Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

2012.9.30 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________________________________

FORM 10-Q



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

For the quarterly period ended September 30, 2012



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

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



Yes o		No x

The number of the registrant’s Common Units outstanding at November 5, 2012, was 23,116,776.



		Page

PART I – FINANCIAL INFORMATION		2

Item 1. Financial Statements		2
	Consolidated and Condensed Balance Sheets as of September 30, 2012 (unaudited) and December 31, 2011 (audited)	2
	Consolidated and Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011 (unaudited)	3
	Consolidated and Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011 (unaudited)	6
	Consolidated and Condensed Statements of Capital for the Nine Months Ended September 30, 2012 and 2011 (unaudited)	7
	Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011 (unaudited)	8
	Notes to Consolidated and Condensed Financial Statements	9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		55

Item 3. Quantitative and Qualitative Disclosures about Market Risk		56

Item 4. Controls and Procedures		57

PART II. OTHER INFORMATION		58

Item 1. Legal Proceedings		58

Item 1A. Risk Factors		58

Item 5. Other Information		58

Item 6. Exhibits		60

SIGNATURE
CERTIFICATIONS

Table of Contents

PART I – FINANCIAL INFORMATION



Item 1.	Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)



	September 30, 2012			December 31, 2011
	(Unaudited)			(Audited)
Assets
Cash	$	27		$	266
Accounts and other receivables, less allowance for doubtful accounts of $3,264 and $3,021, respectively	121,020			126,461
Product exchange receivables	5,455			17,646
Inventories	116,260			77,677
Due from affiliates	21,139			5,968
Fair value of derivatives	—			622
Other current assets	1,511			1,978
Assets held for sale	—			212,787
Total current assets	265,412			443,405

Property, plant and equipment, at cost	695,662			632,728
Accumulated depreciation	(243,780		)	(215,272		)
Property, plant and equipment, net	451,882			417,456

Goodwill	8,337			8,337
Investment in unconsolidated entities	80,799			62,948
Debt issuance costs, net	10,924			13,330
Other assets, net	6,442			3,633
	$	823,796		$	949,109

Liabilities and Partners’ Capital
Current installments of long-term debt and capital lease obligations	$	217		$	1,261
Trade and other accounts payable	104,779			125,970
Product exchange payables	27,908			37,313
Due to affiliates	4,669			18,485
Income taxes payable	7,174			893
Fair value of derivatives	—			362
Other accrued liabilities	11,764			11,022
Liabilities held for sale	—			501
Total current liabilities	156,511			195,807

Long-term debt and capital leases, less current maturities	255,966			458,941
Deferred income taxes	—			7,657
Other long-term obligations	1,069			1,088
Total liabilities	413,546			663,493

Partners’ capital	410,250			284,990
Accumulated other comprehensive income	—			626
Total partners’ capital	410,250			285,616
Commitments and contingencies
	$	823,796		$	949,109

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenues:
Terminalling and storage *	$	23,875		$	19,381		$	65,107		$	56,831
Marine transportation *	22,102			20,773			63,678			57,548
Sulfur services	2,926			2,850			8,777			8,550
Product sales: *
Natural gas services	190,738			159,748			527,666			423,953
Sulfur services	57,670			67,319			193,464			198,310
Terminalling and storage	20,601			17,525			61,482			55,441
	269,009			244,592			782,612			677,704
Total revenues	317,912			287,596			920,174			800,633

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	185,686			156,236			515,928			414,162
Sulfur services *	47,272			59,808			149,582			164,142
Terminalling and storage	18,767			15,676			56,154			49,631
	251,725			231,720			721,664			627,935
Expenses:
Operating expenses *	36,655			34,354			108,109			100,676
Selling, general and administrative *	4,680			5,538			13,687			13,015
Depreciation and amortization	9,966			10,025			29,457			29,523
Total costs and expenses	303,026			281,637			872,917			771,149

Other operating income (loss)	(5		)	1,720			368			1,818
Operating income	14,881			7,679			47,625			31,302

Other income (expense):
Equity in earnings (loss) of unconsolidated entities	(169		)	(54		)	(532		)	100
Interest expense	(6,263		)	(4,297		)	(21,735		)	(17,102		)
Debt prepayment premium	—			—			(2,470		)	—
Other, net	587			24			732			125
Total other expense	(5,845		)	(4,327		)	(24,005		)	(16,877		)

Income from continuing operations before taxes	9,036			3,352			23,620			14,425
Income tax expense	(238		)	(218		)	(810		)	(662		)
Income from continuing operations	8,798			3,134			22,810			13,763
Income from discontinued operations, net of income taxes	63,603			2,265			67,312			7,728
Net income	$	72,401		$	5,399		$	90,122		$	21,491

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

*Related Party Transactions Included Above



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Revenues:
Terminalling and storage	$	18,531	$	14,210	$	48,611	$	40,045
Marine transportation	3,979		6,352		13,282		19,223
Product Sales	1,636		1,628		5,783		7,197
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	6,761		9,257		18,783		13,679
Sulfur services	4,111		4,762		12,512		13,407
Expenses:
Operating expenses	14,100		16,905		42,308		42,170
Selling, general and administrative	2,764		2,373		8,258		6,344

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012		2011
Allocation of net income attributable to:
Limited partner interest:
Continuing operations	$	10,128		$	2,157	$	21,645	$	10,674
Discontinued operations	60,825			1,617		63,874		5,994
	70,953			3,774		85,519		16,668
General partner interest:
Continuing operations	(1,330		)	811		1,165		2,557
Discontinued operations	2,778			537		3,438		1,435
	1,448			1,348		4,603		3,992
Net income attributable to:
Continuing operations	8,798			3,134		22,810		13,763
Discontinued operations	63,603			2,265		67,312		7,728
	$	72,401		$	5,399	$	90,122	$	21,491
Net income attributable to limited partners:
Basic:
Continuing operations	$	0.44		$	0.11	$	0.94	$	0.56
Discontinued operations	2.63			0.09		2.79		0.31
	$	3.07		$	0.20	$	3.73	$	0.87
Weighted average limited partner units - basic	23,101			19,158		22,929		19,161
Diluted:
Continuing operations	$	0.44		$	0.11	$	0.94	$	0.56
Discontinued operations	2.63			0.09		2.79		0.31
	$	3.07		$	0.20	$	3.73	$	0.87
Weighted average limited partner units - diluted	23,105			19,163		22,932		19,163

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net income	$	72,401		$	5,399		$	90,122		$	21,491
Other comprehensive income adjustments:
Changes in fair values of commodity cash flow hedges	—			1,295			126			1,231
Commodity cash flow hedging gains (losses) reclassified to earnings	(63		)	(538		)	(752		)	(1,291		)
Interest rate cash flow hedging gains reclassified to earnings	—			—			—			18
Other comprehensive income	(63		)	757			(626		)	(42		)
Comprehensive income	$	72,338		$	6,156		$	89,496		$	21,449

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)



	Partners’ Capital
	Common Limited					Subordinated Limited			General Partner			Accumulated Other Comprehensive Income
	Units		Amount			Units	Amount		Amount			(Loss)			Total
Balances - January 1, 2011	17,707,832		$	250,785		889,444	$	17,721	$	4,881		$	1,419		$	274,806

Net income	—		17,499			—	—		3,992			—			21,491

Recognition of beneficial conversion feature	—		(831		)	—	831		—			—			—

Follow-on public offering	1,874,500		70,330			—	—		—			—			70,330

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

Cash distributions	—		(43,321		)	—	—		(4,635		)	—			(47,956		)

Excess purchase price over carrying value of acquired assets	—		(19,685		)	—	—		—			—			(19,685		)

Unit-based compensation	15,530		131			—	—		—			—			131

Purchase of treasury units	(14,850	)	(582		)	—	—		—			—			(582		)

Unit-based compensation grant forfeitures	(500	)	—			—	—		—			—			—

Adjustment in fair value of derivatives	—		—			—	—		—			(42		)	(42		)

Balances - September 30, 2011	19,582,512		$	274,326		889,444	$	18,552	$	5,743		$	1,377		$	299,998

Balances - January 1, 2012	20,471,776		$	279,562		—	$	—	$	5,428		$	626		$	285,616

Net income	—		85,519			—	—		4,603			—			90,122

Follow-on public offering	2,645,000		91,361			—	—		—			—			91,361

General partner contribution	—		—			—	—		1,951			—			1,951

Cash distributions	—		(52,880		)	—	—		(5,452		)	—			(58,332		)

Unit-based compensation	6,250		379			—	—		—			—			379

Purchase of treasury units	(6,250	)	(221		)	—	—		—			—			(221		)

Adjustment in fair value of derivatives	—		—			—	—		—			(626		)	(626		)

Balances - September 30, 2012	23,116,776		$	403,720		—	$	—	$	6,530		$	—		$	410,250

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)



	Nine Months Ended
	September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	90,122		$	21,491
Less: Income from discontinued operations	(67,312		)	(7,728		)
Net income from continuing operations	22,810			13,763
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	29,457			29,523
Amortization of deferred debt issuance costs	2,611			3,071
Amortization of debt discount	504			262
Loss on sale of property, plant and equipment	7			405
Gain on sale of equity method investment	(486		)	—
Equity in earnings (loss) of unconsolidated entities	532			(100		)
Other	379			131
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(6,328		)	(4,788		)
Product exchange receivables	12,190			(16,552		)
Inventories	(38,583		)	(28,057		)
Due from affiliates	(27,795		)	221
Other current assets	431			1,874
Trade and other accounts payable	(8,533		)	11,733
Product exchange payables	(9,405		)	27,350
Due to affiliates	4,469			3,430
Income taxes payable	(96		)	(799		)
Other accrued liabilities	840			4,218
Change in other non-current assets and liabilities	(1,126		)	(123		)
Net cash provided by (used in) continuing operating activities	(18,122		)	45,562
Net cash provided by discontinued operating activities	120			12,272
Net cash provided by (used in) operating activities	(18,002		)	57,834
Cash flows from investing activities:
Payments for property, plant and equipment	(63,009		)	(48,769		)
Acquisitions	—			(16,815		)
Payments for plant turnaround costs	(2,578		)	(2,103		)
Proceeds from sale of property, plant and equipment	33			530
Proceeds from sale of equity method investment	531			—
Investment in unconsolidated subsidiaries	(775		)	(59,319		)
Return of investments from unconsolidated entities	5,133			383
Distributions from (contributions to) unconsolidated entities for operations	(22,786		)	(929		)
Net cash used in continuing investing activities	(83,451		)	(127,022		)
Net cash provided by (used in) discontinued investing activities	271,181			(8,253		)
Net cash provided by (used in) investing activities	187,730			(135,275		)
Cash flows from financing activities:
Payments of long-term debt	(547,000		)	(389,000		)
Payments of notes payable and capital lease obligations	(6,522		)	(831		)
Proceeds from long-term debt	349,000			456,000
Net proceeds from follow on offering	91,361			70,330
General partner contribution	1,951			1,505
Treasury units purchased	(221		)	(582		)
Payment of debt issuance costs	(204		)	(3,424		)
Excess purchase price over carrying value of acquired assets	—			(19,685		)
Cash distributions paid	(58,332		)	(47,956		)
Net cash provided by (used in) financing activities	(169,967		)	66,357
Net decrease in cash	(239		)	(11,084		)
Cash at beginning of period	266			11,380
Cash at end of period	$	27		$	296

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(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 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, 2011, filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2012. On August 21, 2012, Part II, Items 6, 7, and 8 of the Partnership's Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012, was updated on Form 8-K to reflect the operations related to the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets as discontinued operations

As discussed in Note 4, on July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets. These assets, along with additional gathering and processing assets discussed in Note 4 are collectively referred to as the "Prism Assets". The Partnership classified the Prism Assets, including related liabilities as held for sale at December 31, 2011, and has presented the results of operations and cash flows as discontinued operations for the periods ended September 30, 2012 and 2011, respectively. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the net assets and operations and cash flows of the Prism Assets as assets held for sale and discontinued operations, respectively.


(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 May 2012, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 6,250 treasury units purchased by the Partnership in the open market for $221. These units vest in 25% increments beginning in January 2013 and will be fully vested in January 2016.

In May 2011, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 5,750 treasury units purchased by the Partnership in the open market for $235 and 500 treasury units from forfeitures. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.

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. On July 31, 2012, 6,850 of these units were fully vested to certain employees in connection with the sale of the Prism Assets. The remaining 2,250 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 $261 and $36 for the three months ended September 30, 2012 and 2011, respectively, and $379 and $131 for the nine months ended September 30, 2012 and 2011, respectively.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)


(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. As discussed further in Note 16, on October 2, 2012, the Partnership Agreement was amended to provide that the General Partner shall not receive the next $18,000 in incentive distributions that it would otherwise be entitled to receive. Therefore, no incentive distributions were allocated to the general partner for the three months ended September 30, 2012, which would have been payable to the general partner on November 14, 2012.

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 September 30, 2012 and 2011, the general partner received $0 and $1,265, respectively, in incentive distributions. For the nine months ended September 30, 2012 and 2011, the general partner received $2,857 and $3,635, respectively, in incentive distributions.


(d)	Net Income per Unit

The Partnership follows the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the IDR would be contractually entitled to receive if all earnings for the period were distributed. 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.

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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	8,798		$	3,134		$	22,810	$	13,763
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	(1,536		)	763			723		2,328
Distributions payable on behalf of general partner interest	(320		)	207			295		640
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	526			(159		)	147		(411		)
Less beneficial conversion feature	—			166			—		532
Limited partners’ interest in net income	$	10,128		$	2,157		$	21,645	$	10,674



	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	63,603	$	2,265		$	67,312	$	7,728
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	1,536		502			2,134		1,307
Distributions payable on behalf of general partner interest	709		138			872		360
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	533		(103		)	432		(232		)
Less beneficial conversion feature	—		111			—		299
Limited partners’ interest in net income	$	60,825	$	1,617		$	63,874	$	5,994

The Partnership allocates the General Partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income. The allocation is done at each period end on an annual basis, resulting in each quarter representing the difference between year to date of the current quarter and year to date as of the previous quarter.

The weighted average units outstanding for basic net income per unit were 23,101,233 and 22,929,172 for the three and nine months ended September 30, 2012, respectively, and 19,158,334 and 19,161,403 for the three and nine months ended September 30, 2011, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 3,596 and 3,164 for the three and nine months ended September 30, 2012, respectively, and 4,794 and 1,663 for the three and nine months ended September 30, 2011, 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

In September 2011, the FASB amended the provisions of ASC 350 related to testing goodwill for impairment. This update simplifies the goodwill impairment assessment by allowing a company to first review qualitative factors to determine the likelihood of whether the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, the company would not be required to perform the two-step goodwill impairment test for that reporting unit. This update is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. This amended guidance was adopted by the Partnership effective January 1, 2012.

In June 2011, the FASB amended the provisions of ASC 220 related to other comprehensive income. This newly issued guidance: (1) eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity; (2) requires the consecutive presentation of the statement of net income and other comprehensive income; and (3) requires an entity to present reclassification adjustments on the face of the financial statements from other comprehensive income to net income. The amendments in this guidance do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income nor do the amendments affect how earnings per share is calculated or presented. This guidance is required to be applied retrospectively and is effective for fiscal years and interim periods within those years beginning after December 15, 2011. This amended guidance was adopted by the Partnership effective January 1, 2012. As this new guidance only requires enhanced disclosure, adoption did not impact the Partnership’s financial position or results of operations.


(3)	Acquisitions

Redbird Gas Storage

On May 31, 2011, the Partnership acquired all of the Class B equity interests in Redbird Gas Storage LLC (“Redbird”) for approximately $59,319. This amount was recorded as an investment in an unconsolidated entity. Redbird, a subsidiary of Martin Resource Management, is a natural gas storage joint venture formed to invest in Cardinal Gas Storage Partners, LLC (“Cardinal”). Cardinal is a joint venture between Redbird and Energy Capital Partners that is focused on the development, construction, operation and management of natural gas storage facilities across North America. Redbird owns an unconsolidated 40.95% interest in Cardinal. Concurrent with the closing of this transaction, Cardinal acquired all of the outstanding equity interests in Monroe Gas Storage Company, LLC (“Monroe”) as well as an option on development rights to an adjacent depleted reservoir facility. This acquisition was funded by borrowings under the Partnership’s revolving credit facility. In addition to owning all of the Class B equity interests of Redbird, the Partnership also owns 10.74% of the Class A equity interests of Redbird at September 30, 2012.

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. These assets are located across the Louisiana Gulf Coast. This acquisition was funded by borrowings under the Partnership’s revolving credit facility.

These terminalling assets were acquired by Martin Resource Management in its acquisition of L&L Holdings LLC (“L&L”) on January 31, 2011. During the second quarter of 2011, Martin Resource Management finalized the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the terminalling assets acquired by the Partnership. The Partnership recorded an adjustment in the amount of $19,685 to reduce property, plant and equipment and partners’ capital for the difference between the purchase price and the fair value of the terminalling assets acquired based on Martin Resource Management’s final purchase price allocation.


(4)	Discontinued operations and divestitures

On July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas Systems I, L.P. (“Prism Gas”), a wholly-owned subsidiary of the Partnership, and other natural gas gathering and processing assets also owned by the Partnership to a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”). The Partnership received net cash proceeds from the sale of $273,269. The asset sale includes

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

the Partnership’s 50% operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint owned the other 50% percent interest.

Additionally, on September 18, 2012, the Partnership completed the sale of its interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) to a private investor group for $1,530.

The assets described above collectively are referred to herein as the Prism Assets.

The Partnership classified the results of operations of the Prism Assets which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the consolidated and condensed statements of operations for all periods presented. The assets and liabilities to be sold met the accounting criteria to be classified as held for sale and were aggregated and reported on separate lines in the consolidated and condensed balance sheet at December 31, 2011.

The assets and liabilities classified held for sale as of December 31, 2011 were as follows:



	December 31, 2011
Assets
Inventories	$	486
Property, plant and equipment	78,324
Accumulated depreciation	(18,438		)
Goodwill	28,931
Investment in unconsolidated entities	107,549
Other assets, net	15,935
Assets held for sale	$	212,787

Liabilities
Other long-term obligations	501
Liabilities held for sale	$	501

The Prism Assets’ operating results, which are included within income from discontinued operations, were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Total revenues from third parties¹	$	9,269		$	28,714		$	66,842		$	90,917
Total costs and expenses, excluding depreciation and amortization	(9,296		)	(26,892		)	(64,556		)	(85,888		)
Depreciation and amortization	—			(1,375		)	(2,320		)	(4,128		)
Other operating income²	62,251			—			61,421			3
Equity in earnings of Waskom, Matagorda, and PIPE	377			1,839			4,611			6,854
Income from discontinued operations before income taxes	62,601			2,286			65,998			7,758
Income tax expense (benefit)	(1,002		)	21			(1,314		)	30
Income from discontinued operations, net of income taxes	$	63,603		$	2,265		$	67,312		$	7,728

¹ Total revenues from third parties excludes intercompany revenues of $3,285, $17,741, $26,431, and $49,444 for the three months ended September 30, 2012 and 2011, and nine months ended September 30, 2012 and 2011, respectively.

² The Partnership recognized a gain on the sale of its Prism Gas Business of $62,251 and $61,411 in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011, respectively.


(5)	Inventories

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

Components of inventories at September 30, 2012 and December 31, 2011 were as follows:



	September 30, 2012		December 31, 2011
Natural gas liquids	$	64,783	$	25,178
Sulfur	26,460		24,335
Sulfur based products	14,115		14,857
Lubricants	8,471		11,012
Other	2,431		2,295
	$	116,260	$	77,677


(6)	Investments in Unconsolidated Entities and Joint Ventures

As discussed in detail in Note 4, the Partnership sold its 50% interests in Waskom, Matagorda, and PIPE. The equity in earnings associated with these investments during the periods owned is recorded in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011.

The Partnership and Martin Resource Management formed Redbird, a natural gas storage joint venture formed to invest in Cardinal. The Partnership owns 10.74% of the Class A equity interests and all the Class B equity interests in Redbird. Redbird owns an unconsolidated 40.95% interest in Cardinal. Redbird utilized the investments by the Partnership to invest in Cardinal to fund projects for natural gas storage facilities.

During the second quarter of 2012, the Partnership acquired an unconsolidated 50% interest in Caliber Gathering System, LLC (“Caliber”) and Pecos Valley Producer Services LLC (“Pecos Valley”). The Partnership sold its interest in Pecos Valley during the third quarter of 2012 for $531, resulting in a gain of $486 recorded in Other, Net in the Partnership's consolidated and condensed statement of operations for the three and nine months ended September 30, 2012.

These investments are accounted for by the equity method.

The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s consolidated and condensed balance sheets and the components of equity in earnings of unconsolidated entities included in the Partnership’s consolidated and condensed statements of operations:



	September 30, 2012		December 31, 2011
Investment in Waskom¹	$	—	$	102,896
Investment in PIPE¹	—		1,291
Investment in Matagorda¹	—		3,362
Investment in unconsolidated entities classified as assets held for sale	—		107,549
Investment in Redbird	80,168		62,948
Investment in Caliber	631		—
Investment in unconsolidated entities	80,799		62,948
Total Investment in unconsolidated entities	$	80,799	$	170,497

¹ As of December 31, 2011, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed balance sheet as assets held for sale.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Equity in earnings of Waskom¹	$	287		$	1,767		$	4,172		$	6,779
Equity in earnings of PIPE¹	10			(15		)	(60		)	(45		)
Equity in earnings of Matagorda¹	80			87			499			120
Equity in earnings of discontinued operations	377			1,839			4,611			6,854
Equity in earnings of Redbird	(103		)	(54		)	(433		)	100
Equity in earnings of Caliber	(98		)	—			(119		)	—
Equity in earnings of Pecos Valley	32			—			20			—
Equity in earnings of unconsolidated entities	(169		)	(54		)	(532		)	100
Total equity in earnings of unconsolidated entities	$	208		$	1,785		$	4,079		$	6,954

¹ For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed statement of operations and cash flows as discontinued operations.

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



	As of September 30				Three Months Ended September 30				Nine Months Ended September 30
	Total Assets		Partner’s Capital		Revenues¹		Net Income¹		Revenues¹		Net Income¹
2012
Waskom	$	—	$	—	$	8,171	$	668	$	66,662	$	8,986
	As of December 31
2011
Waskom	$	146,655	$	126,863	$	29,508	$	3,808	$	95,086	$	14,382

¹ Revenues and Net Income for Waskom include financial information only for the periods owned. Three months ended September 30, 2012 only includes financial information for the one month ended July 31, 2012. Nine months ended September 30, 2012 only includes financial information for the seven months ended July 31, 2012.

As of September 30, 2012 and December 31, 2011 the amount of the Partnership’s consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity-method investees is $0 and $47,152, 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 September 30, 2012 and December 31, 2011, the Partnership’s interest in cash of the unconsolidated equity-method investees was $502 and $565, respectively.


(7)	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 outstanding 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

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. If a forecasted hedge transaction is no longer probable of occurring, any gain or loss in AOCI is 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.


(a)	Commodity Derivative Instruments

The Partnership is exposed to market risks associated with commodity prices and from time to time 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. 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 sale of the Prism Assets completed on July 31, 2012, as of September 30, 2012, the Partnership has terminated and settled all of its commodity derivative instruments. For the three and nine months ended September 30, 2012, 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.


(b)	Impact of Commodity Cash Flow Hedges

Crude Oil. For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts decreased and increased crude revenue (included in income from discontinued operations) by $36 and $361, respectively. For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased crude revenue (included in income from discontinued operations) by $496 and $658, respectively.

Natural Gas. For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $77 and $72, respectively. For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $813 and $215, respectively.

Natural Gas Liquids. For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $5 and $236, respectively. For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $1,066 and $458, respectively.

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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)


(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 credit facility and its’ senior notes. 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.

In August 2011, the Partnership terminated all of its existing interest swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes as described in Note 11. These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings. Termination fees of $2,800 were received on the early extinguishment of the interest rate swap agreements in August 2011.

The Partnership was not a party to interest rate derivatives during the nine months ended September 30, 2012. The Partnership recognized decreases in interest expense of $3,244 and $5,779 for the three and nine months ended September 30, 2011, 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	September 30, 2012		December 31, 2011		Balance Sheet Location	September 30, 2012		December 31, 2011
Derivatives designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	622	Fair value of derivatives	$	—	$	245
Total derivatives designated as hedging instruments		$	—	$	622		$	—	$	245
Derivatives not designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	117
Total derivatives not designated as hedging instruments		$	—	$	—		$	—	$	117

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)



	Effect of Derivative Instruments on the Consolidated Statement of Operations For the Three Months Ended September 30, 2012 and 2011
	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
	2012		2011			2012		2011			2012		2011
Derivatives designated as hedging instruments:
Commodity contracts	$	—	$	1,295	Income from discontinued operations	$	63	$	500	Income from discontinued operations	$	—	$	38
Total derivatives designated as hedging instruments	$	—	$	1,295		$	63	$	500		$	—	$	38



	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012			2011
Derivatives not designated as hedging instruments:
Interest rate contracts	Interest expense	$	—		$	3,244
Commodity contracts	Income from discontinued operations	(18		)	131
Total derivatives not designated as hedging instruments		$	(18	)	$	3,375

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

Effect of Derivative Instruments on the Consolidated Statement of Operations

For the Nine Months Ended September 30, 2012 and 2011



	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
	2012		2011			2012		2011				2012		2011
Derivatives designated as hedging instruments
Interest rate contracts	$	—	$	—	Interest expense	$	—	$	(18	)	Interest expense	$	—	$	—
Commodity contracts	126		1,231		Income from discontinued operations	748		1,264			Income from discontinued operations	4		$	27
Total derivatives designated as hedging instruments	$	126	$	1,231		$	748	$	1,246			$	4	$	27



	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012		2011
Derivatives not designated as hedging instruments
Interest rate contracts	Interest Expense	$	—	$	5,797
Commodity contracts	Income from discontinued operations	1,623		41
Total derivatives not designated as hedging instruments		$	1,623	$	5,838

No amounts are expected to be reclassified into earnings for the subsequent 12-month period for commodity cash flow hedges.


(8)	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 7 for further information on the Partnership’s derivative instruments and hedging activities.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at December 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	December 31, 2011		(Level 1)		(Level 2)		(Level 3)
Assets
Natural gas derivatives	$	622	$	—	$	622	$	—
Total assets	$	622	$	—	$	622	$	—
Liabilities
Crude oil derivatives	245		—		245		—
Natural gas liquids derivatives	117		—		117		—
Total liabilities	$	362	$	—	$	362	$	—

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 due to the short maturity and highly liquid nature of these instruments.


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

The estimated fair value of the Senior Notes was approximately $189,557 as of September 30, 2012 based on quoted market prices of similar debt at September 30, 2012, which is deemed a Level 2 measurement.


(9)	Related Party Transactions

As of September 30, 2012, Martin Resource Management owns 6,593,267 of the Partnership’s common units representing approximately 28.5% 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 September 30, 2012, of approximately 28.5% 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.

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 the Partnership’s 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The omnibus agreement was amended further on October 2, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. See Note 16.

Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls the general partner of the Partnership, 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 the Partnership’s behalf of any asset or group of assets owned by it or its 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, Florida, 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 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.

Services. Under the omnibus agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The omnibus agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s 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, under the omnibus agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

Effective October 1, 2011, through September 30, 2012, the Conflicts Committee of the board of directors of the general partner of the Partnership (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $6,582. The Partnership reimbursed Martin Resource Management for $1,646 and $4,937 of indirect expenses for the three and nine months ended September 30, 2012, respectively. The Partnership reimbursed Martin Resource Management $1,042 and $3,126 of indirect expenses for the three and nine months ended September 30, 2011, 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 the Partnership, 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 the general partner of the Partnership.

Related Party Transactions. The omnibus agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the conflicts committee of the 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 the Partnership 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 the Partnership’s general partner if such amendment would adversely affect the unitholders. The omnibus agreement was first amended on November 24, 2009, to permit the Partnership to provide refining services to Martin Resource Management. The omnibus agreement was amended further on October 2, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. See Note 16. Such amendments were approved by the conflicts committee of the Partnership’s 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 its 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 the Partnership 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 any time 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 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.

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

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 Oil & Refining Marketing, Inc. (“Cross”) entered into two marine charter agreements with the Partnership effective March 1, 2012. 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 the Partnership charges 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. The Partnership is a party to an agreement under which it processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The Tolling Agreement has a 22 year term which expires November 25, 2031. Under this Tolling Agreement, Martin Resource Management agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel. Any additional barrels are processed 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, that is not consumed by the Partnership’s internal operations. This agreement, which was amended and restated in July 2011, 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.

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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

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 September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Revenues:
Terminalling and storage	$	18,531		$	14,210	$	48,611	$	40,045
Marine transportation	3,979			6,352		13,282		19,223
Product sales:
Natural gas services	(1		)	29		104		663
Sulfur services	1,469			1,537		4,829		6,358
Terminalling and storage	168			62		850		176
	1,636			1,628		5,783		7,197
	$	24,146		$	22,190	$	67,676	$	66,465

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



Cost of products sold:
Natural gas services	$	6,761	$	9,257	$	18,783	$	13,679
Sulfur services	4,111		4,762		12,512		13,407
Terminalling and storage	127		45		292		183
	$	10,999	$	14,064	$	31,587	$	27,269

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



Expenses:
Operating expenses
Marine transportation	$	7,236	$	8,631	$	21,217	$	21,412
Natural gas services	453		480		1,368		1,176
Sulfur services	1,494		1,901		4,796		4,803
Terminalling and storage	4,917		5,893		14,927		14,779
	$	14,100	$	16,905	$	42,308	$	42,170

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



Selling, general and administrative:
Marine transportation	$	15	$	19	$	47	$	49
Natural gas services	366		308		1,052		884
Sulfur services	737		1,004		2,183		2,285
Terminalling and storage	—		—		39		—
Indirect overhead allocation, net of reimbursement	1,646		1,042		4,937		3,126
	$	2,764	$	2,373	$	8,258	$	6,344


(10)	Business Segments

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

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, 2011, filed with the SEC on March 5, 2012. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all periods. See Note 4.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (loss) after eliminations			Capital Expenditures
Three Months Ended September 30, 2012
Terminalling and storage	$	45,667	$	(1,191	)	$	44,476	$	5,503	$	5,493		$	7,990
Natural gas services	190,738		—			190,738		149		3,270			143
Sulfur services	60,596		—			60,596		1,750		7,273			7,549
Marine transportation	22,879		(777		)	22,102		2,564		811			1,711
Indirect selling, general and administrative	—		—			—		—		(1,966		)	—
Total	$	319,880	$	(1,968	)	$	317,912	$	9,966	$	14,881		$	17,393

Three Months Ended September 30, 2011
Terminalling and storage	$	38,080	$	(1,174	)	$	36,906	$	4,829	$	3,457		$	14,360
Natural gas services	159,748		—			159,748		148		2,164			277
Sulfur services	70,169		—			70,169		1,676		5,921			2,598
Marine transportation	22,411		(1,638		)	20,773		3,372		(896		)	2,061
Indirect selling, general and administrative	—		—			—		—		(2,967		)	—
Total	$	290,408	$	(2,812	)	$	287,596	$	10,025	$	7,679		$	19,296

Nine Months Ended September 30, 2012
Terminalling and storage	$	130,131	$	(3,542	)	$	126,589	$	15,170	$	12,919		$	45,768
Natural gas services	527,666		—			527,666		436		6,457			410
Sulfur services	202,241		—			202,241		5,325		34,320			9,204
Marine transportation	65,912		(2,234		)	63,678		8,526		662			7,627
Indirect selling, general and administrative	—		—			—		—		(6,733		)	—
Total	$	925,950	$	(5,776	)	$	920,174	$	29,457	$	47,625		$	63,009

Nine Months Ended September 30, 2011
Terminalling and storage	$	115,492	$	(3,220	)	$	112,272	$	14,114	$	9,576		$	24,270
Natural gas services	423,953		—			423,953		435		5,598			581
Sulfur services	206,860		—			206,860		4,998		27,818			14,826
Marine transportation	63,201		(5,653		)	57,548		9,976		(5,143		)	9,092
Indirect selling, general and administrative	—		—			—		—		(6,547		)	—
Total	$	809,506	$	(8,873	)	$	800,633	$	29,523	$	31,302		$	48,769

The Partnership's assets by reportable segment, which exclude assets held for sale of $0 and $212,787, respectively, as of September 30, 2012 and December 31, 2011, are as follows:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)



	September 30, 2012		December 31, 2011
Total assets:
Terminalling and storage	$	161,544	$	231,764
Natural gas services	288,003		198,845
Sulfur services	258,712		162,289
Marine transportation	115,537		143,424
Total assets	$	823,796	$	736,322


(11)	Long-Term Debt and Capital Leases

At September 30, 2012 and December 31, 2011, long-term debt consisted of the following:



	September 30, 2012		December 31, 2011
$200,000* Senior notes, 8.875% interest, net of unamortized discount of $1,688 and $2,192, respectively, issued March 2010 and due April 2018, unsecured	$	173,312	$	197,808
$400,000 Revolving loan facility at variable interest rate (3.72%* weighted average at September 30, 2012), due April 2016 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees	77,000		250,000
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured by equipment	—		6,363
Capital lease obligations	5,871		6,031
Total long-term debt and capital lease obligations	256,183		460,202
Less current installments	217		1,261
Long-term debt and capital lease obligations, net of current installments	$	255,966	$	458,941

* Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%. The applicable margin for existing LIBOR borrowings is 3.00%. Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%. Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

*** Pursuant to the Indenture under which the Senior Notes were issued, the Partnership has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings. On April 24, 2012, the Partnership notified the Trustee of its intention to exercise a partial redemption of the Partnership’s Senior Notes pursuant to the Indenture. On May 24, 2012, the Partnership redeemed $25,000 of the Senior Notes from various holders using proceeds of the Partnership’s January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under the Partnership’s revolving credit facility. In

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

conjunction with the redemption, the Partnership incurred a debt prepayment premium in the amount of $2,219, which is included in the consolidated and condensed statements of operations for the nine months ended September 30, 2012.

In August 2011, the Partnership terminated all of its existing interest rate swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes. These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings. The Partnership received a termination benefit of $2,800 upon cancellation of these swap agreements.

Effective May 10, 2012, the Partnership increased the maximum amount of borrowings and letters of credit available under the Credit Facility from $375,000 to $400,000.

The Partnership paid cash interest in the amount of $4,696 and $2,813 for the three months ended September 30, 2012 and 2011, respectively. The Partnership paid cash interest in the amount of $19,039 and $6,662 for the nine months ended September 30, 2012 and 2011, respectively. Capitalized interest was $175 and $127 for the three months ended September 30, 2012 and 2011, respectively. Capitalized interest was $799 and $373 for the nine months ended September 30, 2012 and 2011, respectively.


(12)	Equity Offering

On January 25, 2012, the Partnership completed a public offering of 2,645,000 common units at a price of $36.15 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 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91,361. The Partnership’s general partner contributed $1,951 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. On January 25, 2012, all of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

On February 9, 2011, the Partnership completed a public offering of 1,874,500 common units at a price of $39.35 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 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70,330. The Partnership’s general partner contributed $1,505 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 reduce the outstanding balance under its revolving credit facility.


(13)	Income Taxes

Because its income is taxed directly to its partners, the operations of a partnership are generally not subject to income taxes, except as discussed below. Effective January 1, 2007, the Partnership became subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the consolidated statements of operations.

The Partnership’s taxable subsidiary, Woodlawn, is subject to income taxes due to its corporate structure. Income tax expense related to Woodlawn is recorded in discontinued operations. A current state income tax expense of $568 and $574, related to Woodlawn was recorded for the three and nine months ended September 30, 2012. A current state income tax expense of $6 and $17 related to Woodlawn was recorded for the three and nine months ended September 30, 2011, respectively.

A deferred tax benefit related to the Woodlawn basis differences of $7,373 and $7,695 was recorded for the three and nine months ended September 30, 2012, respectively. A deferred tax expense of $33 and $2 was recorded for the three and nine months ended September 30, 2011, respectively. A deferred tax (asset) liability of $(38) and $7,657 related to the basis differences existed at September 30, 2012 and December 31, 2011, respectively.

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 recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $238 and $810 were recorded in

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

current income tax expense in continuing operations for the three and nine months ended September 30, 2012 and $218 and $662 for the three and nine months ended September 30, 2011, respectively.

The components of income tax expense (benefit) from operations recorded for the three and nine months ended September 30, 2012 and 2011 are as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	806			223			1,384			679
	6,609			206			7,191			690
Deferred:
Federal	(7,373		)	33			(7,695		)	2
Total income tax expense (benefit)	$	(764	)	$	239		$	(504	)	$	692

Total income tax expense was allocated to continuing and discontinued operations as follows:

Income tax expense (benefit) from continuing operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Current:
State	$	238	$	218	$	810	$	662
Total income tax expense from continuing operations	$	238	$	218	$	810	$	662

Income tax expense (benefit) from discontinued operations:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	568			6			574			17
	6,371			(11		)	6,381			28
Deferred:
Federal	(7,373		)	32			(7,695		)	2
Total income tax expense (benefit) from discontinued operations	$	(1,002	)	$	21		$	(1,314	)	$	30


(14)	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.

On October 2, 2012, the Partnership announced that the ongoing litigation and disputes involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all the lawsuits and disputes referenced in this section. Accordingly, none of the following matters are currently pending and such information is being provided for reference only.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

On May 2, 2008, the Partnership received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management. In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment adverse to the Defendant which contained monetary damages and specific performance components (the “Judgment”). The Defendant appealed the Judgment. On November 3, 2010, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment. The Appellate Court’s opinion rendered a take-nothing judgment against the Plaintiff and found in favor of the Defendant. The Supreme Court of Texas denied the Plaintiff’s petition for review and therefore the opinion of the Sixth Appellate District of Texas at Texarkana has become final.

On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court (the “Harris County Litigation”) against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of the Partnership’s general partner. The Partnership is not a party to this lawsuit, and it does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations, or (iii) against the MRMC Director Defendants or other MRMC Defendants with respect to their service to the Partnership.

The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley M. Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Trust (the “ESOT”), and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares. The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The case was abated in July 2009 during the pendency of a mandamus proceeding in the Texas Supreme Court. The Supreme Court denied mandamus relief on November 20, 2009. This lawsuit was amended to add the ESOT as a party and was subsequently removed to Federal Court by the ESOT. This lawsuit was remanded from Federal Court to the State District Court. The trial was previously set for August of 2012 but has been removed from the trial docket. The trial is nonetheless stayed pending the outcome of procedural matters pending in the appellate courts.

The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against Scott Martin, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that he has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached fiduciary duties owed to Angela Jones Alexander, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, the Partnership has been informed that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above, Angela Jones Alexander amended her claims to include her grandmother, Margaret Martin, as a defendant, but subsequently dropped her claims against Mrs. Martin. Additionally, all claims pertaining to Karen Yost have been resolved. All claims pertaining to Defendant have been preliminarily resolved, as the court, on February 9, 2011, issued an order that granted the parties’ Joint Motion for Administrative Closure. With respect to the lawsuit referenced in (i) above, the case was tried in October 2009 and the jury returned a verdict in favor of the Defendant’s daughters against Scott Martin in the amount of $4,900. On December 22, 2009, the court entered a judgment, reflecting an amount consistent with the verdict and additionally awarded attorneys’ fees and interest. On January 7, 2010, the court modified its original judgment and awarded the Defendant’s daughters approximately $2,700 in damages and attorneys’ fees, plus interest. Scott Martin has appealed the

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

judgment. On March 20, 2012, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment. While the Appellate Court found that there was sufficient evidence to support the jury’s finding that a breach of fiduciary duty occurred, it found insufficient evidence to support any damages and therefore rendered a take-nothing judgment against the daughters of the Defendant. A motion for rehearing at the Appellate Court was overruled on April 26, 2012. The Defendant’s daughters have indicated they will appeal the Appellate Court’s ruling.

On February 22, 2010, as a result of the Harris County Litigation being derivative in nature, Martin Resource Management formed a special committee of its board of directors and designated such committee as the Martin Resource Management authority for the purpose of assessing, analyzing and monitoring the Harris County Litigation and any other related litigation and making any and all determinations in respect of such litigation on behalf of Martin Resource Management. Such authorization includes, but is not limited to, reviewing the merits of the litigation, assessing whether to pursue claims or counterclaims against various persons or entities, assess whether to appoint or retain experts or disinterested persons to make determinations in respect of such litigation, and advising and directing Martin Resource Management’s general counsel and outside legal counsel with respect to such litigation. The special committee consists of Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton.

On May 4, 2010, the Partnership received a copy of a petition filed in a new case with the District Clerk of Gregg County, Texas by Martin Resource Management against the Plaintiff and others with respect to certain matters relating to Martin Resource Management (“the Gregg County Matter”). As noted above, the Plaintiff was a former director of Martin Resource Management. The lawsuit alleges that the Plaintiff with help from others breached the fiduciary duties the Plaintiff owed to Martin Resource Management. The Partnership is not a party to the lawsuit, and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations, or (iii) against the Plaintiff with respect to his service as an officer or former director of the general partner of the Partnership. With respect to this lawsuit, the case was tried in January 2012 and the jury returned a verdict in favor of Martin Resource Management against Scott D. Martin for breach of fiduciary duty and awarded an amount of $1,800. The court entered a judgment in favor of Martin Resource Management in the amount awarded by the jury plus interest. Scott D. Martin is appealing this judgment.

Additionally, on July 11, 2011, Scott D. Martin sued Martin Resource Management in State District Court in Harris County, Texas, alleging that it tortiously interfered with his rights under an existing insurance policy. A motion to transfer this case was granted and this case is currently pending in the 188th District Court of Gregg County, Texas.

On June 22, 2012, the Partnership received from Scott D. Martin a demand that the Partnership indemnify him for legal fees and damages adjudged against him in the Gregg County Matter. He followed this up with an additional demand that the Partnership indemnify him for legal fees and expenses he paid in defending the lawsuit brought in Gregg County, Texas by the daughters of the Defendant. On June 25, 2012, the Partnership filed a petition in the District Court of Gregg County, Texas against Scott D. Martin, seeking a declaratory judgment regarding the Partnership’s obligations to indemnify Scott D. Martin.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)


(15)	Consolidating Financial Statements

Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, has issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities 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.


(16)	Subsequent Events

Litigation Settlement. On October 2, 2012, the Partnership announced that the ongoing litigation and disputes as described in Note 14 involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all of the lawsuits and disputes referenced in Note 14. In connection with the settlement, Martin Resource Management transferred 1,500,000 common units of the Partnership to KCM, LLC, and Martin Resource Management now owns 5,093,267 common units of the Partnership.

Acquisition of Lubricant Packaging Assets. On October 2, 2012, the Partnership purchased certain specialty lubricant packaging assets from Cross Oil Refining & Marketing, Inc., a wholly-owned subsidiary of Martin Resource Management. The consideration consisted of $121,800 in cash, including working capital of approximately $36,800, subject to certain post-closing adjustments. The purchase was funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these packaging assets will be recorded at amounts based on the historical carrying value of the assets at the acquisition date, and we are required to revise our historical financial statements to include the activities of the packaging assets as of the date of common control. Our historical financial statements will be retrospectively revised to reflect the financial position, cash flows and results of operations attributable to these packaging assets as if we owned them for each period presented.

Acquisition of Redbird Class A Interests. On October 2, 2012, the Partnership acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150,000 in cash. Prior to the transaction, the Partnership owned a 10.74% Class A interest and a 100% Class B interest in Redbird. This transaction was also funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these interests will be recorded at amounts based on the historical carrying value of the interests at the acquisition date, and we are required to revise our historical financial statements to include the activities of the Class A interests as of the date of common control. Our historical financial statements will be retrospectively revised to reflect the financial position, cash flows and results of operations attributable to these packaging assets as if we owned them for each period presented.

Amendment No. 2 to Omnibus Agreement. In connection with the purchase of the Cross packaging assets, on October 2, 2012, the Partnership entered into Amendment No. 2 to the Partnership's omnibus agreement (the “Amendment”) with Martin Resource Management, the General Partner, and Martin Operating Partnership L.P. The Amendment allows the Partnership to provide certain products and services to Martin Resource Management under the Omnibus Agreement by amending the definition of the term “Business” to reflect the operation of the packaging assets acquired by the Partnership pursuant to the purchase agreement.

Amendment No. 3 to the Second Amendment and Restated Agreement of Limited Partnership. In conjunction with the Redbird purchase agreement, on October 2, 2012, the General Partner executed Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (“the Partnership Agreement”). The Partnership Agreement Amendment provides that the General Partner, currently the holder of the incentive distribution rights, shall not receive the next $18,000 in incentive distributions that it would otherwise be entitled to receive.

Table of Contents



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

References in this quarterly report on Form 10-Q 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, 2011, filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2012, and in this report.

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;


•	Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and


•	Marine transportation services for petroleum products and by-products.

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 28.0% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest in us and all of our incentive distribution rights.

Martin Resource Management has operated our business since 2002. 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.

Recent Developments

We believe one of the rationales driving investment in master limited partnerships, including us, is the opportunity for distribution growth offered by the partnerships. Such distribution growth is a function of having access to liquidity in the financial markets used for incremental capital investment (development projects and acquisitions) to grow distributable cash flow. Growth opportunities can be constrained by a lack of liquidity or access to the financial markets. During 2011 and thus far in 2012, the financial markets were available to us. As such, we were able to issue equity in February 2011 and January 2012 for the purpose of reducing outstanding indebtedness under our credit facility. Our credit facility is our primary source of liquidity and was refinanced in April 2011. Additionally, we upsized our credit facility in April 2011, December 2011, and May 2012.

Conditions in our industry continue to be challenging in 2012. For example:

•

Coupled with the general decline in drilling activity are the federal government’s enhanced safety regulations and inspection requirements as it relates to deep-water drilling in the Gulf of Mexico. These enhanced safety regulations and inspection requirements of the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) continue to provide uncertainty surrounding the requirements for and pace of issuance of permits on the Gulf of Mexico Outer Continental Shelf (OCS). Although permits began to be issued by the BOEMRE again during first quarter 2011, they have not been approved in a timely manner consistent with pre-BP/Macondo spill levels.

Despite the industry challenges we have faced, we are positioning ourselves for continued growth. In particular:

•

We continue to adjust our business strategy to focus on maximizing our liquidity, maintaining a stable asset base, and improving the profitability of our assets by increasing their utilization while controlling costs. Over the past year we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth. Our goal over the next two years will be to increase growth capital expenditures primarily in our Terminalling and Storage and Sulfur Services segments.


•	We continue to evaluate opportunities to enter into interest rate and commodity hedging transactions. We believe these transactions can beneficially remove risks associated with interest rate and commodity price volatility.


•	During this past year, we have experienced positive changing market dynamics in our Terminalling and Storage and Marine Transportation segments including activity associated with the rapidly developing basins such as the Eagle Ford shale in South Texas.

On July 31, 2012, we completed the sale of our East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas Systems I, L.P. (“Prism Gas”), our wholly-owned subsidiary, and other natural gas gathering and processing assets also owned by us to a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”). We received net cash proceeds from the sale of $273.3 million. The asset sale includes our 50% operating interest in Waskom Gas Processing Company (“Waskom”). A subsidiary of CenterPoint currently owns the other 50% percent interest.

Additionally, on September 18, 2012, we completed the sale of our interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) to a private investor group for $1.5 million.

Acquisition of Lubricant Packaging Assets. On October 2, 2012, we purchased certain specialty lubricant packaging assets from Cross Oil Refining & Marketing, Inc., a wholly-owned subsidiary of Martin Resource Management. The consideration consisted of $121.8 million in cash, including working capital of approximately $36.8 million, subject to certain post-closing adjustments. The purchase was funded by borrowings under our revolving credit facility.

Acquisition of Redbird Class A Interests. On October 2, 2012, we acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150.0 million in cash. Prior to the transaction, we owned a 10.7% Class A

interest and a 100% Class B interest in Redbird. This transaction was also funded by borrowings under our revolving credit facility.

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. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 350 related to goodwill. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2011, and there have been no material changes to these policies through September 30, 2012.

Our Relationship with Martin Resource Management

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


•	providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;


•	distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids;


•	providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas;


•	operating a small crude oil gathering business in Stephens, Arkansas;


•	operating a lube oil processing facility in Smackover, Arkansas;


•	operating an underground NGL storage facility in Arcadia, Louisiana;


•	supplying employees and services for the operation of our business; and


•	operating, solely for our account, our asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.

We are and will continue to be closely affiliated with Martin Resource Management as a result of the following relationships.

Ownership

Martin Resource Management owns an approximate 28.0% limited partnership interest and a 2% general partnership interest in us and all of our incentive distribution rights.

Management

Martin Resource Management directs our business operations through its ownership and control of our general partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of management expertise and established relationships throughout the energy industry. We do not have employees. Martin Resource Management employees are responsible for conducting our business and operating our assets on our behalf.

Related Party Agreements

We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $26.2 million of direct costs and expenses for the three months ended September 30, 2012 compared to $32.3 million for the three months ended September 30, 2011. We reimbursed Martin Resource Management for $77.2 million of direct costs and expenses for the nine months ended September 30, 2012 compared to $72.7 million for the nine months ended September 30, 2011. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. Effective October 1, 2011 through September 30, 2012, the Conflicts Committee of the board of directors of our general partner (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $6.6 million. We reimbursed Martin Resource Management for $1.6 and $1.0 million of indirect expenses for the three months ended September 30, 2012 and 2011, respectively. We reimbursed Martin Resource Management for $4.9 and $3.1 million of indirect expenses for the nine months ended September 30, 2012 and 2011, respectively. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The omnibus agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the omnibus agreement.

In addition to the omnibus agreement, we and Martin Resource Management have entered into various other agreements including, but not limited to, a motor carrier agreement, terminal services agreements, marine transportation agreements and other agreements for the provision of various goods and services. Pursuant to the terms of the omnibus agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee.

For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions – Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012.

Commercial

We have been and anticipate that we will continue to be both a significant customer and supplier of products and services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is currently a key component of our integrated distribution network.

We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.4 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

In the aggregate, our purchases of land transportation services, NGL storage services, sulfuric acid and lube oil product purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 4% and 6% of our total cost of products sold during the three months ended September 30, 2012 and 2011, respectively and approximately 4% and 4% of our total cost of products sold for the nine months ended September 30, 2012 and 2011, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for approximately 8% of our total revenues for both the three months ended September 30, 2012 and 2011. Our sales to Martin Resource Management accounted for approximately 7% and 8% of our total revenues for the nine months ended September 30, 2012 and 2011, respectively. We provide terminalling and storage and marine transportation services to Martin Energy Services LLC and Martin Energy Services LLC provides terminal services to us to handle lubricants, greases and drilling fluids.

For a more comprehensive discussion concerning the agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions – Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012.

Approval and Review of Related Party Transactions

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

Results of Operations

The results of operations for the three and nine months ended September 30, 2012 and 2011 have been derived from our consolidated and condensed financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating revenues and operating income by segment for the three and nine months ended September 30, 2012 and 2011. The results of operations for these interim periods during the year are not necessarily indicative of the results of operations which might be expected for the entire year.

The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all periods.



	Operating Revenues		Revenues Intersegment Eliminations			Operating Revenues after Eliminations		Operating Income (loss)			Operating Income Intersegment Eliminations			Operating Income (loss) after Eliminations
	(In thousands)
Three Months Ended September 30, 2012
Terminalling and storage	$	45,667	$	(1,191	)	$	44,476	$	6,148		$	(655	)	$	5,493
Natural gas services	190,738		—			190,738		2,876			394			3,270
Sulfur services	60,596		—			60,596		6,114			1,159			7,273
Marine transportation	22,879		(777		)	22,102		1,709			(898		)	811
Indirect selling, general and administrative	—		—			—		(1,966		)	—			(1,966		)
Total	$	319,880	$	(1,968	)	$	317,912	$	14,881		$	—		$	14,881

Three Months Ended September 30, 2011
Terminalling and storage	$	38,080	$	(1,174	)	$	36,906	$	3,810		$	(353	)	$	3,457
Natural gas services	159,748		—			159,748		1,793			371			2,164
Sulfur services	70,169		—			70,169		4,301			1,620			5,921
Marine transportation	22,411		(1,638		)	20,773		742			(1,638		)	(896		)
Indirect selling, general and administrative	—		—			—		(2,967		)	—			(2,967		)
Total	$	290,408	$	(2,812	)	$	287,596	$	7,679		$	—		$	7,679

Nine Months Ended September 30, 2012
Terminalling and storage	$	130,131	$	(3,542	)	$	126,589	$	14,882		$	(1,963	)	$	12,919
Natural gas services	527,666		—			527,666		5,302			1,155			6,457
Sulfur services	202,241		—			202,241		30,927			3,393			34,320
Marine transportation	65,912		(2,234		)	63,678		3,247			(2,585		)	662
Indirect selling, general and administrative	—		—			—		(6,733		)	—			(6,733		)
Total	$	925,950	$	(5,776	)	$	920,174	$	47,625		$	—		$	47,625

Nine Months Ended September 30, 2011
Terminalling and storage	$	115,492	$	(3,220	)	$	112,272	$	10,150		$	(574	)	$	9,576
Natural gas services	423,953		—			423,953		4,779			819			5,598
Sulfur services	206,860		—			206,860		22,430			5,388			27,818
Marine transportation	63,201		(5,653		)	57,548		490			(5,633		)	(5,143		)
Indirect selling, general and administrative	—		—			—		(6,547		)	—			(6,547		)
Total	$	809,506	$	(8,873	)	$	800,633	$	31,302		$	—		$	31,302

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

Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2011

Our total revenues before eliminations were $319.9 million for the three months ended September 30, 2012, compared to $290.4 million for the three months ended September 30, 2011, an increase of $29.5 million, or 10%. Our operating income before eliminations was $14.9 million for the three months ended September 30, 2012, compared to $7.7 million for the three months ended September 30, 2011, an increase of $7.2 million, or 94%.

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

Terminalling and Storage Segment

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



	Three Months Ended September 30,
	2012		2011
	(In thousands)
Revenues:
Services	$	25,066	$	20,555
Products	20,601		17,525
Total revenues	45,667		38,080

Cost of products sold	19,303		16,497
Operating expenses	14,373		12,891
Selling, general and administrative expenses	340		53
Depreciation and amortization	5,503		4,829
Operating income	$	6,148	$	3,810

Revenues. Our terminalling and storage revenues increased $7.6 million, or 20%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. Of the increase, $4.5 million is related to new terminalling assets commissioned in the second quarter of 2012 and fourth quarter of 2011. Product revenues increased $3.1 million compared to the prior year period. This increase is primarily related to a new trade agreement executed during the fourth quarter of 2011 with a customer operating out of our River Ridge location.

Cost of products sold. Our cost of products increased $2.8 million, or 17%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. This increase is primarily related to a new trade agreement executed during the fourth quarter of 2011 with a customer operating out of our River Ridge location.

Operating Expenses. Operating expenses increased $1.5 million, or 12%, for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The increase in operating expenses is primarily due to having a full quarter of operations from new terminalling assets commissioned in the second quarter of 2012 and fourth quarter of 2011.

Selling, general and administrative expenses. Selling, general, and administrative expenses increased $0.3 million for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. This increase is related to an increase of $0.3 million in compensation expense.

Depreciation and amortization. Depreciation and amortization increased $0.7 million, or 14%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011 resulting from capital expenditures made during the past twelve months.

In summary, our terminalling and storage operating income increased $2.4 million, or 61%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

Natural Gas Services Segment

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



	Three Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	190,738	$	159,748
Cost of products sold	186,080		156,607
Operating expenses	847		762
Selling, general and administrative expenses	786		438
Depreciation and amortization	149		148
Operating income	$	2,876	$	1,793

NGLs Volumes (Bbls)	3,092		2,068

Revenues. Our natural gas services revenues increased $31.0 million, or 19% for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. NGL sales volumes for the three months of 2012 increased 50% compared to the same period of 2011, resulting in a positive impact on revenues of $62.4 million. Our NGL average sales price per barrel for the three months ended September 30, 2012, decreased $15.60, or 20% compared to the same period of 2011, resulting in a decrease in revenue of $31.4 million.

Cost of products sold. Our cost of products sold increased $29.5 million, or 19%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. The percentage increase in NGL cost of products sold was approximately the same as our percentage increase in NGL revenues, resulting in increased margins of 20% for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Operating expenses. Operating expenses remained consistent for the three months ended September 30, 2012, as compared to the three months ended September 30, 2011.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.3 million, or 79%, for the three months ended September 30, 2012, as compared to the three months ended September 30, 2011. This is primarily due to an increase in the reserve of an uncollectible customer receivable of $0.1 million and increased compensation expense of $0.2 million.

Depreciation and amortization. Depreciation and amortization remained consistent for the three months ended September 30, 2012, as compared to the three months ended September 30, 2011.

In summary, our natural gas services operating income increased $1.1 million, or 60%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Sulfur Services Segment

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



	Three Months Ended September 30,
	2012			2011
	(In thousands)
Revenues:
Services	$	2,926		$	2,850
Products	57,670			67,319
Total revenues	60,596			70,169

Cost of products sold	47,362			59,899
Operating expenses	4,357			4,930
Selling, general and administrative expenses	1,008			774
Depreciation and amortization	1,750			1,676
	6,119			2,890
Other operating income (loss)	(5		)	1,411
Operating income	$	6,114		$	4,301

Sulfur (long tons)	225.6			310.2
Fertilizer (long tons)	61.2			54.2
Sulfur services volumes (long tons)	286.8			364.4

Revenues. Our total sulfur services revenues decreased $9.6 million, or 14%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. The decrease in products revenue was primarily a result of a 21% decline in volumes sold.

Cost of products sold. Our cost of products sold decreased $12.5 million, or 21%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. The percentage decrease in sulfur services cost of products sold was higher than our percentage decrease in sulfur services revenues, resulting in an increase in our margin per ton of 77%.

Operating expenses. Our operating expenses decreased $0.5 million, or 12%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This was primarily a result of decreased outside towing expenses.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.2 million, or 30%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This increase is related to an increase of $0.1 million in overhead allocation expense and $0.1 million in compensation expense.

Depreciation and amortization. Depreciation and amortization expense increased $0.1 million, or 4%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Other operating income. Other operating income decreased $1.4 million for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This decrease relates to business interruption insurance recoveries from Hurricane Ike that were reimbursed in 2011.

In summary, our sulfur operating income increased $1.8 million, or 42%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Marine Transportation Segment

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



	Three Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	22,879	$	22,411
Operating expenses	18,026		17,300
Selling, general and administrative expenses	580		1,306
Depreciation and amortization	2,564		3,372
	1,709		433
Other operating income	—		309
Operating income	$	1,709	$	742

Revenues. Our marine transportation revenues increased $0.5 million, or 2%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This increase was primarily a result of an increase in our offshore marine operations somewhat offset by a decrease in our inland marine operations. Our offshore revenues increased $1.7 million, primarily due to increased utilization of the offshore fleet in 2012 of $1.1 million due to increased demand for our two offshore tows which operate in the spot market and an increase in ancillary charges of $0.6 million. Our inland marine operations decreased $1.2 million, of which $1.3 million is attributed to decreased utilization of the inland fleet and $0.1 million in increased ancillary charges, primarily related to fuel.

Operating expenses. Operating expenses increased $0.7 million, or 4%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This increase in operating costs is primarily due to increases in fuel expense of $0.7 million, increased repairs and maintenance expense of $0.6 million, decreased outside towing expense of $0.3 million, and decreased barge cleaning and lease rental of $0.3 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.7 million, or 56%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This decrease was primarily related to a decrease in expense related to an uncollectible customer accounts receivable.

Depreciation and amortization. Depreciation and amortization decreased $0.8 million, or 24%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This decrease was primarily a result of a reduction in depreciation from disposal of equipment made in the last twelve months somewhat offset by capital expenditures made in the last twelve months.

In summary, our marine transportation operating income increased $1.0 million, or 130% for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

Our total revenues before eliminations were $926.0 million for the nine months ended September 30, 2012 compared to $809.5 million for the nine months ended September 30, 2011, an increase of $116.5 million, or 14%. Our operating income before eliminations was $47.6 million for the nine months ended September 30, 2012 compared to $31.3 million for the nine months ended September 30, 2011, an increase of $16.3 million, or 52%.

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

Terminalling and Storage Segment

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



	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Revenues:
Services	$	68,649	$	60,031
Products	61,482		55,461
Total revenues	130,131		115,492

Cost of products sold	57,733		52,277
Operating expenses	42,340		38,145
Selling, general and administrative expenses	401		229
Depreciation and amortization	15,170		14,114
	14,487		10,727
Other operating income (loss)	395		(577		)
Operating income	$	14,882	$	10,150

Revenues. Our terminalling and storage revenues increased $14.6 million, or 13%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. Of the increase in total revenues, $8.6 million is attributable to services revenue and $6.0 million pertains to product revenues. The increase in services revenue is primarily related to certain terminalling assets commissioned during the nine months of 2012 and the fourth quarter of 2011. Of the increase in product revenues, $9.8 million was due to the conversion of a consigned product delivery agreement with one of our customers during December 2011. This increase was offset by decreased revenues of $3.8 million from reduced sales volumes.

Cost of products sold. Our cost of products sold increased $5.5 million, or 10%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. Of this increase, $9.1 million was primarily due to the conversion of a consigned product delivery agreement with one of our customers during December 2011. The increase was offset by a $3.4 million decrease in cost of sales from reduced sales volumes.

Operating expenses. Operating expenses increased $4.2 million, or 11%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. Of this increase, $4.0 million was due primarily to increased operating expenses associated with certain terminalling assets commissioned during the nine months of 2012 and the fourth quarter of 2011.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.2 million, or 75%, for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011. This is primarily due to increased compensation expense of $0.2 million.

Depreciation and amortization. Depreciation and amortization increased $1.1 million, or 7%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. The balance of the increase was a result of capital expenditures made during the past twelve months.

Other operating income. Other operating income of $0.4 million for the nine months ended September 30, 2012 consisted of the final indemnity payment related to the sale of our Mont Belvieu facility in 2009. Other operating income for the nine months ended September 30, 2011 includes a loss of $0.7 million on the disposition of certain property, plant and equipment at our terminal located in Corpus Christi, Texas. The disposition was executed to facilitate the construction of a new crude terminal adjacent to our existing facility. The loss was offset primarily by business interruption insurance recoveries of $0.1 million received during the second quarter of 2011.

In summary, our terminalling and storage operating income increased $4.7 million, or 47%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Natural Gas Services Segment

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



	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	527,666	$	423,953
Cost of products sold	517,083		414,981
Operating expenses	2,603		2,249
Selling, general and administrative expenses	2,242		1,509
Depreciation and amortization	436		435
Operating income	$	5,302	$	4,779

NGLs Volumes (Bbls)	7,825		5,444

Revenues. Our natural gas services revenues increased $103.7 million, or 24% for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. Natural gas services volumes for the nine months of 2012 increased 44% compared to the same period of 2011, positively impacting revenues $160.0 million. Our NGL average sales price per barrel for the nine months ended September 30, 2012, decreased $10.44, or 13% compared to the same period of 2011, resulting in an offsetting decrease to revenues of $56.3 million.

Cost of products sold. Our cost of products sold increased $102.1 million, or 25%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. The percentage increase in NGL cost of products sold was slightly higher than our percentage increase in NGL revenues, resulting in decreased margins of $0.30 per barrel.

Operating expenses. Operating expenses increased $0.4 million, or 16%, for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011. This is primarily related to increased compensation expense of $0.1 million and increased pipeline maintenance expenses of $0.2 million.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.7 million, or 49%, for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011. This is primarily due to an increase in the reserve of an uncollectible customer receivable of $0.4 million, increased compensation expense of $0.1 million, and increased property tax expense of $0.1 million.

Depreciation and amortization. Depreciation and amortization remained consistent for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011.

In summary, our natural gas services operating income increased $0.5 million, or 11%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.

Sulfur Services Segment

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



	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Revenues:
Services	$	8,777		$	8,550
Products	193,464			198,310
Total revenues	202,241			206,860

Cost of products sold	149,853			164,414
Operating expenses	13,164			14,587
Selling, general and administrative expenses	2,945			2,517
Depreciation and amortization	5,325			4,998
	30,954			20,344
Other operating income (loss)	(27		)	2,086
Operating income	$	30,927		$	22,430

Sulfur (long tons)	861.8			998.7
Fertilizer (long tons)	238.7			201.2
Sulfur services volumes (long tons)	1,100.5			1,199.9

Revenues. Our total sulfur services revenues decreased $4.7 million, or 2%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. The decrease in product revenue was primarily a result of an 8% decrease in our volumes sold, offset by a 6% increase in average sales price.

Cost of products sold. Our cost of products sold decreased $14.5 million, or 9%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. The percentage decrease in sulfur services cost of products sold was higher than our percentage decrease in sulfur services revenues, resulting in an increase in our margin per ton of 40%. This decrease is also related to a decline in the market price of our sulfur products.

Operating expenses. Our operating expenses decreased $1.4 million, or 10%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. This decrease was a result of decreased outside towing expenses of $1.4 million.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.4 million, or 17%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. This increase is related to an increase of $0.2 million in overhead allocation expense and $0.2 million in compensation expense.

Depreciation and amortization. Depreciation and amortization expense increased $0.3 million, or 7%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. This increase is a result of capital expenditures made during the past twelve months.

Other operating income. Other operating income decreased $2.1 million for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. This decrease consists of a $1.4 million received for the termination of a rail services agreement and $0.7 million for business interruption insurance recoveries from Hurricane Ike both occurring in 2011.

In summary, our sulfur services operating income increased $8.5 million, or 38%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Marine Transportation Segment

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



	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	65,912	$	63,201
Operating expenses	52,773		50,831
Selling, general and administrative expenses	1,366		2,213
Depreciation and amortization	8,526		9,976
	3,247		181
Other operating income	—		309
Operating income	$	3,247	$	490

Revenues. Our marine transportation revenues increased $2.7 million, or 4%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. This increase was primarily a result of an increase in our offshore marine operations, offset by a decrease in our inland marine operations. Our offshore revenues increased $5.6 million primarily due to increased utilization of the offshore fleet in 2012 of $4.5 million due to increased demand for our two offshore tows which operate in the spot market and an increase in ancillary charges of $1.1 million. Our inland marine operations decreased $2.9 million, of which $3.2 million is attributed to decreased utilization of the inland fleet offset by $0.3 million in increased ancillary charges, primarily related to fuel.

Operating expenses. Operating expenses increased $1.9 million, or 4%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. This increase in operating costs is primarily due to an increase in fuel expense of $1.9 million, increased compensation expense of $0.9 million, and increased assist tug expense of $0.3 million. These increases were offset by a decrease in outside towing expense of $1.3 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.8 million, or 38%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. This decrease was primarily related to a decrease in expense related to an uncollectible customer receivable.

Depreciation and amortization. Depreciation and amortization decreased $1.5 million, or 15%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011. This decrease was primarily a result of disposal of equipment made in the last twelve months offset by capital expenditures made in the last twelve months.

In summary, our marine transportation operating income increased $2.8 million for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Equity in Earnings of Unconsolidated Entities

For the three and nine months ended September 30, 2012, equity in earnings of unconsolidated entities relates to our unconsolidated interests in Redbird, Caliber Gathering System, LLC, and Pecos Valley Producer Services LLC. For the three and nine months ended September 30, 2011, equity in earnings of unconsolidated entities relates to our unconsolidated interest in Redbird.

Equity in earnings (loss) of unconsolidated entities remained consistent for the three months ended September 30, 2012 and 2011.

Equity in earnings (loss) of unconsolidated entities was $(0.5) million for the nine months ended September 30, 2012 compared to $0.1 million for the nine months ended September 30, 2011, a decrease of $0.6 million. This decrease is primarily related to Redbird’s share of a base gas liability adjustment during second quarter 2012.

Interest Expense

Our interest expense for all operations was $6.3 million for the three months ended September 30, 2012, compared to $4.3 million for the three months ended September 30, 2011, an increase of $2.0 million, or 46%. This increase was primarily due to fees received related to the termination of all our interest rate swaps of $2.8 million during third quarter 2011.

Our interest expense for all operations was $21.7 million for the nine months ended September 30, 2012, compared to $17.1 million for the nine months ended September 30, 2011, an increase of $4.6 million, or 27%. This increase was primarily due to fees received related to the termination of all our interest rate swaps of $2.8 million during third quarter 2011 and decreases in interest expense related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps.

In conjunction with the redemption of our senior notes, we incurred a debt prepayment premium in the amount of $2.2 million for the nine months ended September 30, 2012.

Indirect Selling, General and Administrative Expenses

Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocating these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

Indirect selling, general and administrative expenses were $1.6 million for the three months ended September 30, 2012 compared to $1.0 million for the three months ended September 30, 2011, an increase of $0.6 million, or 60% primarily due to an increase in allocated overhead expenses from Martin Resource Management. Indirect selling, general and administrative expenses were $4.9 million for the nine months ended September 30, 2012 compared to $3.1 million for the nine months ended September 30, 2011, an increase of $1.8 million, or 58% primarily due to an increase in allocated overhead expenses from Martin Resource Management.

Liquidity and Capital Resources

General

Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private. During 2012 and 2011, we completed several transactions that have improved our liquidity position. In July 2012, we completed the sale of certain gas gathering and processing assets for approximately $273.3 million. In January 2012, we received net proceeds of $91.4 million from a public offering of common units. In February 2011, we received net proceeds of $70.3 million from a public offering of common units. Additionally, we made certain strategic amendments to our credit facility which provides for a maximum borrowing capacity of $400 million under our revolving credit facility.

As a result of these financing activities, discussed in further detail below, management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances and our current borrowing capacity under the expanded revolving credit facility. However, it may be necessary to raise additional funds to finance our future capital requirements.

Our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012, as well as our updated risk factors contained in “Item 1A. Risk Factors” set forth elsewhere herein, for a discussion of such risks.

Debt Financing Activities

On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility.

On May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million.

On December 5, 2011, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $350.0 million to $375.0 million.

On September 7, 2011, we amended our revolving credit facility to (1) increase the maximum amount of investments made in permitted joint ventures to $50.0 million, and (2) increase the maximum amount of investments made in Redbird and Cardinal to $120.0 million.

On April 15, 2011, we amended our credit facility to (i) increase the maximum amount of borrowings and letters of credit under the Credit Agreement from $275.0 million to $350.0 million, (ii) extend the maturity date of all amounts outstanding under the Credit Agreement from March 15, 2013 to April 15, 2016, (iii) decrease the applicable interest rate margin on committed revolver loans under the Credit Agreement as described in more detail below, (iv) adjust the financial covenants as described in more detail below, (v) increase the maximum allowable amount of additional outstanding indebtedness of the borrower and the Partnership and certain of its subsidiaries as described in more detail below, and (vi) adjust the commitment fee incurred on the unused portion of the loan facility as described in more detail below.

Equity Offerings

On January 25, 2012, we completed a public offering of 2,645,000 common units at a price of $36.15 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 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91.4 million. Our general partner contributed $2.0 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. On January 25, 2012, all of the net proceeds were used to reduce our outstanding indebtedness.

On February 9, 2011, we completed a public offering of 1,874,500 common units at a price of $39.35 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 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70.3 million. Our general partner contributed $1.5 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. On February 9, 2011, we made a $65.0 million payment to reduce the outstanding balance under our revolving credit facility.

Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2013.

Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012, as well as our updated risk factors contained in “Item 1A. Risk Factors” set forth elsewhere herein, for a discussion of such risks.

Cash Flows and Capital Expenditures

For the nine months ended September 30, 2012, cash decreased $0.2 million as a result of $18.0 million used in operating activities ($18.1 million used in continuing operating activities and $0.1 million provided by discontinued operating activities), $187.7 million provided by investing activities ($83.5 million used in continuing investing activities and $271.2 million provided by discontinued investing activities) and $170.0 million used in financing activities. For the nine months ended September 30, 2011, cash decreased $11.1 million as a result of $57.8 million provided by operating activities ($45.6 million from continuing operating activities and $12.3 million provided by discontinued operating activities), $135.3 million used in investing activities ($127.0 million used in continuing investing activities and $8.3 million used in discontinued investing activities), and $66.4 million provided by financing activities.

For the nine months ended September 30, 2012, our cash flows used in continuing investing activities of $83.5 million consisted of capital expenditures, payments for plant turnaround costs, return of investments from unconsolidated entities, contributions to unconsolidated entities, proceeds from the sale of equity method investment, and proceeds from the sale of property, plant, and equipment. For the nine months ended September 30, 2012, our cash flows provided by discontinued investing activities of $271.2 million consisted of proceeds from the sale of the Prism Assets, capital expenditures, return of investments from unconsolidated entities and contributions to unconsolidated entities. For the nine months ended September 30, 2011, our cash flows used in continuing investing activities of $127.0 million consisted of capital expenditures, payments for turnaround costs, investments in other long-term assets, return of investments from unconsolidated entities and contributions to unconsolidated entities. For the nine months ended September 30, 2011, our cash flows used in discontinued investing activities of $8.3 million consisted of capital expenditures, return of investments from unconsolidated entities and contributions to unconsolidated entities.

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


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


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

For the nine months ended September 30, 2012 and 2011, our capital expenditures for property and equipment in continuing investing activities were $63.0 million and $48.8 million, respectively. For the nine months ended September 30, 2012 and 2011, our capital expenditures for property and equipment in discontinued investing activities were $1.1 million and $0.9 million, respectively.

As to each period:

•

For the nine months ended September 30, 2012, we spent $59.4 million for expansion capital expenditures and $3.6 million for maintenance capital expenditures related to continuing operations. Our expansion capital expenditures were made in connection with construction projects associated with our terminalling and sulfur services segments. Our maintenance capital expenditures were primarily made in our sulfur services segment for routine improvements on the facilities as well as marine transportation segment dry dockings of our vessels pursuant to the United States Coast Guard requirements. For the nine months ended September 30, 2012, we spent $0.6 million for expansion capital expenditures and $0.5 million for maintenance capital expenditures related to discontinued investing activities.

•

For the nine months ended September 30, 2011, we spent $39.4 million for expansion capital expenditures and $9.4 million for maintenance capital expenditures related to continuing operations. Our expansion capital expenditures were made in connection with construction projects associated with our terminalling and sulfur services segments. Our maintenance capital expenditures were primarily made in our sulfur services segment for routine improvements on the facilities as well as marine transportation segment dry dockings of our vessels pursuant to the United States Coast Guard requirements. For the nine months ended September 30, 2011, we spent $0.2 million for expansion capital expenditures and $0.7 million for maintenance capital expenditures related to discontinued investing activities.

For the nine months ended September 30, 2012, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $58.3 million, payments of long term debt to financial lenders of $547.0 million, payments of notes payable and capital lease obligations of $6.5 million, borrowings of long-term debt under our credit facility of $349.0 million, payments of debt issuance costs of $0.2 million, proceeds from a public offering of $91.4 million, purchase of treasury stock of $0.2 million and general partner contributions of $1.9 million.

For the nine months ended September 30, 2011, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $48.0 million, payments of long-term debt to financial lenders of $389.0 million, payments of notes payable and capital lease obligations of $0.8 million, borrowings of long-term debt under our credit facility of $456.0 million, excess purchase price over carrying value of acquired assets of $19.7 million, payments of debt issuance

costs of $3.4 million, proceeds from a public offering of $70.3 million, purchase of treasury stock of $0.6 million and general partner contributions of $1.5 million.

With respect to continuing investing activities, we made contributions to unconsolidated entities for operations of $22.8 million and $1.0 million during the nine months ended September 30, 2012 and 2011, respectively. We made initial investments in unconsolidated entities of $0.8 million and $59.3 million during the nine months ended September 30, 2012 and 2011, respectively. Additionally, we received distributions from unconsolidated entities of $5.1 million and $0.4 million during the nine months ended September 30, 2012 and 2011, respectively.

With respect to discontinued investing activities, we made contributions to unconsolidated entities for operations of $3.1 million and $8.7 million during the nine months ended September 30, 2012 and 2011, respectively. Additionally, we received distributions from unconsolidated entities of $0.4 million and $1.3 million during the nine months ended September 30, 2012 and 2011, respectively.

The net investment in unconsolidated entities includes $3.1 million and $7.1 million of expansion capital expenditures in the nine months ended September 30, 2012 and 2011, respectively.

With respect to discontinued operating activities, we received distributions in-kind from unconsolidated entities of $6.4 million and $9.0 million during the nine months ended September 30, 2012 and 2011, respectively.

Capital Resources

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

As of September 30, 2012, we had $256.2 million of outstanding indebtedness, consisting of outstanding borrowings of $173.3 million (net of unamortized discount) under our Senior Notes, $77.0 million under our revolving credit facility, and $5.9 million under capital lease obligations.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2012, is as follows (dollars in thousands):



	Payments due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Revolving credit facility	$	77,000	$	—	$	—	$	77,000	$	—
Senior unsecured notes	173,312		—		—		—		173,312
Capital leases including current maturities	5,873		217		608		5,048		—
Non-competition agreements	100		50		50		—		—
Throughput commitment	49,938		4,384		9,981		10,632		24,941
Operating leases	47,201		9,979		24,103		7,379		5,740
Interest expense: ¹
Revolving credit facility	10,126		2,863		5,726		1,537		—
Senior unsecured notes	86,715		15,531		31,062		31,062		9,060
Capital leases	3,346		921		1,713		712		—
Total contractual cash obligations	$	453,611	$	33,945	$	73,243	$	133,370	$	213,053

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

Letter of Credit. At September 30, 2012, we had outstanding irrevocable letters of credit in the amount of $0.1 million, which were issued under our revolving credit facility.

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

Description of Our Long-Term Debt

Senior Notes

We and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of us (collectively, the “Issuers”), entered into (i) a Purchase Agreement, dated as of March 23, 2010 (the “Purchase Agreement”), by and among the Issuers, certain subsidiary guarantors (the “Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets Corporation and UBS Securities LLC, as representatives of a group of initial purchasers (collectively, the “Initial Purchasers”), (ii) an Indenture, dated as of March 26, 2010 (the “Indenture”), among the Issuers, the Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”) and (iii) a Registration Rights Agreement, dated as of March 26, 2010 (the “Registration Rights Agreement”), among the Issuers, the Guarantors and the Initial Purchasers, in connection with a private placement to eligible purchasers of $200 million in aggregate principal amount of the Issuers’ 8.875% senior unsecured notes due 2018 (the “Senior Notes”). We completed the aforementioned Senior Notes offering on March 26, 2010 and received proceeds of approximately $197.2 million, after deducting initial purchaser discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility.

In connection with the issuance of the Senior Notes, all “non-issuer” wholly-owned subsidiaries issued full, irrevocable, and unconditional guarantees of the Senior Notes. We do not provide separate financial statements of the operating partnership because it has no independent assets or operations, the guarantees are full and unconditional, and our other subsidiary is minor.

Indenture

Interest and Maturity. On March 26, 2010, the Issuers issued the Senior Notes pursuant to the Indenture in a transaction exempt from registration requirements under the Securities Act. The Senior Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Senior Notes will mature on April 1, 2018. The interest payment dates are April 1 and October 1.

Optional Redemption. Prior to April 1, 2013, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the Senior Notes issued under the Indenture at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the Senior Notes with the proceeds of certain equity offerings. Prior to April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on April 1, 2014, 102.219% for the 12-month period beginning on April 1, 2015 and 100.00% for the 12-month period beginning on April 1, 2016, and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Senior Notes.

On April 24, 2012 we notified the Trustee of our intention to exercise a partial redemption of the our Senior Notes pursuant to the Indenture. On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility.

Certain Covenants. The Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in its subsidiaries; (ii) pay distributions on, redeem or repurchase its units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate.

Events of Default. The Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the Senior Notes; (ii) default in payment when due of the principal of, or premium, if any, on the Senior Notes; (iii) our failure to comply with certain covenants relating to asset sales, repurchases of the Senior Notes upon a change of control and mergers or consolidations; (iv) our failure, for 180 days after notice, to comply with its reporting

obligations under the Securities Exchange Act of 1934; (v) our failure, for 60 days after notice, to comply with any of the other agreements in the Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by us or any of our restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20 million or more, subject to a cure provision; (vii) our or any of our restricted subsidiaries failure to pay final judgments aggregating in excess of $20 million, which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a continuing Event of Default, the Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding Senior Notes, by notice to the Issuers and the Trustee, may declare the Senior Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the Senior Notes to become due and payable.

Registration Rights Agreement. Under the Registration Rights Agreement, the Issuers and the Guarantors filed with the SEC a registration statement to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. We exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018.

Credit Facility

On November 10, 2005, we entered into a $225.0 million multi-bank credit facility, which has subsequently been amended, including most recently on September 7, 2011, when we amended our credit facility to, (1) increase the maximum amount of investments made in permitted joint ventures to $50.0 million, and (2) increase the maximum amount of investments made in Redbird and Cardinal to $120.0 million. Effective May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million.

As of September 30, 2012, we had approximately $77.0 million outstanding under the revolving credit facility and $0.1 million of letters of credit issued, leaving approximately $322.9 million available under our credit facility for future revolving credit borrowings and letters of credit.

The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. During the current fiscal year, draws on our credit facility have ranged from a low of $35.0 million to a high of $309.0 million.

The credit facility is guaranteed by substantially all of our subsidiaries. Obligations under the credit facility are secured by first priority liens on substantially all of our assets and those of the guarantors, including, without limitation, inventory, accounts receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our subsidiaries and certain of our equity method investees.

We may prepay all amounts outstanding under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, equity issuances and debt incurrences. We used the proceeds from our disposition of the Prism Assets to pay down outstanding indebtedness.

Indebtedness under the credit facility bears interest, at our option, at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee on all letters of credit issued under the credit facility, and we pay a commitment fee which ranges from 0.375% to 0.50% per annum on the unused revolving credit availability under the credit facility. The letter of credit fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the new credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:



Leverage Ratio	Base Rate Loans		Eurodollar Rate Loans		Letters of Credit
Less than 2.25 to 1.00	1.00	%	2.00	%	2.00	%
Greater than or equal to 2.25 to 1.00 and less than 3.00 to 1.00	1.25	%	2.25	%	2.25	%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00	1.50	%	2.50	%	2.50	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00	1.75	%	2.75	%	2.75	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00	2.00	%	3.00	%	3.00	%
Greater than or equal to 4.50 to 1.00	2.25	%	3.25	%	3.25	%

The applicable margin for existing LIBOR borrowings is 3.00%. Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%. Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.

The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio is 5.00 to 1.00. The maximum permitted senior leverage ratio (as defined in the new credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.25 to 1.00. The minimum consolidated interest coverage ratio (as defined in the new credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.75 to 1.00.

In addition, the credit facility contains various covenants that, among other restrictions, limit our and our subsidiaries’ ability to:


•	grant or assume liens;


•	make investments (including investments in our joint ventures) and acquisitions;


•	enter into certain types of hedging agreements;


•	incur or assume indebtedness;


•	sell, transfer, assign or convey assets;


•	repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us to make quarterly distributions to unitholders so long as no default or event of default exists under the credit facility;


•	change the nature of our business;


•	engage in transactions with affiliates;


•	enter into certain burdensome agreements;


•	make certain amendments to the omnibus agreement and our material agreements;


•	make capital expenditures; and


•	permit our joint ventures to incur indebtedness or grant certain liens.

Each of the following will be an event of default under the credit facility:


•	failure to pay any principal, interest, fees, expenses or other amounts when due;


•	failure to meet the quarterly financial covenants;


•	failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan document, subject to cure periods for certain failures;


•	the failure of any representation or warranty to be materially true and correct when made;


•	our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount;


•	bankruptcy or other insolvency events involving us or any of our subsidiaries;


•	judgments against us or any of our subsidiaries, in excess of a threshold amount;


•	certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount;


•	a change in control (as defined in the credit facility);


•	the termination of any material agreement or certain other events with respect to material agreements;


•	the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral; and


•	any of our joint ventures incurs debt or liens in excess of a threshold amount.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, or if Ruben Martin is not the chief executive officer of our general partner and a successor acceptable to the administrative agent and lenders providing more than 50% of the commitments under our credit facility is not appointed, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, either a bankruptcy event with respect to Martin Resource Management or a judgment with respect to Martin Resource Management could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us.

If an event of default relating to bankruptcy or other insolvency events occurs with respect to us or any of our subsidiaries, all indebtedness under our credit facility will immediately become due and payable. If any other event of default exists under our credit facility, the lenders may terminate their commitments to lend us money, accelerate the maturity of the indebtedness outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral. Any event of default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations as well as our ability to make distributions to unitholders.

If any default occurs under our credit facility, or if we are unable to make any of the representations and warranties in the credit facility, we will be unable to borrow funds or have letters of credit issued under our credit facility.

As of November 5, 2012, our outstanding indebtedness includes $355.0 million under our credit facility.

We are subject to interest rate risk on our credit facility and may enter into interest rate swaps to reduce this risk.

Effective September 2010, we entered into an interest rate swap that swapped $40 million of fixed rate to floating rate. The floating rate cost is the applicable three-month LIBOR rate. This interest rate swap was not accounted for using hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.

Effective September 2010, we entered into an interest rate swap that swapped $60 million of fixed rate to floating rate. The floating rate cost is the applicable three-month LIBOR rate. This interest rate swap was not accounted for using hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.

Seasonality

A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season. The demand for fertilizers is strongest during the early spring planting season. However, our terminalling and

storage and marine transportation businesses and the molten sulfur business are typically not impacted by seasonal fluctuations. We expect to derive a majority of our net income from our terminalling and storage, sulfur and marine transportation businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our terminalling and storage and marine transportation businesses.

Impact of Inflation

Inflation did not have a material impact on our results of operations for the three and nine months ended September 30, 2012 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the three and nine months ended September 30, 2012 or 2011.

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Item 3.	Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 3.35% as of September 30, 2012. As of November 5, 2012, we had total indebtedness outstanding under our credit facility of $355.0 million, all of which was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on September 30, 2012, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $3.6 million annually.

We are not exposed to changes in interest rates with respect to our Senior Notes as these obligations are fixed rate. The estimated fair value of the Senior Notes was approximately $189.6 million as of September 30, 2012, based on market prices of similar debt at September 30, 2012. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately an $5.8 million decrease in fair value of our long-term debt at September 30, 2012.

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Item 4.	Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective, as of the end of the period covered by this report, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There were no changes in our internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II - OTHER INFORMATION



Item 1.	Legal Proceedings

From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. Information regarding legal proceedings is set forth in Note 14 in Part I of this Form 10-Q and in Item 5 below.



Item 1A.	Risk Factors

There have been no material changes to the risk factors disclosed in our annual report on Form 10-K filed with the SEC on March 5, 2012.



Item 5.	Other Information

Certain Other Information. On October 2, 2012, we announced that the ongoing litigation and disputes involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all of the lawsuits and disputes referenced in Note 14 and below. Accordingly, none of the following matters are currently pending and such information is being provided for reference only. In connection with the settlement, Martin Resource Management transferred 1,500,000 of our common units to KCM, LLC.

Litigation Settlement. On October 2, 2012, the Partnership announced that the ongoing litigation and disputes as described in Note 14 and below involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all of the lawsuits and disputes referenced in this section. Accordingly, none of the following matters are currently pending and the information provided in Note 14 and below is for reference only.

On May 2, 2008, we received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management. In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment adverse to the Defendant which contained monetary damages and specific performance components (the “Judgment”). The Defendant appealed the Judgment. On November 3, 2010, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment. The Appellate Court’s opinion rendered a take-nothing judgment against the Plaintiff and found in favor of the Defendant. The Supreme Court of Texas denied the Plaintiff’s petition for review and therefore the opinion of the Sixth Appellate District of Texas at Texarkana has become final.

On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court (the “Harris County Litigation”) against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of our general partner. We are not a party to this lawsuit, and it does not assert any claims (i) against us, (ii) concerning our governance or operations, or (iii) against the MRMC Director Defendants or other MRMC Defendants with respect to their service to us.

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their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The case was abated in July 2009 during the pendency of a mandamus proceeding in the Texas Supreme Court. The Supreme Court denied mandamus relief on November 20, 2009. This lawsuit was amended to add the ESOT as a party and was subsequently removed to Federal Court by the ESOT. This lawsuit was remanded from Federal Court to the State District Court. The trial was previously set for August 2012 but has been removed from the trial docket. The trial is nonetheless stayed pending the outcome of procedural matters pending in the appellate courts.

The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against Scott Martin, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that he has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached fiduciary duties owed to Angela Jones Alexander, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, we have been informed that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above, Angela Jones Alexander amended her claims to include her grandmother, Margaret Martin, as a defendant, but subsequently dropped her claims against Mrs. Martin. Additionally, all claims pertaining to Karen Yost have been resolved. All claims pertaining to Defendant have been preliminarily resolved, as the court, on February 9, 2011, issued an order that granted the parties’ Joint Motion for Administrative Closure. With respect to the lawsuit referenced in (i) above, the case was tried in October 2009 and the jury returned a verdict in favor of the Defendant’s daughters against Scott Martin in the amount of $4,900. On December 22, 2009, the court entered a judgment, reflecting an amount consistent with the verdict and additionally awarded attorneys’ fees and interest. On January 7, 2010, the court modified its original judgment and awarded the Defendant’s daughters approximately $2,700 in damages and attorneys’ fees, plus interest. Scott Martin has appealed the judgment. On March 20, 2012, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment. While the Appellate Court found that there was sufficient evidence to support the jury’s finding that a breach of fiduciary duty occurred, it found insufficient evidence to support any damages and therefore rendered a take-nothing judgment against the daughters of the Defendant. A motion for rehearing at the Appellate Court was overruled on April 26, 2012. The Defendant’s daughters have indicated they will appeal the Appellate Court’s ruling.

On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which the board of directors of Martin Resource Management determined was detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of our general partner. The position on the board of directors of the Partnership’s general partner vacated by the Plaintiff may be filled in accordance with the existing procedures for replacement of a departing director utilizing the Nominations Committee of the board of directors of the general partner of the Partnership. This position on the board of directors has been filled as of July 26, 2010, by Charles Henry “Hank” Still.

On May 4, 2010, we received a copy of a petition filed in a new case with the District Clerk of Gregg County, Texas by Martin Resource Management against the Plaintiff and others with respect to certain matters relating to Martin Resource Management (“the “Gregg County Matter”). As noted above, the Plaintiff was a former director of Martin Resource Management. The lawsuit alleges that the Plaintiff with help from others breached the fiduciary duties the Plaintiff owed to Martin Resource Management. We are not a party to the lawsuit, and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning our governance or operations, or (iii) against the Plaintiff with respect to his service as an officer or former director of the general partner of the Partnership. With respect to this lawsuit, the case was tried in January 2012 and the jury returned a verdict in favor of Martin Resource Management against Scott D. Martin for breach of fiduciary duty and

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awarded an amount of $1,800. The court entered a judgment in favor or Martin Resource Management in the amount awarded by the jury plus interest. Scott D. Martin is appealing this judgment.

On June 22, 2012, we received from Scott D. Martin a demand that we indemnify him for legal fees and damages adjudged against him in the Gregg County Matter. He followed this up with an additional demand that we indemnify him for legal fees and expenses he paid in defending the lawsuit brought in Gregg County, Texas by the daughters of the Defendant. On June 25, 2012, we filed a petition in the District Court of Gregg County, Texas against Scott D. Martin, seeking a declaratory judgment regarding the Partnership’s obligations to indemnify Scott D. Martin.



Item 6.	Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.

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SIGNATURES

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



	Martin Midstream Partners L.P.

	By:	Martin Midstream GP LLC
		It’s General Partner

Date: November 5, 2012		By:	/s/ Ruben S. Martin
			Ruben S. Martin
			President and Chief Executive Officer

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INDEX TO EXHIBITS



Exhibit Number	Exhibit Name

3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.2	Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 25, 2009 (filed as Exhibit 10.1 to the Partnership’s Amendment to Current Report on Form 8-K/A, filed January 19, 2010, and incorporated herein by reference).
3.3	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed February 1, 2011, and incorporated herein by reference).
3.4	Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
3.5	Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.6	Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
3.7	Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.8	Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 33-91706), filed July 1, 2002, and incorporated herein by reference).
3.9	Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.1	Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
4.1	Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
4.2	Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
4.3	Indenture, dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed March 26, 2010, and incorporated herein by reference).
4.4	Registration Rights Agreement, dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 4.2 to the Partnership’s Current Report on Form 8-K, filed March 26, 2010, and incorporated herein by reference).
10.1	Commitment Increase and Joinder Agreement dated May 10, 2012 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 10, 2012 and incorporated herein by reference).
10.2	Membership Interests Purchase Agreement dated October 2, 2012 by and among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Martin Underground Storage, Inc. and Martin Resource Management Corporation (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
10.3	Purchase Price Reimbursement Agreement dated October 2, 2012 by Martin Resource Management Corporation to and for the benefit of Martin Operating Partnership L.P. (filed as Exhibit 10.2 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
10.4	Asset Purchase Agreement, dated October 2, 2012, by and among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Cross Oil Refining & Marketing, Inc. and Martin Resource Management Corporation (filed as Exhibit 10.3 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
10.5	Amendment No. 2 to Omnibus Agreement dated October 1, 2012, by Martin Resource Management Corporation, Martin Midstream GP, LLC, Martin Midstream Partners L.P., and Martin Operating Partnership L.P. (filed as Exhibit 10.4 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).

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10.6*	Second Amended and Restated LLC Agreement of Redbird Gas Storage LLC, dated as of October 2, 2012.
10.7*	Supply Agreement dated as of October 2, 2012 by and between the Partnership and Cross Oil & Refining Marketing Inc.
10.8*	Noncompetition Agreement dated as of October 2, 2012 by and among the Partnership, Cross Oil Refining & Marketing Inc., and Martin Resource Management Corporation.
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2012, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; (5) the Consolidated Statements of Other Comprehensive Income; and (6) the Notes to Consolidated Financial Statements.

* Filed or furnished herewith