UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2008

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

Yes o No þ

     The number of the registrant’s Common Units outstanding at May 7, 2008 was 12,837,480. The number of the registrant’s subordinated units outstanding at May 7, 2008 was 1,701,346.

 

 

		Page
PART I – FINANCIAL INFORMATION			1
Item 1. Financial Statements			1
Consolidated and Condensed Balance Sheets as of March 31, 2008 (unaudited) and December 31, 2007 (audited)			1
Consolidated and Condensed Statements of Operations for the Three Months Ended March 31, 2008 and 2007 (unaudited)			2
Consolidated and Condensed Statements of Capital for the Three Months Ended March 31, 2008 and 2007 (unaudited)			3
Consolidated and Condensed Statements of Comprehensive Income for the Three Months Ended March 31, 2008 and 2007 (unaudited)			4
Consolidated and Condensed Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007 (unaudited)			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			24
Item 3. Quantitative and Qualitative Disclosures about Market Risk			40
Item 4. Controls and Procedures			41
PART II – OTHER INFORMATION			42
Item 1. Legal Proceedings			42
Item 1A. Risk Factors			42
Item 6. Exhibits			42
SIGNATURE
CERTIFICATIONS
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Balance Sheets

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

		March 31,				December 31,
		2008				2007
		(Unaudited)				(Audited)
Assets
Cash		$	6,918			$	4,113
Accounts and other receivables, less allowance for doubtful accounts of $298 and $211			96,493				88,039
Product exchange receivables			10,244				10,912
Inventories			51,051				51,798
Due from affiliates			3,908				2,325
Other current assets			1,743				819
Total current assets			170,357				158,006
Property, plant and equipment, at cost			478,265				441,117
Accumulated depreciation			(103,025	)			(98,080	)
Property, plant and equipment, net			375,240				343,037
Goodwill			37,405				37,405
Investment in unconsolidated entities			75,664				75,690
Other assets, net			8,937				9,439
		$	667,603			$	623,577
Liabilities and Partners’ Capital
Current installments of long-term debt		$	1			$	21
Trade and other accounts payable			123,927				104,598
Product exchange payables			21,875				24,554
Due to affiliates			7,037				7,543
Income taxes payable			587				602
Other accrued liabilities			12,533				9,254
Total current liabilities			165,960				146,572
Long-term debt			255,000				225,000
Deferred income taxes			8,735				8,815
Other long-term obligations			9,914				7,342
Total liabilities			439,609				387,729
Partners’ capital			239,748				242,610
Accumulated other comprehensive income (loss)			(11,754	)			(6,762	)
Total partners’ capital			227,994				235,848
Commitments and contingencies
		$	667,603			$	623,577

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Three Months Ended
		March 31,
		2008				2007
Revenues:
Terminalling and storage		$	7,920			$	6,951
Marine transportation			16,403				13,884
Product sales:
Natural gas services			207,092				101,788
Sulfur services			70,225				29,380
Terminalling and storage			11,376				3,793
			288,693				134,961
Total revenues			313,016				155,796
Costs and expenses:
Cost of products sold:
Natural gas services			202,850				96,772
Sulfur services			56,340				21,801
Terminalling and storage			9,921				3,015
			269,111				121,588
Expenses:
Operating expenses			24,217				18,993
Selling, general and administrative			3,479				2,721
Depreciation and amortization			7,340				4,894
Total costs and expenses			304,147				148,196
Other operating income			139				—
Operating income			9,008				7,600
Other income (expense):
Equity in earnings of unconsolidated entities			3,510				2,050
Interest expense			(4,743	)			(3,577	)
Other, net			181				79
Total other income (expense)			(1,052	)			(1,448	)
Net income before taxes			7,956				6,152
Income tax benefit (expense)			61				(349	)
Net income		$	8,017			$	5,803
General partner’s interest in net income		$	651			$	275
Limited partners’ interest in net income		$	7,366			$	5,528
Net income per limited partner unit – basic and diluted		$	0.51			$	0.42
Weighted average limited partner units – basic			14,532,826				13,152,826
Weighted average limited partner units – diluted			14,535,491				13,155,125

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Partners’ Capital
																						Accumulated
																						Other
																		General				Comprehensive
		Common								Subordinated								Partner				Income (Loss)
		Units				Amount				Units				Amount				Amount				Amount				Total
Balances – January 1, 2007			10,603,808			$	201,387				2,552,018			$	(6,237	)		$	3,253			$	122			$	198,525
Net income			—				4,608				—				920				275				—				5,803
Cash distributions			—				(6,574	)			—				(1,582	)			(311	)			—				(8,467	)
Unit-based compensation			—				11				—				—				—				—				11
Adjustment in fair value of derivatives			—				—				—				—				—				(1,111	)			(1,111	)
Balances – March 31, 2007			10,603,808			$	199,432				2,552,018			$	(6,899	)		$	3,217			$	(989	)		$	194,761
Balances – January 1, 2008			12,837,480			$	244,520				1,701,346			$	(6,022	)		$	4,112			$	(6,762	)		$	235,848
Net income			—				6,141				—				1,225				651				—				8,017
Cash distributions			—				(8,986	)			—				(1,191	)			(719	)			—				(10,896	)
Unit-based compensation			—				17				—				—								— —				17
Adjustment in fair value of derivatives			—				—				—				—				—				(4,992	)			(4,992	)
Balances – March 31, 2008			12,837,480			$	241,692				1,701,346			$	(5,988	)		$	4,044			$	(11,754	)		$	227,994

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Three Months Ended
		March 31,
		2008				2007
Net income		$	8,017			$	5,803
Changes in fair values of commodity cash flow hedges			213				(164	)
Cash flow hedging losses reclassified to earnings			(665	)			(432	)
Changes in fair value of interest rate cash flow hedges			(4,540	)			(515	)
Comprehensive income		$	3,025			$	4,692

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

		Three Months Ended
		March 31,
		2008				2007
Cash flows from operating activities:
Net income		$	8,017			$	5,803
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			7,340				4,894
Amortization of deferred debt issuance costs			279				270
Deferred taxes			(80	)			—
Gain on disposition or sale of property, plant and equipment			(140	)			—
Equity in earnings of unconsolidated entities			(3,510	)			(2,050	)
Distributions from unconsolidated entities			—				200
Distributions in-kind from equity investments			2,580				1,853
Non-cash derivatives loss			1,888				593
Other			17				11
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables			(8,454	)			(1,964	)
Product exchange receivables			668				5,094
Inventories			747				6,850
Due from affiliates			(1,583	)			230
Other current assets			(1,159	)			26
Trade and other accounts payable			19,329				1,789
Product exchange payables			(2,679	)			(8,719	)
Due to affiliates			(506	)			(2,515	)
Income taxes payable			(15	)			190
Other accrued liabilities			(809	)			(770	)
Change in other non-current assets and liabilities			14				126
Net cash provided by operating activities			21,944				11,911
Cash flows from investing activities:
Payments for property, plant and equipment			(33,600	)			(15,764	)
Acquisitions, net of cash acquired			(5,983	)			—
Proceeds from sale of property, plant and equipment			404				—
Return of investments from unconsolidated entities			450				1,125
Distributions from (contributions to) unconsolidated entities for operations			506				(3,883	)
Net cash used in investing activities			(38,223	)			(18,522	)
Cash flows from financing activities:
Payments of long-term debt			(58,120	)			(25,119	)
Proceeds from long-term debt			88,100				41,100
Cash distributions paid			(10,896	)			(8,467	)
Net cash provided by financing activities			19,084				7,514
Net increase in cash			2,805				903
Cash at beginning of period			4,113				3,675
Cash at end of period		$	6,918			$	4,578

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

(1) General

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

     The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and U.S. generally accepted accounting principles for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by generally accepted accounting principles for annual audited financial statements of the type contained in the Partnership’s annual reports on Form 10-K. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for such interim periods are not necessarily indicative of the results of operations for the full year. These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2008.

     (a) Use of Estimates

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

     (b) Unit Grants

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

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

     The Partnership accounts for the transaction under Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based payment transactions was $17 and $11 for the three months ended March 31, 2008 and 2007, respectively. The Partnership’s general partner contributed cash of $2 in January 2006 and $3 in May 2007 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.

     (c) Incentive Distribution Rights

     The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights in the Partnership.  Incentive distribution rights represent the right to

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved.  The Partnership is required to distribute all of its available cash from operating surplus, as defined in the partnership agreement.  The target distribution levels entitle the general partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months ended March 31, 2008 and 2007 the general partner received $501 and $163, respectively, in incentive distributions.

     (d) Net Income per Unit

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

     EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period where the Partnership’s aggregate net income exceeds the Partnership’s aggregate distribution for such period, the Partnership is required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. 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. EITF 03-06 does not impact the Partnership’s overall net income or other financial results because the Partnership does not have undistributed earnings in any period presented.

     In March 2008, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 07-4 “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” This pronouncement provides that incentive distribution rights (IDRs) in a typical master limited partnership are participating securities under Statement 128, but earnings in excess of partnership’s “available cash” should not be allocated to the IDR holders for purposes of calculating earnings-per-share using the two class method when “available cash” represents a specified threshold that limits participation. The standard only applies when payments to IDR holders are accounted for as equity distributions. The standard is effective for fiscal years beginning after December 15, 2008, and applied retrospectively to all periods presented. The Partnership does not expect the adoption of EITF 07-4 to have a material effect on the consolidated financial statements because the Partnership’s earnings have not historically exceeded distributions.

     The weighted average units outstanding for basic net income per unit were 14,532,826 and 13,152,826 for the three months ended March 31, 2008 and 2007, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 2,665 and 2,299 for the three months ended March 31, 2008 and 2007, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

     (e) Income taxes

     With respect to our taxable subsidiary (Woodlawn Pipeline Co., Inc.), income taxes are accounted for under the asset and liability method. Deferred tax assets

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

     (f) Reclassification

     The Partnership made a reclassification to the consolidated balance sheet for the year ended December 31, 2007 to properly classify current and long-term derivative liabilities. This reclassification had no impact on the total liabilities reported in consolidated balance sheet for the year ended December 31, 2007.

(2) New Accounting Pronouncements

     In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) FAS 157-2, which delayed the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statement on a recurring basis, to fiscal years beginning after November 15, 2008. On January 1, 2008, the Partnership adopted the portion of SFAS No. 157 that was not delayed, and since the Partnership’s existing fair value measurements are consistent with the guidance of the Statement, the partial adoption of SFAS No. 157 did not have a material impact on the Partnership’s consolidated financial statements. The adoption of the deferred portion of SFAS No. 157 on January 1, 2009 is not expected to have a material impact on the Partnership’s consolidated financial statements. See Note 3 for expanded disclosures about fair value measurements.

     In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Partnership to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Partnership would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Partnership currently has no plans to apply SFAS No. 159.

     In December 2007, the FASB revised SFAS No. 141, “Business Combinations,” to establish revised principles and requirements for how entities will recognize and measure assets and liabilities acquired in a business combination. SFAS No. 141 is effective for business combinations completed on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Partnership will apply the guidance of SFAS No. 141 to business combinations completed on or after January 1, 2009.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51.” SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 is effective on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Partnership is currently evaluating the impact of adopting SFAS No. 160 on January 1, 2009.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133.” SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 is effective for fiscal years and interim periods

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

beginning after November 15, 2008. The Partnership is evaluating the additional disclosures required by SFAS No. 161 beginning January 1, 2009.

(3) Fair Value Measurements

     During the first quarter of 2008, the Partnership adopted Financial Accounting Standards Board (FASB) Statement No. 157, Fair Value Measurements (FAS 157). FAS 157 established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of FAS 157 had no impact on the Partnership’s financial position or results of operations.

     FAS 157 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that each asset and liability carried at fair value be classified into one of the following categories:

     Level 1: Quoted market prices in active markets for identical assets or liabilities.

     Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

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

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

     As prescribed by the FAS 157 levels listed above, the Partnership considers the Partnership’s derivative assets and liabilities as Level 2. The net fair value of the Partnership’s assets and liabilities measured on a recurring basis was a liability of $16,722 and $ 9,843 at March 31, 2008 and December 31, 2007, respectively.

(4) Acquisitions

     (a) Stanolind Assets

     In January 2008, The Partnership acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management Corporation (“Martin Resource Management”) for $5,983 which was allocated to property, plant and equipment. The Partnership entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks.

     (b) Asphalt Terminal

     In October 2007, the Partnership acquired the asphalt assets of Monarch Oil, Inc. and related companies (“Monarch Oil”) for $3,927 which was allocated to property, plant and equipment. The results of Monarch Oil’s operations have been included in the consolidated financial statements beginning October 2, 2007. The assets are located in Omaha, Nebraska. The Partnership entered into an agreement with Martin Resource Management, whereby Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will bear all additional expenses to operate the facility.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

     (c) Lubricants Terminal

     In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) located in Channelview, Texas. The results of Mega Lubricant’s operations have been included in the consolidated financial statements beginning June 13, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $1,020 was recorded as goodwill. The goodwill was a result of Mega Lubricant’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional lubricant blending and truck loading and unloading services to customers. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment. The terminal is located on 5.6 acres of land, and consists of 38 tanks with a storage capacity of approximately 15,000 Bbls, pump and piping infrastructure for lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an administrative office.

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

Current assets		$	446
Property, plant and equipment, net			3,042
Goodwill			1,020
Other assets			530
Other liabilities			(300	)
Total		$	4,738

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

     (d) Woodlawn Pipeline Co., Inc.

     On May 2, 2007, the Partnership, through its subsidiary Prism Gas Systems I, L.P. (“Prism Gas”), acquired 100% of the outstanding stock of Woodlawn Pipeline Co., Inc. (“Woodlawn”). The results of Woodlawn’s operations have been included in the consolidated financial statements beginning May 2, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $8,785 was recorded as goodwill. The goodwill was a result of Woodlawn’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional gathering services to customers through internal growth projects including natural gas processing, fractionation and pipeline expansions as well as new pipeline construction. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment.

     Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 Mcf/day processing plant. Prism Gas also acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from Woodlawn to the Texas Eastern Transmission pipeline system.

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

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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

Current assets		$	4,297
Property, plant and equipment, net			29,101
Goodwill			8,785
Other assets			3,339
Current liabilities			(3,889	)
Deferred income taxes			(8,964	)
Other long-term obligations			(63	)
Total		$	32,606

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

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

(5) Inventories

     Components of inventories at March 31, 2008 and December 31, 2007 were as follows:

		March 31,				December 31,
		2008				2007
Natural gas liquids		$	15,967			$	31,283
Sulfur			17,215				7,490
Sulfur Based Products			9,542				6,626
Lubricants			5,779				5,345
Other			2,548				1,054
		$	51,051			$	51,798

(6) Investment in Unconsolidated Partnerships and Joint Ventures

     The Partnership, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”) and a 20% ownership interest in a partnership which owns the lease rights to Bosque County Pipeline (“BCP”). Each of these interests is accounted for under the equity method of accounting.

     In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $148 for the three months March 31, 2008 and 2007, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $10,537 and $10,685 at March 31, 2008 and December 31, 2007, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in the first three months of 2008 or the year ended December 31, 2007.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

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

     Activity related to these investment accounts is as follows:

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

		Waskom				PIPE				Matagorda				BCP				Total
Investment in unconsolidated entities, December 31, 2006		$	64,937			$	1,718			$	3,786			$	210			$	70,651
Distributions in kind			(1,853	)			—				—				—				(1,853	)
Distributions from (contributions to) unconsolidated entities for operations			3,883				—				—				—				3,883
Cash distributions			(1,125	)			(200	)			—				—				(1,325	)
Equity in earnings:
Equity in earnings from operations			1,864				293				74				(33	)			2,198
Amortization of excess investment			(137	)			(4	)			(7	)			—				(148	)
Investment in unconsolidated entities, March 31, 2007		$	67,569			$	1,807			$	3,853			$	177			$	73,406

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

										Three Months Ended
		As of March 31								March 31
		Total				Partner’s								Net
		Assets				Capital				Revenues				Income
2008
Waskom		$	67,666			$	57,658			$	26,733			$	7,280

		As of December 31
2007
Waskom		$	66,772			$	57,149			$	14,799			$	3,729

     (7) Commodity Cash Flow Hedges

     The Partnership is exposed to market risks associated with commodity prices, counterparty credit and interest rates. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. In addition, the Partnership is 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,

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

the Partnership manages interest rate exposure by targeting a ratio of fixed and floating interest rates it deems prudent and using hedges to attain that ratio.

     In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. The Partnership has adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges.

     Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of March 31, 2008, 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.

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

		Three Months
		Ended March 31
		2008				2007
Change in fair value of derivatives that do not qualify for hedge accounting and settlements of maturing hedges		$	(2,181	)		$	(283	)
Ineffective portion of derivatives qualifying for hedge accounting			121				124
Change in fair value of derivatives in the Consolidated Statement of Operations		$	(2,060	)		$	(159	)

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

		March 31,				December 31,
		2008				2007
Fair value of derivative assets — current		$	—			$	235
Fair value of derivative assets — long term			105				—
Fair value of derivative liabilities — current			(4,100	)			(3,261	)
Fair value of derivative liabilities — long term			(2,740	)			(2,140	)
Net fair value of derivatives		$	(6,735	)		$	(5,166	)

     Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2008 (all gas quantities are expressed in British Thermal Units, crude oil and NGLs are expressed in barrels). As of March 31, 2008, the remaining term of the contracts extend no later than December 2011, with no single contract longer than one year. The Partnership’s counterparties to the derivative contracts include Shell Energy North America (US) L.P., Morgan Stanley Capital Group Inc., Wachovia Bank and Wells Fargo Bank. For the period ended March 31, 2008, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in other comprehensive income as a component of equity since the Partnership has designated a portion of its derivative instruments as hedges as of March 31, 2008.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

March 31, 2008
		Total
		Volume Per				Remaining Terms
Transaction Type		Month		Pricing Terms		of Contracts		Fair Value
Mark to Market Derivatives::
Natural Gas swap		30,000 MMBTU		Fixed price of $8.12 settled against Houston Ship Channel first of the month		April 2008 to December 2008			(500	)
Crude Oil Swap		3,000 BBL		Fixed price of $70.75 settled against WTI NYMEX average monthly closings		April 2008 to December 2008			(770	)
Crude Oil Swap		3,000 BBL		Fixed price of $69.08 settled against WTI NYMEX average monthly closings		January 2009 to December 2009			(900	)
Crude Oil Swap		3,000 BBL		Fixed price of $70.90 settled against WTI NYMEX average monthly closings		January 2009 to December 2009			(839	)
Total swaps not designated		as cash flow hedges						$	(3,009	)
Cash Flow Hedges:
Crude Oil Swap		5,000 BBL		Fixed price of $66.20 settled against WTI NYMEX average monthly closings		April 2008 to December 2008			(1,482	)
Ethane Swap		5,000 BBL		Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings		April 2008 to December 2008			(481	)
Natural Gasoline Swap		3,000 BBL		Fixed price of $87.31 (Jan-Mar) and $85.10 (Apr-June) settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.		April 2008 to June 2008			(61	)
Natural Gasoline Swap		3,000 BBL		Fixed price of $86.52 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.		July 2008 to September 2008			(38	)
Natural Gasoline Swap		3,000 BBL		Fixed price of $85.79 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.		October 2008 to December 2008			(39	)
Natural Gas swap		30,000 MMBTU		Fixed price of $9.025 settled against Inside Ferc Columbia Gulf daily average		January 2009 to December 2009			(220	)
Crude Oil Swap		1,000 BBL		Fixed price of $70.45 settled against WTI NYMEX average monthly closings		January 2009 to December 2009			(285	)
Natural Gasoline Swap		2,000 BBL		Fixed price of $86.42 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.		January 2009 to December 2009			(24	)
Crude Oil Swap		2,000 BBL		Fixed price of $69.15 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			(519	)
Crude Oil Swap		3,000 BBL		Fixed price of $72.25 settled against WTI NYMEX average monthly closings		January 2010 to December 2010			(682	)
Crude Oil Swap		2,000 BBL		Fixed price of $99.15 settled against WTI NYMEX average monthly closings		January 2011 to December 2011			105
Total swaps designated as cash flow hedges								$	(3,726	)
Total net fair value of derivatives								$	(6,735	)

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

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

     As a result of the Prism Gas acquisition, the Partnership is exposed to the impact of market fluctuations in the prices of natural gas, 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 2011 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, ethane, and natural gasoline.

     Based on estimated volumes, as of March 31, 2008, Prism Gas had hedged approximately 69%, 44%, 14% and 6% of its commodity risk by volume for 2008, 2009, 2010 and 2011, 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.

Hedging Arrangements in Place
As of March 31, 2008

Year		Commodity Hedged		Volume		Type of Derivative		Basis Reference
2008		Condensate & Natural Gasoline		5,000 BBL/Month		Crude Oil Swap ($66.20)		NYMEX
2008		Natural Gas		30,000 MMBTU/Month		Natural Gas Swap ($8.12)		Houston Ship Channel
2008		Ethane		5,000 BBL/Month		Ethane Swap ($27.30)		Mt. Belvieu
2008		Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($70.75)		NYMEX
2008		Natural Gasoline		3,000 BBL/Month		Natural Gasoline Swap ($87.31)		Mt. Belvieu (Non-TET)
2008		Natural Gasoline		3,000 BBL/Month		Natural Gasoline Swap ($86.52)		Mt. Belvieu (Non-TET)
2008		Natural Gasoline		3,000 BBL/Month		Natural Gasoline Swap ($85.79)		Mt. Belvieu (Non-TET)
2008		Natural Gasoline		3,000 BBL/Month		Natural Gasoline Swap ($85.10)		Mt. Belvieu (Non-TET)
2009		Natural Gas		30,000 MMBTU/Month		Natural Gas Swap (9.025)		Columbia Gulf
2009		Condensate & Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($69.08)		NYMEX
2009		Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($70.90)		NYMEX
2009		Condensate		1,000 BBL/Month		Crude Oil Swap ($70.45)		NYMEX
2009		Natural Gasoline		2,000 BBL/Month		Natural Gasoline Swap ($86.42)		Mt. Belvieu (Non-TET)
2010		Condensate		2,000 BBL/Month		Crude Oil Swap ($69.15)		NYMEX
2010		Natural Gasoline		3,000 BBL/Month		Crude Oil Swap ($72.25)		NYMEX
2011		Natural Gasoline		2,000 BBL/Month		Crude Oil Swap ($99.15)		NYMEX

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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

Impact of Cash Flow Hedges

Crude Oil

     For the three months ended March 31, 2008 and 2007, net gains and losses on swap hedge contracts decreased crude revenue by $1,092 and increased crude revenue by $143, respectively. As of March 31, 2008 an unrealized derivative fair value loss of $2,319, related to cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). Fair value losses of $938, $285 and $1,201 are expected to be reclassified into earnings in 2008, 2009 and 2010, respectively. A fair value gain of $105 is expected to be reclassified into earnings in 2011. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

Natural Gas

     For the three months ended March 31, 2008 and 2007, net losses on swap hedge contracts decreased gas revenue by $699 and $373, respectively. As of March 31, 2008 an unrealized derivative fair value loss of $220, related to cash flow hedges of natural gas price risk, was recorded in other comprehensive income (loss). This fair value loss is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

NGLs

     For the three months ended March 31, 2008 and 2007, net gains and losses on swap hedge contracts decreased liquids revenue by $269 and increased liquids revenue by $71, respectively. As of March 31, 2008, an unrealized derivative fair value loss of $633 related to cash flow hedges of NGLs price risk was recorded in other comprehensive income (loss). Fair value losses of $609 and $24 are expected to be reclassified into earnings in 2008 and 2009, respectively. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

(8) Interest Rate Cash Flow Hedge 

     The Partnership has entered into several cash flow hedge agreements with an aggregate notional amount of $195,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. The Partnership designated these swap agreements as cash flow hedges. Under these swap agreements, the Partnership pays a fixed rate of interest and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because these swaps are designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of these

     hedges, these swaps were identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and these swaps remain equal. This condition results in a 100% effective swap for the following hedges:

Date of Hedge		Notional Amount				Fixed Rate				Maturity Date
January 2008		$	25,000				3.400	%		January 2010
September 2007		$	25,000				4.605	%		September 2010
November 2006		$	40,000				4.820	%		December 2009
March 2006		$	75,000				5.250	%		November 2010

     In November 2006, the Partnership entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006; therefore, hedge accounting was not utilized. The swap has been recorded at fair value at March 31, 2008 with an offset to current operations.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

     The Partnership recognized increases in interest expense of $773 and $67 for the three months ended March 31, 2008 and 2007, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate hedges

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

		March 31,				December 31,
		2008				2007
Fair value of derivative liabilities — current		$	(4,491	)		$	(1,241	)
Fair value of derivative liabilities — long term			(5,496	)			(3,436	)
Net fair value of derivatives		$	(9,987	)		$	(4,677	)

(9) Related Party Transactions

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

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

		Three Months Ended March 31,
		2008				2007
Revenues:
Terminalling and storage		$	3,778			$	2,585
Marine transportation			6,224				6,554
Product sales:
Natural gas services			1,199				—
Sulfur services			4,511				8
Terminalling and storage			18				3
			5,728				11
		$	15,730			$	9,150
Costs and expenses:
Cost of products sold:
Natural gas services		$	20,403			$	12,210
Sulfur services			3,318				3,978
Terminalling and storage			278				—
		$	23,999			$	16,188
Expenses:
Operating expenses
Marine transportation		$	7,224			$	4,162
Natural gas services			383				385
Sulfur services			165				277
Terminalling and storage			2,271				1,037
		$	10,043			$	5,861
Selling, general and administrative:
Natural gas services		$	200			$	167
Sulfur services			440				387
Terminalling and storage			—				14
Indirect overhead allocation, net of reimbursement			674				326
		$	1,314			$	894

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

(10) Business Segments

     The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation and sulfur services. The Partnership’s reportable segments are strategic business units 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, 2007 filed with the SEC on March 5, 2008. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

										Operating								Operating
						Revenues				Revenues				Depreciation				Income
		Operating				Intersegment				after				and				(loss) after				Capital
		Revenues				Eliminations				Eliminations				Amortization				eliminations				Expenditures
Three months ended March 31, 2008
Terminalling and storage		$	20,362			$	(1,066	)		$	19,296			$	2,141			$	1,176			$	4,451
Natural gas services			207,092				—				207,092				977				41				1,169
Marine transportation			16,981				(578	)			16,403				2,794				792				26,126
Sulfur services			70,241				(16	)			70,225				1,428				8,326				1,854
Indirect selling, general and administrative			—				—				—				—				(1,327	)			—
Total		$	314,676			$	(1,660	)		$	313,016			$	7,340			$	9,008			$	33,600
Three months ended March 31, 2007
Terminalling and storage		$	10,841			$	(97	)		$	10,744			$	1,340			$	2,977			$	5,006
Natural gas services			101,788				—				101,788				431				1,944				704
Marine transportation			14,876				(992	)			13,884				1,939				1,018				5,103
Sulfur services			29,530				(150	)			29,380				1,184				2,417				4,951
Indirect selling, general and administrative			—				—				—				—					(756)			—
Total		$	157,035			$	(1,239	)		$	155,796			$	4,894			$	7,600			$	15,764

     The following table reconciles operating income to net income:

		Three Months Ended
		March 31
		2008				2007
Operating income		$	9,008			$	7,600
Equity in earnings of unconsolidated entities			3,510				2,050
Interest expense			(4,743	)			(3,577	)
Other, net			181				79
Income taxes			61				(349	)
Net income		$	8,017			$	5,803

     Total assets by segment are as follows:

		March 31,				December 31,
		2008				2007
Total assets:
Terminalling and storage		$	138,936			$	126,575
Natural gas services			254,642				268,230
Marine transportation			130,797				107,081
Sulfur services			143,228				121,691
Total assets		$	667,603			$	623,577

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

(11) Public Equity Offerings

     In May 2007, the Partnership completed a public offering of 1,380,000 common units at a price of $42.25 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,380,000 common units, net of underwriters’ discounts, commissions and offering expenses were $55,933. The Partnership’s general partner contributed $1,190 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital.

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

Proceeds received:
Sale of common units		$	58,305
General partner contribution			1,190
Total proceeds received		$	59,495
Use of Proceeds:
Underwriter’s fees		$	2,107
Professional fees and other costs			265
Repayment of debt under revolving credit facility			55,850
Working capital			1,273
Total use of proceeds		$	59,495

(12) Long-term Debt

     At March 31, 2008 and December 31, 2007, long-term debt consisted of the following:

		March 31,				December 31,
		2008				2007
**$195,000 Revolving loan facility at variable interest rate (6.13%* weighted average at March 31, 2008), 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 and equity method investees		$	125,000			$	95,000
***$130,000 Term loan facility at variable interest rate (6.99%* at March 31, 2008), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries			130,000				130,000
Other secured debt maturing in 2008, 7.25%			1				21
Total long-term debt			255,001				225,021
Less current installments			1				21
Long-term debt, net of current installments		$	255,000			$	225,000

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

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

     On November 10, 2005, the Partnership entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the Partnership increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. Effective December 28, 2007, the Partnership increased its revolving credit facility $75,000 resulting in a committed $195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of March 31, 2008, the Partnership had $125,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of March 31, 2008, the Partnership had $69,880 available under its revolving credit facility.

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

     The Partnership’s obligations under the credit facility are secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. 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

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

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) allow 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 the credit facility for the year ended December 31, 2007 and as of March 31, 2008.

     On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made or required under the term loan through March 31, 2008. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Partnership must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

     Draws made under the Partnership’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Partnership’s credit facility have ranged from a low of $225,000 to a high of $279,200. As of March 31, 2008, the Partnership had $69,880 available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility.

     In connection with the Partnership’s Stanolind asset acquisition on January 22, 2008, the Partnership borrowed approximately $6,000 under its revolving credit facility.

     In connection with the Partnership’s Monarch acquisition on October 2, 2007, the Partnership borrowed approximately $3,900 under its revolving credit facility.

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

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

     The Partnership paid cash interest in the amount of $4,333 and $3,603 for the three months ended March 31, 2008 and 2007, respectively. Capitalized interest was $452 and $539 for the three months ended March 31, 2008 and 2007, respectively.

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

(13) Income Taxes

     The operations of a partnership are generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. Effective January 1, 2007, the Partnership is subject to the Texas margin tax as described below. Our subsidiary, Woodlawn, is subject to income taxes due to its corporate structure. Woodlawn was not acquired until May 2, 2007 and accordingly, had no effect on the financial statements for the three months ended March 31, 2007. A current federal income tax benefit of $164 and state income tax expense of $6 related to the operation of the subsidiary was recorded for the three months ended March 31, 2008. In connection with the Woodlawn acquisition, the Partnership also established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment. A deferred tax benefit related to these basis differences of $80 was recorded for the three months ended March 31, 2008, and a deferred tax liability of $8,735 and $8,815 related to the basis differences existing at March 31, 2008 and at December 31, 2007, respectively.

     The final liquidation of the Prism Gas corporate entity was completed on November 15, 2006. Additional federal and state income taxes of $214 resulting from the liquidation were recorded in income tax expense for the three months ended March 31, 2007.

     On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Partnership has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change was immaterial.  The impact of the change in deferred tax assets does not have a material impact on tax expense. State income taxes attributable to the Texas margin tax of $183 and $135 were recorded in current income tax expense for the three months ended March 31, 2008 and 2007, respectively.

     In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Partnership adopted FIN 48 effective January 1, 2007. There was no impact to the Partnership’s financial statements as a result of adopting FIN 48, nor is there any impact in the current financial statements.

     The components of income tax expense (benefit) from operations recorded for the three months ended March 31, 2008 and 2007 are as follows:

		Three Months Ended
		2008				2007
Current:
Federal		$	(164	)		$	169
State			183				180
		$	19			$	349
Deferred:
Federal		$	(80	)		$	—
		$	(61	)		$	349

(14) CONSOLIDATED FINANCIAL STATEMENTS

       In connection with the Partnership’s filing of a shelf registration statement on Form S-3 with the Securities and Exchange Commission (the “Registration Statement”), Martin Operating Partnership L.P. (the

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
March 31, 2008
(Unaudited)

“Operating Partnership”), the Partnership’s wholly-owned subsidiary, may issue unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time under the registration statement. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities under the Registration Statement which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. The Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has no independent assets or operations, the guarantees are full and unconditional and the other subsidiary of the Partnership is minor. There are no significant restrictions on the ability of the Partnership or the Operating Partnership to obtain funds from any of their respective subsidiaries by dividend or loan.

(15) COMMITMENTS AND CONTINGENCIES

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

     In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of the Partnership’s tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, the Partnership has been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two of the Partnership’s employees were served with grand jury subpoenas during the fourth quarter of 2007. The Partnership is cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against the Partnership.

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

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

Forward-Looking Statements

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

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

     Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2008.

Overview

     We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Our four primary business lines include:

	•		Terminalling and storage services for petroleum and by-products;
	•		Natural gas services;
	•		Marine transportation services for petroleum products and by-products; and
	•		Sulfur and sulfur-based products gathering, processing, marketing, 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 an approximate 34.9% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest and incentive distribution rights in us.

     Martin Resource Management has operated our business for several years. Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and

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

Critical Accounting Policies

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

     You should also read Note 1, “General” in Notes to Consolidated and Condensed Financial Statements contained in this quarterly report and the “Significant Accounting Policies” note in the consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 5, 2008 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. Our hedging policy allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges or hedges that become ineffective are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of March 31, 2008, 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

     The Partnership enters into product exchange agreements with third parties whereby the Partnership agrees to exchange natural gas liquids (“NGLs”) and sulfur with third parties. The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method.

     Revenue Recognition

     Revenue for our four 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 the Partnership’s 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 services – Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in

storage, or by pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.

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

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

     Equity Method Investments

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

     We own an unconsolidated 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”) and a 20% ownership interest in a partnership which owns the lease rights to Bosque County Pipeline (“BCP”). Each of these interests is accounted for under the equity method of accounting.

     Goodwill

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

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

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

     Environmental Liabilities

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

     Allowance for Doubtful Accounts

     In evaluating the collectability of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past

due and historical collection experience. Based on these assessments, we record specific and general reserves for bad debts to reduce the related receivables to the amount we ultimately expect to collect from customers.

     Asset Retirement Obligation

     We recognize and measure our asset and conditional asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset and based upon the estimate of the cost to settle the obligation at its anticipated future date. The obligation is accreted to its estimated future value and the asset retirement cost is depreciated over the estimated life of the asset.

Our Relationship with Martin Resource Management

     Martin Resource Management is engaged in the following principal business activities:

	•		providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;
	•		distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids;
	•		providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas;
	•		operating a small crude oil gathering business in Stephens, Arkansas;
	•		operating a lube oil processing facility in Smackover, Arkansas;
	•		operating an underground NGL storage facility in Arcadia, Louisiana;
	•		developing an underground natural gas 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;
	•		operating, solely for our account, an NGL truck loading and unloading and pipeline distribution terminal in Mont Belvieu, Texas; and
	•		operating, solely for our account, the asphalt facilities in Omaha, Nebraska.