Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________

FORM 10-Q

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

For the quarterly period ended March 31, 2011

¨	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 T No o

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

Yes o No o

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

Large accelerated filer £	Accelerated filer T
Non-accelerated filer £ (Do not check if a smaller reporting company)	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 T

The number of the registrant’s Common Units outstanding at May 4, 2011, was 19,582,332. The number of the registrant’s subordinated units outstanding at May 4, 2011, was 889,444.

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PART I – FINANCIAL INFORMATION		2

Item 1.	Financial Statements	2
	Consolidated and Condensed Balance Sheets as of March 31, 2011 (unaudited) and December 31, 2010 (audited)	2
	Consolidated and Condensed Statements of Operations for the Three Months Ended March 31, 2011 and 2010 (unaudited)	3
	Consolidated and Condensed Statements of Capital for the Three Months Ended March 31, 2011 and 2010 (unaudited)	4
	Consolidated and Condensed Statements of Comprehensive Income for the Three Months Ended March 31, 2011 and 2010 (unaudited)	5
	Consolidated and Condensed Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010 (unaudited)	6
	Notes to Consolidated and Condensed Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	51

Item 4.	Controls and Procedures	53

PART II. OTHER INFORMATION		54

Item 1.	Legal Proceedings	54

Item 1A.	Risk Factors	54

Item 5.	Other Information	54

Item 6.	Exhibits	56

SIGNATURE
CERTIFICATIONS

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	March 31, 2011 (Unaudited)			December 31, 2010 (Audited)
Assets
Cash	$	10,819		$	11,380
Accounts and other receivables, less allowance for doubtful accounts of $2,576 and $2,528, respectively		94,699			95,276
Product exchange receivables		5,254			9,099
Inventories		50,296			52,616
Due from affiliates		9,229			6,437
Fair value of derivatives		2,138			2,142
Other current assets		3,245			2,784
Total current assets		175,680			179,734

Property, plant and equipment, at cost		684,413			632,456
Accumulated depreciation		(210,627	)		(200,276	)
Property, plant and equipment, net		473,786			432,180

Goodwill		37,268			37,268
Investment in unconsolidated entities		100,236			98,217
Deferred debt costs		12,357			13,497
Other assets, net		25,851			24,582
	$	825,178		$	785,478
Liabilities and Partners’ Capital
Current portion of capital lease obligations	$	1,148		$	1,121
Trade and other accounts payable		80,504			82,837
Product exchange payables		19,703			22,353
Due to affiliates		11,271			6,957
Income taxes payable		1,037			811
Fair value of derivatives		1,093			282
Other accrued liabilities		13,333			10,034
Total current liabilities		128,089			124,395

Long-term debt and capital leases, less current maturities		344,655			372,862
Deferred income taxes		8,210			8,213
Fair value of derivatives		5,064			4,100
Other long-term obligations		1,947			1,102
Total liabilities		487,965			510,672

Partners’ capital		337,117			273,387
Accumulated other comprehensive income		96			1,419
Total partners’ capital		337,213			274,806
Commitments and contingencies
	$	825,178		$	785,478

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended March 31,
	2011			2010
Revenues:
Terminalling and storage *	$	18,123		$	16,041
Marine transportation *		19,399			17,877
Sulfur services		2,850			—
Product sales: *
Natural gas services		167,211			165,229
Sulfur services		56,908			34,409
Terminalling and storage		18,545			9,120
		242,664			208,758
Total revenues		283,036			242,676

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *		158,204			157,664
Sulfur services *		44,442			24,735
Terminalling and storage		16,560			8,446
		219,206			190,845
Expenses:
Operating expenses *		34,349			29,195
Selling, general and administrative *		5,028			5,270
Depreciation and amortization		11,183			9,905
Total costs and expenses		269,766			235,215
Other operating income		—			102
Operating income		13,270			7,563

Other income (expense):
Equity in earnings of unconsolidated entities		2,376			2,176
Interest expense		(8,402	)		(8,003	)
Other, net		60			60
Total other income (expense)		(5,966	)		(5,767	)

Net income before taxes		7,304			1,796
Income tax benefit (expense)		(223	)		(25	)
Net income	$	7,081		$	1,771

General partner’s interest in net income	$	1,224		$	863
Limited partners’ interest in net income	$	5,580		$	631

Net income per limited partner unit – basic and diluted	$	0.30		$	0.04

Weighted average limited partner units - basic		18,760,861			17,708,165
Weighted average limited partner units - diluted		18,761,611			17,709,027

See accompanying notes to consolidated and condensed financial statements.

*Related Party Transactions Included Above

Revenues:
Terminalling and storage	$	12,938	$	10,694
Marine transportation		6,565		6,060
Product Sales		5,399		307
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services		23,205		18,706
Sulfur services		4,152		3,317
Expenses:
Operating expenses		12,042		10,633
Selling, general and administrative		3,031		1,802

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)

	Partners’ Capital
	Common						Subordinated				General Partner			Accumulated Other Comprehensive Income
	Units			Amount			Units		Amount		Amount			(Loss)			Total
Balances – January 1, 2010		16,057,832		$	245,683			889,444	$	16,613	$	4,731		$	(2,076	)	$	264,951

Net income		—			908			—		—		863			—			1,771

Recognition of beneficial conversion feature		—			(277	)		—		277		—			—			—

Follow-on public offering		1,650,000			50,530			—		—		—			—			50,530

General partner contribution		—			—			—		—		1,089			—			1,089

Cash distributions		—			(12,043	)		—		—		(1,121	)		—			(13,164	)

Unit-based compensation		—			27			—		—		—			—			27

Adjustment in fair value of derivatives		—			—			—		—		—			2,512			2,512

Balances – March 31, 2010		17,707,832		$	284,828			889,444	$	16,890	$	5,562		$	436		$	307,716

Balances – January 1, 2011		17,707,832		$	250,785			889,444	$	17,721	$	4,881		$	1,419		$	274,806

Net income		—			5,857			—		—		1,224			—			7,081

Recognition of beneficial conversion feature		—			(277	)		—		277		—			—			—

Follow-on public offering		1,874,500			70,329			—		—		—			—			70,329

General partner contribution		—			—			—		—		1,505			—			1,505

Cash distributions		—			(13,458	)		—		—		(1,416	)		—			(14,874	)

Unit-based compensation		9,100			36			—		—		—			—			36

Purchase of treasury units		( 9,100	)		(347	)		—		—		—			—			(347	)

Adjustment in fair value of derivatives		—			—			—		—		—			(1,323	)		(1,323	)

Balances – March 31, 2011		19,582,332		$	312,925			889,444	$	17,998	$	6,194		$	96		$	337,213

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

	Three Months Ended March 31,
	2011			2010

Net income	$	7,081		$	1,771
Changes in fair values of commodity cash flow hedges		(908	)		499
Commodity cash flow hedging gains (losses) reclassified to earnings		(434	)		(117	)
Changes in fair value of interest rate cash flow hedges		—			(241	)
Interest rate cash flow hedging losses reclassified to earnings		19			2,371

Comprehensive income	$	5,758		$	4,283

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Three Months Ended March 31,
	2011			2010
Cash flows from operating activities:
Net income	$	7,081		$	1,771

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		11,183			9,905
Amortization of deferred debt issuance costs		1,140			1,467
Amortization of debt discount		88			6
Deferred taxes		(3	)		(147	)
Gain on sale of property, plant and equipment		—			(102	)
Equity in earnings of unconsolidated entities		(2,376	)		(2,176	)
Distributions from unconsolidated entities		—			—
Distributions in-kind from equity investments		3,948			3,741
Non-cash mark-to-market on derivatives		456			(3,142	)
Other		36			27
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		577			3,306
Product exchange receivables		3,845			3,871
Inventories		2,320			1,560
Due from affiliates		(2,792	)		(2,271	)
Other current assets		(461	)		(1,331	)
Trade and other accounts payable		(2,333	)		(525	)
Product exchange payables		(2,649	)		(2,526	)
Due to affiliates		4,314			(454	)
Income taxes payable		226			286
Other accrued liabilities		3,299			(1,898	)
Change in other non-current assets and liabilities		155			(20	)
Net cash provided by operating activities		28,054			11,348

Cash flows from investing activities:
Payments for property, plant and equipment		(14,874	)		(3,475	)
Acquisitions		(36,500	)		—
Payments for plant turnaround costs		(1,995	)		(1,043	)
Proceeds from sale of property, plant and equipment		—			625
Investment in unconsolidated entities		—			(20,110	)
Return of investments from unconsolidated entities		60			115
Distributions from (contributions to) unconsolidated entities for operations		(3,651	)		(568	)
Net cash used in investing activities		(56,960	)		(24,456	)

Cash flows from financing activities:
Payments of long-term debt		(101,500	)		(284,127	)
Payments of notes payable and capital lease obligations		(268	)		—
Proceeds from long-term debt		73,500			273,093
Net proceeds from follow on offering		70,329			50,530
Treasury units purchased		(347	)		—
General partner contribution		1,505			1,089
Payments of debt issuance costs		—			(6,969	)
Cash distributions paid		(14,874	)		(13,164	)
Net cash provided by financing activities		28,345			20,452

Net increase (decrease) in cash		(561	)		7,344

Cash at beginning of period		11,380			5,956

Cash at end of period	$	10,819		$	13,300

See accompanying notes to consolidated and condensed financial statements.

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(1)

General

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

The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and United States 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, 2010, filed with the Securities and Exchange Commission (the “SEC”) on March 2, 2011.

(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 accounting principles generally accepted in the United States. Actual results could differ from those estimates.

(b)

Unit Grants

In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for $347. These units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015.

The cost resulting from share-based payment transactions was $36 and $27 for the three months ended March 31, 2011 and 2010, respectively.

(c)

Incentive Distribution Rights

The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights (“IDRs”) in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the partnership agreement of the Partnership (the “Partnership Agreement”), and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement.

The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit.

For the three months ended March 31, 2011 and 2010 the general partner received $1,104 and $844, respectively, in incentive distributions.

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(d)

Net Income per Unit

The Partnership follows the provisions of ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. To the extent the Partnership Agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the Partnership Agreement. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement.

The provisions of ASC 260-10 did not impact the Partnership’s computation of earnings per limited partner unit as cash distributions exceeded earnings for the three months ended March 31, 2011 and 2010, respectively, and the IDRs do not share in losses under the Partnership Agreement. In the event the Partnership’s earnings exceed cash distributions, ASC 260-10 will have an impact on the computation of the Partnership’s earnings per limited partner unit. For the three months ended March 31, 2011 and 2010, the general partner’s interest in net income, including the IDRs, represents distributions declared after period-end on behalf of the general partner interest and IDRs less the allocated excess of distributions over earnings for the periods.

For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the beneficial conversion feature is added back to net income available to common limited partners, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method.

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

	Three Months Ended March 31,
	2011			2010
Net income	$	7,081		$	1,771
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs		1,105			844
Distributions payable on behalf of general partner interest		311			277
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest		(192	)		(258	)
Less beneficial conversion feature		277			277
Limited partners’ interest in net income	$	5,580		$	631

The weighted average units outstanding for basic net income per unit was 18,760,861 and 17,708,165 for the three months ended March 31, 2011 and 2010, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 750 and 862 for the three months ended March 31, 2011 and 2010, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(e)

Income Taxes

With respect to the Partnership’s taxable subsidiary, Woodlawn Pipeline Co., Inc. (“Woodlawn”), income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(2)	New Accounting Pronouncements

No new accounting pronouncements were issued or became effective in the first quarter of 2011 that impact the Partnership’s consolidated financial statements.

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(3)	Acquisitions

Terminalling Facilities

On January 31, 2011, the Partnership acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for $36,500. Martin Resource Management acquired these assets in its acquisition of L&L Holdings LLC (“L&L”) on January 31, 2011. Martin Resource Management has not completed the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the assets acquired by the Partnership. In the event the final fair value of the assets acquired by the Partnership differs from the amount paid by the Partnership, the difference will be accounted for as an adjustment to property, plant and equipment and partners’ capital. The acquired assets were recorded in property, plant and equipment. These assets are located across the Louisiana Gulf Coast. This acquisition was funded by borrowings under the Partnership’s revolving loan facility.

Harrison Gathering System

On January 15, 2010, the Partnership, through Prism Gas, as 50% owner and the operator of Waskom Gas Processing Company (“Waskom”), through Waskom’s wholly-owned subsidiary Waskom Midstream LLC, acquired from Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and equipment referred to as the Harrison Gathering System. The Partnership’s share of the acquisition cost was approximately $20,000 and was recorded as an investment in an unconsolidated entity.

(4)	Inventories

Components of inventories at March 31, 2011 and December 31, 2010, were as follows:

	March 31, 2011		December 31, 2010
Natural gas liquids	$	13,053	$	19,775
Sulfur		21,149		15,933
Sulfur Based Products		6,831		9,027
Lubricants		6,778		5,267
Other		2,485		2,614
	$	50,296	$	52,616

(5)	Investments in Unconsolidated Entities and Joint Ventures

Prism Gas owns an unconsolidated 50% interest in Waskom, the Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these assets are accounted for by the equity method.

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 and $149 for the three months ended March 31, 2011 and 2010, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated entities. The remaining unamortized excess investment relating to property and equipment was $8,755 and $8,903 at March 31, 2011 and December 31, 2010, respectively. The equity-method goodwill is not amortized; however, it is analyzed for impairment annually or when changes in circumstance indicate that a potential impairment exists. No impairment was recognized for the three months ended March 31, 2011 or 2010.

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

Activity related to these investment accounts for the three months ended March 31, 2011 and 2010 is as follows:

	Waskom			PIPE			Matagorda			Total

Investment in unconsolidated entities, December 31, 2010	$	93,768		$	1,311		$	3,138		$	98,217

Distributions in kind		(3,948	)		—			—			(3,948	)
Contributions to unconsolidated entities:
Cash contributions		—			—			—			—
Contributions to unconsolidated entities for operations		3,651			—			—			3,651
Return of investments		—			—			(60	)		(60	)
Equity in earnings:
Equity in earnings (losses) from operations		2,488			(15	)		51			2,524
Amortization of excess investment		(138	)		(3	)		(7	)		(148	)

Investment in unconsolidated entities, March 31, 2011	$	95,821		$	1,293		$	3,122		$	100,236

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	Waskom			PIPE			Matagorda			Total

Investment in unconsolidated entities, December 31, 2009	$	75,844		$	1,401		$	3,337		$	80,582

Distributions in kind		(3,741	)		—			—			(3,741	)
Contributions to unconsolidated entities:
Cash contributions (See Note 3)		20,110			—			—			20,110
Contributions to unconsolidated entities for operations		568			—			—			568
Return of investments		—			(30	)		(85	)		(115	)
Equity in earnings:
Equity in earnings (losses) from operations		2,296			(35	)		64			2,325
Amortization of excess investment		(138	)		(4	)		(7	)		(149	)

Investment in unconsolidated entities, March 31, 2010	$	94,939		$	1,332		$	3,309		$	99,580

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

	As of March 31				Three Months Ended March 31
	Total Assets		Partner’s Capital		Revenues		Net Income
2011
Waskom	$	125,890	$	111,889	$	31,506	$	4,976

	As of December 31
2010
Waskom	$	117,606	$	109,025	$	28,654	$	4,591

As of March 31, 2011 and December 31, 2010 the amount of the Partnership’s consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity-method investees is $42,825 and $40,509, respectively. There are no material restrictions to transfer funds in the form of dividends, loans or advances related to the equity-method investees.

As of March 31, 2011 and December 31, 2010, the Partnership’s interest in cash of the unconsolidated equity-method investees was $786 and $789, respectively.

(6)	Derivative Instruments and Hedging Activities

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

The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of its hedge contracts, including assessing the possibility of counterparty default. If the Partnership determines that a derivative is no longer expected to be highly effective, the Partnership discontinues hedge accounting prospectively and recognizes subsequent changes in the fair value of the hedge in earnings. As a result of its effectiveness assessment at March 31, 2011, the Partnership believes certain hedge contracts will continue to be effective in offsetting changes in cash flow or fair value attributable to the hedged risk.

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

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

In March 2008, the FASB amended the provisions of ASC Topic 820 related to fair value measurements and disclosures, which changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted this guidance on January 1, 2009.

(a)

Commodity Derivative Instruments

The Partnership is exposed to market risks associated with commodity prices and uses derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. The Partnership has entered into hedging transactions through 2012 to protect a portion of its commodity exposure. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership is focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

Due to the volatility in commodity markets, the Partnership is unable to predict the amount of ineffectiveness each period, including the loss of hedge accounting, which is determined on a derivative by derivative basis. This may result, and has resulted, in increased volatility in the Partnership’s financial results. Factors that have and may continue to lead to ineffectiveness and unrealized gains and losses on derivative contracts include: a substantial fluctuation in energy prices, the number of derivatives the Partnership holds and significant weather events that have affected energy production. The number of instances in which the Partnership has discontinued hedge accounting for specific hedges is primarily due to those reasons. However, even though these derivatives may not qualify for hedge accounting, the Partnership continues to hold the instruments as it believes they continue to afford the Partnership opportunities to manage commodity risk exposure.

As of March 31, 2011 and 2010, the Partnership has both derivative instruments qualifying for hedge accounting with fair value changes being recorded in AOCI as a component of partners’ capital and derivative instruments not designated as hedges being marked to market with all market value adjustments being recorded in earnings.

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2011 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of March 31, 2011, the remaining term of the contracts extend no later than December 2012, with no single contract longer than one year. For the three months ended March 31, 2011 and 2010, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in AOCI as a component of partners’ capital.

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Transaction Type	Total Volume Per Month	Pricing Terms	Remaining Terms of Contracts	Fair Value

Mark to Market Derivatives::

Crude Oil Swap	2,000 BBL	Fixed price of $91.20 settled against WTI NYMEX average monthly closings	April 2011 to December 2011		(292	)
Total commodity swaps not designated as hedging instruments				$	(292	)

Cash Flow Hedges:

Natural Gas Swap	10,000 Mmbtu	Fixed price of $6.1250 settled against IF_ANR_LA first of the month posting	April 2011 to December 2011		144

Natural Gas Swap	20,000 Mmbtu	Fixed price of $4.3225 settled against IF_ANR_LA first of the month posting	April 2011 to December 2011		(34	)

Natural Gasoline Swap	2,000 BBL	Fixed price of $87.10 settled against WTI NYMEX average monthly closings	April 2011 to December 2011		(365	)

Natural Gasoline Swap	1,000 BBL	Fixed price of $88.85 settled against WTI NYMEX average monthly closings	April 2011 to December 2011		(167	)

Natural Gasoline Swap	1,000 BBL	Fixed price of $2.383 settled against Mont Belvieu Non-TET OPIS Average	April 2011 to December 2011		( 4	)

Crude Oil Swap	1,000 BBL	Fixed price of $101.90 settled against WTI NYMEX average monthly closings	April 2011 to December 2011		(50	)

Natural Gas Swap	10,000 Mmbtu	Fixed price of $4.8700 settled against IF_ANR_LA first of the month posting	January 2012 to December 2012		(15	)

Natural Gas Swap	20,000 Mmbtu	Fixed price of $4.9600 settled against IF_ANR_LA first of the month posting	January 2012 to December 2012		(9	)

Natural Gasoline Swap	1,000 BBL	Fixed price of $90.20 settled against WTI NYMEX average monthly closings	January 2012 to December 2012		(190	)

Natural Gasoline Swap	1,000 BBL	Fixed price of $2.340 settled against Mont Belvieu Non-TET OPIS Average	January 2012 to December 2012		(19	)

Crude Oil Swap	2,000 BBL	Fixed price of $88.63 settled against WTI NYMEX average monthly closings	January 2012 to December 2012		(416	)

Total commodity swaps designated as hedging instruments				$	(1,125	)

Total net fair value of commodity derivatives				$	(1,417	)

Based on estimated volumes, as of March 31, 2011, the Partnership had hedged approximately 46% and 35% of its commodity risk by volume for 2011 and 2012, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.

The Partnership’s credit exposure related to commodity cash flow hedges is represented by the positive fair value of contracts to the Partnership at March 31, 2011. These outstanding contracts expose the Partnership to credit loss in the event of nonperformance by the counterparties to the agreements. The Partnership has incurred no losses associated with counterparty nonperformance on derivative contracts.

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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; establishes a maximum credit limit threshold pursuant to its hedging policy; and monitors the appropriateness of these limits on an ongoing basis. The Partnership has agreements with five counterparties containing collateral provisions. Based on those current agreements, cash deposits are required to be posted whenever the net fair value of derivatives associated with the individual counterparty exceed a specific threshold. If this threshold is exceeded, cash is posted by the Partnership if the value of derivatives is a liability to the Partnership. As of March 31, 2011, the Partnership has no cash collateral deposits posted with counterparties.

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

(b)

Impact of Commodity Cash Flow Hedges

Crude Oil. For the three months ended March 31, 2011 and 2010, net gains and losses on swap hedge contracts decreased crude revenue by $60 and $3, respectively. As of March 31, 2011, an unrealized derivative fair value gain of $96, related to current and terminated cash flow hedges of crude oil price risk, was recorded in AOCI. Fair value gains of $512 and fair value losses of $416 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at March 31, 2011, adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

Natural Gas. For the three months ended March 31, 2011 and 2010, net gains and losses on swap hedge contracts increased gas revenue by $75 and $65, respectively. As of March 31, 2011, an unrealized derivative fair value gain of $74 related to cash flow hedges of natural gas was recorded in AOCI. Fair value gains of $98 and fair value losses of $24 are expected to be reclassified into earnings in 2011 and 2012, 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.

Natural Gas Liquids. For the three months ended March 31, 2011 and 2010, net gains and losses on swap hedge contracts increased liquids revenue by $162 and decreased liquids revenue by $37, respectively. As of March 31, 2011, an unrealized derivative fair value loss of $74 related to current and terminated cash flow hedges of NGLs price risk was recorded in AOCI. Fair value gains of $134 and fair value losses of $208 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at March 31, 2011, adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

For information regarding fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note.

(c)

Impact of Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt and term loan credit facilities. 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 AOCI until such time as the hedged item is recognized in earnings.

The Partnership has entered into interest rate swap agreements with an aggregate notional amount of $100,000 to hedge its exposure to changes in the fair value of Senior Notes as described in Note 10. The Partnership believes the interest rate hedge contracts will be effective in offsetting changes in fair value attributable to the hedged risk; however, the contracts were not designated as fair value hedges and therefore, are not receiving hedge accounting but being marked to market through earnings.

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Under the following swap agreements, the Partnership pays a floating rate of interest and receives a fixed rate based on a three-month U.S. Dollar LIBOR rate to match the fixed rate of the Senior Notes:

Date of Hedge	Notional Amount	Paying Floating Rate	Receiving Fixed Rate	Maturity Date
September 2010	$40,000	3 Month LIBOR	2.3150%	April 2018
September 2010	$60,000	3 Month LIBOR	2.3150%	April 2018

In March 2010, in connection with a pay down of the Partnership’s revolving credit facility, the Partnership terminated all of its existing cash flow hedge agreements with an aggregate notional amount of $140,000, which it had entered to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. Termination fees of $3,850 were paid on early extinguishment of all interest rate swap agreements in March 2010. The amounts remaining in AOCI were reclassified into interest expense over the original term of the terminated interest rate derivatives.

The Partnership recognized increases in interest expense of $633 and $2,561 for the three months ended March 31, 2011 and 2010, 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 swaps and hedges.

For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” below.

(d)

Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items

The following table summarizes the fair values and classification of the Partnership’s derivative instruments in its Consolidated Balance Sheet:

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities

		Fair Values					Fair Values
	Balance Sheet Location	March 31, 2011		December 31, 2010		Balance Sheet Location	March 31, 2011		December 31, 2010
Derivatives designated as hedging instruments	Current:					Current:
Interest rate contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	—
Commodity contracts	Fair value of derivatives		144		201	Fair value of derivatives		802		230
			144		201			802		230
	Non-current:					Non-current:
Interest rate contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		—
Commodity contracts	Fair value of derivatives		—		—	Fair value of derivatives		468		171
			—		—			468		171

Total derivatives designated as hedging instruments		$	144	$	201		$	1,270	$	401


Derivatives not designated as hedging instruments	Current:					Current:
Interest rate contracts	Fair value of derivatives	$	1,994	$	1,941	Fair value of derivatives	$	—	$	—
Commodity contracts	Fair value of derivatives		—		-	Fair value of derivatives		291		51
			1,994		1,941			291		51
	Non-current:					Non-current:
Interest rate contracts	Fair value of derivatives		—		—	Fair value of derivatives		4,596		3,930
Commodity contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		—
			—		—			—		3,930
Total derivatives not designated as hedging instruments		$	1 ,994	$	1,941		$	4,887	$	3,981

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	Effect of Derivative Instruments on the Consolidated Statement of Operations For the Three Months Ended March 31, 2011 and 2010

	Effective Portion													Ineffective Portion and Amount Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives						Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income						Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives

	2011			2010				2011			2010				2011		2010

Derivatives designated as hedging instruments
Interest rate contracts	$	—		$	(241	)	Interest Expense	$	(19	)	$	(2,371	)	Interest Expense	$	—	$	—
Commodity contracts		(908	)		499		Natural Gas Revenues		434			113		Natural Gas Revenues		—		4

Total derivatives designated as hedging instruments	$	(908	)	$	(258	)		$	415		$	(2,258	)		$	—	$	4

	Location of Gain or (Loss) Recognized in Income on	Amount of Gain or (Loss) Recognized in Income on Derivatives
	Derivatives
		2011			2010
Derivatives not designated as hedging instruments
Interest rate contracts	Interest Expense	$	(614	)	$	(190	)
Commodity contracts	Natural Gas Services Revenues		(257	)		(93	)
Total derivatives not designated as hedging instruments		$	(871	)	$	(283	)

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Amounts expected to be reclassified into earnings for the subsequent 12-month period are losses of $0 for interest rate cash flow hedges and of $578 for commodity cash flow hedges.

(7)	Fair Value Measurements

The Partnership provides disclosures pursuant to certain provisions of ASC 820, which provides a framework for measuring fair value and expanded disclosures about fair value measurements. ASC 820 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. ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value into one of the following categories:

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

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

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

The Partnership’s derivative instruments, which consist of commodity and interest rate swaps, are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets, which is considered Level 2. Refer to Note 6 for further information on the Partnership’s derivative instruments and hedging activities.

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at March 31, 2011:

	Fair Value Measurements at Reporting Date Using
				Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	March 31, 2011			(Level 1)		(Level 2)			(Level 3)
Assets

Interest rate derivatives	$	1,994		$	—	$	1,994		$	—
Natural gas derivatives		144			—		144			—

Total assets	$	2,138		$	—	$	2,138		$	—
Liabilities
Interest rate derivatives	$	(4,596	)	$	—	$	(4,596	)	$	—
Natural gas derivatives		(58	)		—		(58	)		—
Crude oil derivatives		(758	)		—		(758	)		—
Natural gas liquids derivatives		(745	)		—		(745	)		—

Total liabilities	$	(6,157	)	$	—	$	(6,157	)	$	—

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The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at December 31, 2010:

	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	December 31, 2010		(Level 1)		(Level 2)		(Level 3)
Assets
Interest rate derivatives	$	1,941	$	—	$	1,941	$	—
Natural gas derivatives		201		—		201		—
Total assets	$	2,142	$	—	$	2,142	$	—
Liabilities
Interest rate derivatives	$	3,930	$	—	$	3,930	$	—
Natural gas derivatives		28		—		28		—
Crude oil derivatives		177		—		177		—
Natural gas liquids derivatives		247		—		247		—

Total liabilities	$	4,382	$	—	$	4,382	$	—

ASC 825-10-65, related to disclosures about fair value of financial instruments, requires that the Partnership disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for the Partnership’s financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable and due from/to affiliates — the carrying amounts approximate fair value because of the short maturity of these instruments.

Long-term debt including current installments — the carrying amount of the revolving and term loan facilities approximates fair value due to the debt having a variable interest rate.

The estimated fair value of the Senior Notes was approximately $217,932 and $216,366 based on market prices of similar debt at March 31, 2011 and December 31, 2010, respectively.

(8)	Related Party Transactions

As of March 31, 2011, Martin Resource Management owns 5,703,823 of the Partnership’s common units and 889,444 subordinated units collectively representing approximately 32.2% of the Partnership’s outstanding limited partnership units. The Partnership’s general partner is a wholly-owned subsidiary of Martin Resource Management. The Partnership’s general partner owns a 2.0% general partner interest in the Partnership and the Partnership’s incentive distribution rights. The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of March 31, 2011, of approximately 32.2% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

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The following is a description of the Partnership’s material related party transactions:

Omnibus Agreement

Omnibus Agreement. The Partnership and its general partner are parties to an omnibus agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks. The omnibus agreement was amended on November 24, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls our general partner, not to engage in the business of:

providing terminalling, refining, processing, distribution and midstream logistical services for hydrocarbon products and by-products;

providing marine and other transportation of hydrocarbon products and by-products; and

manufacturing and marketing fertilizers and related sulfur-based products.

This restriction does not apply to:

the ownership and/or operation on our behalf of any asset or group of assets owned by us or our affiliates;

any business operated by Martin Resource Management, including the following:

providing land transportation of various liquids;

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 NGL storage facility in Arcadia, Louisiana;

building and marketing sulfur processing equipment; and

developing an underground natural gas storage facility in Arcadia, Louisiana.

any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000;

any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 million or more if the Partnership has been offered the opportunity to purchase the business for fair market value, and the Partnership declines to do so with the concurrence of the conflicts committee; and

any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5,000 or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business.

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Services. Under the omnibus agreement, Martin Resource Management provides us with corporate staff, support services, and administrative services necessary to operate our business. The omnibus agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses. Under the omnibus agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

Effective October 1, 2010, through September 30, 2011, the Conflicts Committee of the board of directors of our general partner (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $4,168. We reimbursed Martin Resource Management for $1,042 and $916 of indirect expenses for the three months ended March 31, 2011 and 2010, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

These indirect expenses are intended to cover 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 the Partnership shares with Martin Resource Management retained businesses. The provisions of the omnibus agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control our general partner.

Related Party Transactions. The omnibus agreement prohibits us from entering into any material agreement with Martin Resource Management without the prior approval of the conflicts committee of our general partner’s board of directors. For purposes of the omnibus agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read “— Services” above.

License Provisions. Under the omnibus agreement, Martin Resource Management has granted us a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates.

Amendment and Termination. The omnibus agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the conflicts committee of our general partner if such amendment would adversely affect the unitholders. The omnibus agreement was amended on November 24, 2009, to permit us to provide refining services to Martin Resource Management. Such amendment was approved by the conflicts committee of our general partner. The omnibus agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on our behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.

Motor Carrier Agreement

Motor Carrier Agreement. The Partnership is a party to a motor carrier agreement effective January 1, 2006, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. This agreement replaced a prior agreement effective November 1, 2002, between us and Martin Transport, Inc. for land transportation services. Under the agreement, Martin Transport Inc. agreed to ship our NGL shipments as well as other liquid products.

Term and Pricing. This agreement was amended in November 2006, January 2007, April 2007 and January 2008 to add additional point-to-point rates and to modify certain fuel and insurance surcharges being charged to the Partnership. The agreement has an initial term that expired in December 2007 but 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 Partnership has the right to terminate this agreement at anytime by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustment to which are mutually agreed or in accordance with a price index. 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.

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Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. This agreement replaced a prior agreement effective November 1, 2002 between the Partnership and Martin Resource Management covering marine transportation services which expired November 2005. Effective each January 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 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.

Cross Marine Charter Agreements. Cross entered into four marine charter agreements with the Partnership effective March 1, 2007. These agreements have an initial term of five years and continue indefinitely thereafter subject to cancellation after the initial term by either party upon a 30 day written notice of cancellation. The charter hire payable under these agreements will be adjusted annually to reflect the percentage change in the Consumer Price Index.

Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate over the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil. Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement. The Partnership is a party to an agreement under which the Partnership provides terminal services to Martin Resource Management. This agreement was amended and restated as of October 27, 2004, and was set to expire in December 2006, but automatically renewed and will continue to automatically renew on a month-to-month basis until either party terminates the agreement by giving 60 days written notice. The per gallon throughput fee we charge under this agreement may be adjusted annually based on a price index.

Miscellaneous Terminal Services Agreements. The Partnership is currently party to several terminal services agreements and from time to time the Partnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.

Other Agreements

Cross Tolling Agreement. We are party to an agreement under which we process crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The Tolling Agreement has a 12 year term which expires November 24, 2021. Under this Tolling Agreement, Martin Resource Management agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a fixed price per barrel. Any additional barrels are refined at a modified price per barrel. In addition, Martin Resource Management agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. The Partnership is party to an agreement under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, and which is not consumed by the Partnership’s internal operations. This agreement, which was amended and restated in August 2008, will remain in place until the Partnership terminates it by providing 180 days’ written notice. Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

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Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.

The tables below summarize the related party transactions that are included in the related financial statement captions on the face of the Partnership’s Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the consolidated financial statement and do not reflect a statement of profits and losses for related party transactions.

The impact of related party revenues from sales of products and services is reflected in the consolidated financial statement as follows:

	Three Months Ended March 31,
Revenues:	2011		2010
Terminalling and storage	$	12,938	$	10,694
Marine transportation		6,565		6,060
Product sales:
Natural gas services		2,203		61
Sulfur services		3,186		186
Terminalling and storage		10		60
		5,399		307
	$	24,902	$	17,061

The impact of related party cost of products sold is reflected in the consolidated financial statement as follows:

Costs and expenses:
Cost of products sold:
Natural gas services	$	23,205	$	18,706
Sulfur services		4,152		3,317
Terminalling and storage		56		877
	$	27,413	$	22,900

The impact of related party operating expenses is reflected in the consolidated financial statement as follows:

Operating expenses
Terminalling and storage	$	4,202	$	3,041
Natural gas services		608		332
Sulfur services		1,244		1,016
Marine Transportation		5,988		6,244
	$	12,042	$	10,633

The impact of related party selling, general and administrative expenses is reflected in the consolidated financial statement as follows:

Selling, general and administrative:
Terminalling and storage	$	15	$	—
Natural gas services		1,332		269
Sulfur services		642		617
Indirect overhead allocation, net of reimbursement		1,042		916
	$	3,031	$	1,802

Table of Contents

(9)	Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, sulfur services and marine transportation. 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, 2010, filed with the SEC on March 2, 2011. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (loss) after eliminations			Capital Expenditures
Three months ended March 31, 2011
Terminalling and storage	$	37,646	$	(978	)	$	36,668	$	4,782	$	2,927		$	4,204
Natural gas services		167,211		—			167,211		1,514		3,531			515
Sulfur services		59,758		—			59,758		1,622		9,911			7,247
Marine transportation		21,439		(2,040	)		19,399		3,265		(1,281	)		2,908
Indirect selling, general and administrative		—