirect selling, general and administrative expenses were $2.4 million for the nine months ended September 30, 2006 compared to $2.5 million for the nine months ended September 30, 2005, a decrease of $0.1 million, or 4%. The decrease of $0.1 million was primarily due to a decrease of $0.3 million in Sarbanes-Oxley compliance which was offset by an increase of $0.2 million in overhead allocation expense.

Martin Resource Management allocates 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 expenses 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 expenses 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 year period ending October 31, 2004. 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 9, 2006, we have not increased this cap. In addition, our general partner has the right to agree to increases in this cap in connection with expansions of our operations through the acquisition or construction of new assets or businesses.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

For the nine months ended September 30, 2006, cash decreased $5.6 million as a result of $15.9 million provided by operating activities, $73.3 million used in investing activities and $51.7 million provided by financing activities. For the nine months ended September 30, 2005, cash decreased $0.1 million as a result of $24.3 million provided by operating activities, $46.4 million used in investing activities and $22.1 million provided by financing activities.

For the nine months ended September 30, 2006 our investing activities of $73.3 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 distributions from unconsolidated partnerships. For the nine months ended September 30, 2006, our investments in unconsolidated partnerships consisted primarily of $5.9 million used for capital expenditures at the Waskom facility.

For the nine months ended September 30, 2005 our investing activities of $46.4 million consisted primarily of capital expenditures and acquisitions.

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, 2006 and 2005, our capital expenditures for property, plant and equipment were $70.1 million and $36.3 million, respectively.

As to each period:

	•		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, 2005, we spent $33.1 million for expansion capital expenditures and $3.2 million for maintenance capital expenditures. Our expansion capital expenditures were made in connection with the purchase of a liquefied petroleum gas pipeline from an unrelated party in January 2005, the purchase of a sulfur priller from an unrelated party in April 2005, the purchase of additional marine equipment and the purchase of the CF Martin Sulphur partnership interests not owned by us. Our maintenance capital expenditures were primarily made for terminalling, marine transportation, LPG and fertilizer facilities.

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. For the nine months ended September 30, 2005, our financing activities consisted of cash distributions paid to common and subordinated unit holders of $14.0 million, payments of long term debt under our credit facility of $16.7 million, borrowings of long-term debt under our credit facility of $53.2 million and payments of debt issuance costs of $0.4 million.

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, 2006, we had $180.1 million of outstanding indebtedness, consisting of outstanding borrowings of $50.0 million under our revolving credit facility and $130.0 million under our term loan facility and $0.1 million of other secured debt. Under our prior acquisition subfacility, we borrowed $3.5 million in connection with the acquisition of the East Texas Pipeline in January 2005, $5.0 million in connection with the acquisition of the operating assets of Bay Sulfur Company in April 2005, and $19.4 million in connection with the acquisition of the partnership interests in CF Martin Sulphur not owned by us in July 2005. In connection with the CF Martin Sulphur acquisition, we assumed $11.5 million of indebtedness owed by CF Martin Sulphur and promptly repaid $2.4 million of such indebtedness. The remaining indebtedness relates to certain financing of CF Martin Sulphur under its 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. During the third quarter of 2006, we borrowed $30.0 million under our revolving credit facility in connection with the acquisition of the Corpus Christi barge terminal, certain asphalt terminalling assets and to fund growth capital expenditures.

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 certain of the sellers and approximately $0.8 million in capital provided by Martin Resource Management for acquisition

costs and in order to continue the 2% general partnership interest in us. The common units were priced at $32.54 per common unit, based on the average closing price of our common units on the NASDAQ during the ten trading days immediately preceding and immediately following the date of the execution of the definitive purchase agreement.

In January 2006, we completed a public offering of 3,000,000 common units as well as the full over-allotment of an additional 450,000 units at a price of $29.12 per common unit, before payment of underwriters’ discounts, commissions and offering expenses. After the completion of our offering in January 2006, we have $100 million available under this registration statement. The nature and terms of any securities to be offered and sold under the registration statement, including the use of proceeds, will be described in related prospectus supplements to be filed with the SEC from time to time.

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 2006. 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. See “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2005 filed with the SEC on March 14, 2006 for a discussion of such risks.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2006 is as follows: (dollars in thousands):


	Payment due by period
	Total		Less than		1-3		3-5		Due
Type of Obligation	Obligation		One Year		Years		Years		Thereafter
Long-Term Debt
Revolving credit facility	$	50,000	$	—	$	—	$	50,000	$	—
Term loan facility		130,000		—		—		130,000		—
Other		113		73		40		—		—
Non-competition agreements		1,200		250		500		300		150
Operating leases		14,651		2,542		4,962		3,163		3,984
Interest expense(1)
Revolving Credit Facility		15,317		3,718		7,436		4,163		—
Term loan facility		39,316		9,544		19,088		10,684		—
Other		7		6		1		—		—


Total contractual cash obligations	$	250,604	$	16,133	$	32,027	$	198,310	$	4,134


(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, 2006, we had an outstanding irrevocable letter of credit in the amount of $0.1 million which was issued under our revolving credit facility. This letter of credit was issued to the Texas Commission on Environmental Quality to provide financial assurance for our used oil handling program.

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

Description of Our Credit Facility

On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of credit sub-limit. Our credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25.0 million resulting in a committed $120.0 million revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of September 30, 2006, we had $50.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of September 30, 2006, we had $69.9 million available under our revolving credit facility.

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

Draws made under our credit facility are normally made to fund acquisitions, growth capital expenditures and for working capital requirements. During the current fiscal year, draws on our credit facilities have ranged from a low of $130.0 million to a high of $197.7 million.

Our obligations under the credit facility are secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees. 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 January 1, 2007, this margin will increase to 2.50%. We incur a commitment fee on the unused portions of the credit facility.

Effective April 13, 2006, we entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010.

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.

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. 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 9, 2006, our outstanding indebtedness includes $190.1 million under our credit facility.

Seasonality

A substantial portion of our revenues are dependent on sales prices of products, particularly LPGs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for LPGs 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 and nine months ended September 30, 2006 and 2005. However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot assure you that we will be able to pass along increased costs to our customers.

Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot assure you that we will be able to pass along increased operating expenses to our customers.

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the three and nine months ended September 30, 2006 or 2005. 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 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. The principal market risk to which we are exposed is commodity price risk for LPGs. We also incur, to a lesser extent, risks related to interest rate fluctuations. Historically, we have not engaged in commodity contract trading or hedging activities. However, in connection with our acquisition of Prism Gas, we have initiated hedging activities with respect to commodity price risks.

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. However, in connection with the acquisition of Prism Gas, we have established a hedging policy and monitor and manage the commodity market risk associated with the commodity risk exposure of the Prism Gas acquisition. 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 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 have established a maximum credit limit threshold pursuant to our hedging policy. Under our hedging policy, we limit our counterparty risk to investment-grade counterparties.

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

Based on estimated volumes, as of September 30, 2006, Prism Gas had hedged approximately 63%, 60%, 22%, and 14% of its commodity risk by volume for 2006, 2007, 2008, and 2009, respectively. As of September 30, 2006, derivative assets of $900 were included in other current assets and $190 were included in non-current assets on the balance sheet. Derivative liabilities of $56 were included in other current liabilities and $204 were included in long-term liabilities on the balance sheet. We anticipate 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 we will be able to do so or that the terms thereof will be similar to 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
2006	Ethane	6,000 BBL/Month	Ethane Swap ($29.09)	Mt. Belvieu
2006	Condensate & Natural Gasoline	2,000 BBL/Month	Crude Oil Swap ($66.80)	NYMEX
2006	Condensate & Natural Gasoline	2,000 BBL/Month	Crude Oil Swap ($66.25)	NYMEX
2006	Condensate & Natural Gasoline	1,000 BBL/Month	Crude Oil Swap ($65.10)	NYMEX
2006	Natural Gas	10,000 MMBTU/Month	Natural Gas Swap ($9.03)	Houston Ship Channel
2006	Natural Gas	10,000 MMBTU/Month	Natural Gas Swap ($9.54)	Houston Ship Channel
2007	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($65.95)	NYMEX
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Swap ($9.14)	Henry Hub
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Basis Swap (-$0.60)	Henry Hub to Centerpoint East
2007	Ethane	8,000 BBL/Month	Ethane Swap ($28.04)	Mt. Belvieu
2008	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($66.20)	NYMEX
2009	Condensate & Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($69.08)	NYMEX

Our principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of our natural gas and NGL sales are made at market-based prices. Our standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or continuance of deliveries to the buyer after the buyer provides security for payment in a form satisfactory to us. For additional information regarding our hedging activities, see “Note 8 – Commodity Cash Flow Hedges” in our “Notes to Consolidated and Condensed Financial Statements” contained herein.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our revolving credit facility, which had a floating interest rate as of November 9, 2006. We had a total of $190.1 million of indebtedness outstanding under our credit facility at November 9, 2006. Effective April 13, 2006, we entered into a cash flow

hedge that swaps $75.0 million of floating rate debt to a fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. This cash flow hedge matures in November 2010. The impact of a 1% increase in interest rates on the remaining amount of floating rate debt of $115.1 million would result in an increase in interest expense and a corresponding decrease in net income of approximately $1.2 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 December 31, 2005. 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.

INDEX TO EXHIBITS


Exhibit
Number		Exhibit Name
3.1		Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).

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

3.3		Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).

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

3.5		Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).

3.6		Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 33-91706), filed July 1, 2002, and incorporated herein by reference).

3.7		Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).

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

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

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

10.1		First Amendment to Second Amended and Restated Credit Agreement, dated as of June 30, 2006, among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Martin Operating GP LLC, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., the financial institution parties to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed July 3, 2006, 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.”


*		Filed herewith


	Page
PART I – FINANCIAL INFORMATION		1

Item 1. Financial Statements		1
Consolidated and Condensed Balance Sheets as of September 30, 2006 (unaudited) and December 31, 2005 (audited)		1
Consolidated and Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2006 and 2005 (unaudited)		2
Consolidated and Condensed Statements of Capital for the Nine Months Ended September 30, 2006 and 2005 (unaudited)		3
Consolidated and Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2006 and 2005 (unaudited)		4
Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005 (unaudited)		5
Notes To Consolidated Financial Statements (unaudited)		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3. Quantitative and Qualitative Disclosures about Market Risk		43

Item 4. Controls and Procedures		45

PART II. OTHER INFORMATION		46

Item 1. Legal Proceedings		46

Item 1A. Risk Factors		46

Item 6. Exhibits		46

SIGNATURE
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


	Martin Midstream Partners L.P.

	By:	Martin Midstream GP LLC
		Its General Partner

Date: November 9, 2006	By:	/s/ Ruben S. Martin
		Ruben S. Martin
		President and Chief Executive Officer