Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

2013.9.30 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, 2013



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 4, 2013, was 26,625,026.



		Page

PART I – FINANCIAL INFORMATION		2

Item 1. Financial Statements		2
	Consolidated and Condensed Balance Sheets as of September 30, 2013 (unaudited) and December 31, 2012 (audited)	2
	Consolidated and Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012 (unaudited)	3
	Consolidated and Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012 (unaudited)	6
	Consolidated and Condensed Statements of Capital for the Nine Months Ended September 30, 2013 and 2012 (unaudited)	7
	Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012 (unaudited)	8
	Notes to Consolidated and Condensed Financial Statements	9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32

Item 3. Quantitative and Qualitative Disclosures about Market Risk		58

Item 4. Controls and Procedures		59

PART II. OTHER INFORMATION		60

Item 1. Legal Proceedings		60

Item 1A. Risk Factors		60

Item 6. Exhibits		60

PART I – FINANCIAL INFORMATION



Item 1.	Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)



	September 30, 2013			December 31, 2012
	(Unaudited)			(Audited)
Assets
Cash	$	45		$	5,162
Accounts and other receivables, less allowance for doubtful accounts of $2,864 and $2,805, respectively	147,609			190,652
Product exchange receivables	3,635			3,416
Inventories	106,783			95,987
Due from affiliates	18,531			13,343
Other current assets	9,141			2,777
Assets held for sale	750			3,578
Total current assets	286,494			314,915

Property, plant and equipment, at cost	900,175			767,344
Accumulated depreciation	(291,638		)	(256,963		)
Property, plant and equipment, net	608,537			510,381

Goodwill	19,616			19,616
Investment in unconsolidated entities	181,586			154,309
Debt issuance costs, net	16,469			10,244
Other assets, net	7,500			3,531
	$	1,120,202		$	1,012,996

Liabilities and Partners’ Capital
Current installments of long-term debt and capital lease obligations	$	3,173		$	3,206
Trade and other accounts payable	110,617			140,045
Product exchange payables	13,123			12,187
Due to affiliates	2,791			3,316
Income taxes payable	1,121			10,239
Other accrued liabilities	18,331			9,489
Total current liabilities	149,156			178,482

Long-term debt and capital lease obligations, less current installments	648,004			474,992
Other long-term obligations	2,236			1,560
Total liabilities	799,396			655,034

Partners’ capital	320,806			357,962
Commitments and contingencies
	$	1,120,202		$	1,012,996

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,
	2013			2012¹			2013			2012¹
Revenues:
Terminalling and storage *	$	28,956		$	23,875		$	85,267		$	65,107
Marine transportation *	24,217			22,102			74,694			63,678
Sulfur services	3,001			2,926			9,003			8,777
Product sales: *
Natural gas services	204,296			190,738			650,605			527,666
Sulfur services	39,096			57,670			164,375			193,464
Terminalling and storage	60,050			56,779			167,546			177,570
	303,442			305,187			982,526			898,700
Total revenues	359,616			354,090			1,151,490			1,036,262

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	196,308			185,686			626,609			515,928
Sulfur services *	33,994			47,272			131,577			149,582
Terminalling and storage *	52,718			52,161			146,806			160,271
	283,020			285,119			904,992			825,781
Expenses:
Operating expenses *	43,444			36,654			129,839			108,108
Selling, general and administrative *	7,211			5,774			20,624			17,184
Depreciation and amortization	13,698			10,292			37,944			30,315
Total costs and expenses	347,373			337,839			1,093,399			981,388

Other operating income	—			(5		)	796			368
Operating income	12,243			16,246			58,887			55,242

Other income (expense):
Equity in earnings (loss) of unconsolidated entities	(577		)	(775		)	(878		)	256
Interest expense	(11,060		)	(6,789		)	(31,058		)	(23,284		)
Debt prepayment premium	—			—			—			(2,470		)
Other, net	(111		)	505			(134		)	1,054
Total other expense	(11,748		)	(7,059		)	(32,070		)	(24,444		)

Net income before taxes	495			9,187			26,817			30,798
Income tax expense	(303		)	(541		)	(910		)	(3,366		)
Income from continuing operations	192			8,646			25,907			27,432
Income from discontinued operations, net of income taxes	—			63,603			—			67,312
Net income	192			72,249			25,907			94,744
Less general partner's interest in net income	(4		)	(1,448		)	(518		)	(4,603		)
Less pre-acquisition income allocated to Parent	—			152			—			(4,622		)
Less income allocable to unvested restricted units	(1		)	—			(67		)	—
Limited partners' interest in net income	$	187		$	70,953		$	25,322		$	85,519

See accompanying notes to consolidated and condensed financial statements.

¹ Financial information for 2012 has been revised to include results attributable to the Redbird Class A interests and the Blending and Packaging Assets acquired from Cross prior to October 2, 2012. See Note 1 – General. The 2012 financial information also includes the effects of immaterial corrections made discussed in Note 18 - Prior Period Correction of an Immaterial Error.

*Related Party Transactions Shown Below

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,
	2013		2012¹		2013		2012¹
Revenues:
Terminalling and storage	$	18,044	$	18,531	$	52,857	$	48,611
Marine transportation	5,943		3,979		18,828		13,282
Product Sales	964		1,637		4,012		5,784
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	7,799		6,761		23,391		18,783
Sulfur services	4,539		4,111		13,514		12,512
Terminalling and storage	13,488		13,165		39,638		36,509
Expenses:
Operating expenses	17,902		14,100		53,410		42,308
Selling, general and administrative	4,356		2,764		12,944		8,258

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,
	2013		2012¹			2013		2012¹
Allocation of net income attributable to:
Limited partner interest:
Continuing operations	$	187	$	10,128		$	25,322	$	21,645
Discontinued operations	—		60,825			—		63,874
	$	187	$	70,953		$	25,322	$	85,519
General partner interest:
Continuing operations	$	4	$	(1,330	)	$	518	$	1,165
Discontinued operations	—		2,778			—		3,438
	$	4	$	1,448		$	518	$	4,603

Net income per unit attributable to limited partners:
Basic:
Continuing operations	$	0.01	$	0.44		$	0.95	$	0.94
Discontinued operations	—		2.63			—		2.79
	$	0.01	$	3.07		$	0.95	$	3.73
Weighted average limited partner units - basic	26,552		23,101			26,561		22,929
Diluted:
Continuing operations	$	0.01	$	0.44		$	0.95	$	0.94
Discontinued operations	—		2.63			—		2.79
	$	0.01	$	3.07		$	0.95	$	3.73
Weighted average limited partner units - diluted	26,579		23,105			26,581		22,932

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,
	2013		2012¹			2013		2012¹
Net income	$	192	$	72,249		$	25,907	$	94,744
Other comprehensive income adjustments:
Changes in fair values of commodity cash flow hedges	—		—			—		126
Commodity cash flow hedging losses reclassified to earnings	—		(63		)	—		(752		)
Other comprehensive income	—		(63		)	—		(626		)
Comprehensive income	$	192	$	72,186		$	25,907	$	94,118

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
	Parent Net Investment¹		Common Limited					General Partner			Accumulated Other Comprehensive Income
			Units		Amount			Amount			(Loss)			Total
Balances - January 1, 2012	$	51,571	20,471,776		$	279,562		$	5,428		$	626		$	337,187

Net income	4,622		—		85,519			4,603			—			94,744

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	$	56,193	23,116,776		$	403,720		$	6,530		$	—		$	466,443

Balances - January 1, 2013	$	—	26,566,776		$	349,490		$	8,472		$	—		$	357,962

Net income	—		—		25,389			518			—			25,907

Issuance of restricted units	—		63,750		—			—			—			—

Forfeiture of restricted units	—		(250	)	—			—			—			—

General partner contribution	—		—		—			37			—			37

Cash distributions	—		—		(61,902		)	(1,384		)	—			(63,286		)

Unit-based compensation	—		—		737			—			—			737

Excess purchase price over carrying value of acquired assets	—		—		(301		)	—			—			(301		)

Purchase of treasury units	—		(6,000	)	(250		)	—			—			(250		)

Balances - September 30, 2013	$	—	26,624,276		$	313,163		$	7,643		$	—		$	320,806

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,
	2013			2012¹
Cash flows from operating activities:
Net income	$	25,907		$	94,744
Less: Income from discontinued operations	—			(67,312		)
Net income from continuing operations	25,907			27,432
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	37,944			30,315
Amortization of deferred debt issuance costs	2,890			2,611
Amortization of debt discount	230			504
Deferred taxes	—			402
(Gain) loss on sale of property, plant and equipment	(796		)	7
Gain on sale of equity method investment	—			(486		)
Equity in (earnings) loss of unconsolidated entities	878			(256		)
Unit-based compensation	737			379
Preferred dividends on MET investment	1,171			—
Other	7			—
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	43,043			(10,352		)
Product exchange receivables	(219		)	12,190
Inventories	(8,362		)	(41,736		)
Due from affiliates	(5,188		)	(27,795		)
Other current assets	(6,358		)	1,996
Trade and other accounts payable	(29,641		)	(16,808		)
Product exchange payables	936			(9,405		)
Due to affiliates	(525		)	21,040
Income taxes payable	(440		)	154
Other accrued liabilities	8,842			1,353
Change in other non-current assets and liabilities	(210		)	(1,126		)
Net cash provided by (used in) continuing operating activities	70,846			(9,581		)
Net cash provided by (used in) discontinued operating activities	(8,678		)	120
Net cash provided by (used in) operating activities	62,168			(9,461		)
Cash flows from investing activities:
Payments for property, plant and equipment	(68,591		)	(71,550		)
Acquisitions	(73,921		)	—
Payments for plant turnaround costs	—			(2,578		)
Proceeds from sale of property, plant and equipment	4,719			33
Proceeds from sale of equity method investment	—			531
Investment in unconsolidated subsidiaries	—			(775		)
Milestone distributions from ECP	—			2,208
Return of investments from unconsolidated entities	1,551			5,133
Contributions to unconsolidated entities	(30,877		)	(22,786		)
Net cash used in continuing investing activities	(167,119		)	(89,784		)
Net cash provided by discontinued investing activities	—			271,181
Net cash provided by (used in) investing activities	(167,119		)	181,397
Cash flows from financing activities:
Payments of long-term debt	(518,000		)	(547,000		)
Payments of notes payable and capital lease obligations	(251		)	(6,522		)
Proceeds from long-term debt	691,000			349,000
Net proceeds from follow on offering	—			91,361
General partner contribution	37			1,951
Purchase of treasury units	(250		)	(221		)
Decrease in affiliate funding of investments in unconsolidated entities	—			(2,208		)
Payment of debt issuance costs	(9,115		)	(204		)
Excess purchase price over carrying value of acquired assets	(301		)	—
Cash distributions paid	(63,286		)	(58,332		)
Net cash provided by (used in) financing activities	99,834			(172,175		)
Net decrease in cash	(5,117		)	(239		)
Cash at beginning of period	5,162			266
Cash at end of period	$	45		$	27

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, 2013

(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 including the refining, blending, and packaging of finished lubricants; natural gas services, including liquids distribution services and natural gas storage; 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 (“U.S. GAAP”) for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by U.S. GAAP 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 financial position, results of operations, 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, 2012, filed with the Securities and Exchange Commission (the “SEC”) on March 4, 2013, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2012 filed on March 28, 2013.

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 and condensed financial statements in conformity with U.S. GAAP. Actual results could differ from those estimates.

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 owned by Prism Gas Systems I, L.P. (“Prism Gas”), a wholly-owned subsidiary of the Partnership. These assets, along with additional gathering and processing assets discussed in Note 4, are collectively referred to as the “Prism Assets.” The Partnership has retrospectively adjusted its prior period consolidated and condensed financial statements to comparably classify the amounts related to the operations and cash flows of the Prism Assets as discontinued operations.

On October 2, 2012, the Partnership, which owned 10.74% of the Class A interests and 100% of the Class B interests, acquired all of the remaining Class A interests in Redbird Gas Storage LLC (“Redbird”) from Martin Underground Storage, Inc., (“MUS”) a subsidiary of Martin Resource Management Corporation (“Martin Resource Management” or “Parent”). In 2011, the Partnership and Martin Resource Management formed Redbird, a natural gas storage joint venture to invest in Cardinal Gas Storage Partners LLC (“Cardinal”). Cardinal is a joint venture between Redbird and Energy Capital Partners (“ECP”) that is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi.

On October 2, 2012, the Partnership acquired from Cross Oil Refining and Marketing, Inc. (“Cross”), a wholly-owned subsidiary of Martin Resource Management, certain specialty lubricant product blending and packaging assets (“Blending and Packaging Assets”).

The acquisitions of the Redbird Class A interests and the Blending and Packaging Assets were considered a transfer of net assets between entities under common control. As a result, the acquisitions of the Redbird Class A interests and the Blending and Packaging Assets are recorded at amounts based on the historical carrying value of these assets at October 2, 2012, and the Partnership is required to update its historical financial statements to include the activities of the Redbird Class A interests and the Blending and Packaging Assets as of the date of common control. The Partnership’s accompanying historical financial statements have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the activities of the Redbird Class A interests and the Blending and Packaging Assets as if the Partnership owned these assets for the periods presented. Net income attributable to the Redbird Class A interests and the activities of the Blending and Packaging Assets for periods prior to the Partnership’s acquisition of the assets is not allocated to the general and limited partners for purposes of calculating net income per limited partner unit. See Note 11.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

On August 30, 2013, Martin Resource Management completed the sale of a 49% non-controlling voting interest (50% economic interest) in MMGP Holdings, LLC (“Holdings”), a newly-formed sole member of Martin Midstream GP LLC (“MMGP”), the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners (“Alinda”). Upon closing the transaction, Alinda appointed two representatives to serve as directors of the general partner.

Certain expense reclassifications were made to the Partnership's Consolidated and Condensed Statements of Operations for the three and nine months ended September 30, 2012 in order to conform to the current presentation.


(2)	New Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board (“FASB”) amended the provisions of Accounting Standards Codification (“ASC”) 220 related to accumulated other comprehensive income, which does not change the current requirements for reporting net income or other comprehensive income in financial statements. The standard requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. The entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This amended guidance was adopted by the Partnership effective January 1, 2013. As this new guidance only requires enhanced disclosure, adoption did not impact the Partnership's financial position or results of operations.


(3)	Acquisitions

Marine Transportation Equipment Purchase

On September 30, 2013, the Partnership acquired two inland tank barges from Martin Resource Management for $7,100. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The Partnership recorded $6,799 to property, plant and equipment in the Marine Transportation segment and the excess of the purchase price over the carrying value of the assets of $301 was recorded as an adjustment to partners' capital. This transaction was funded with borrowings under the Partnership's revolving credit facility.

Sulfur Production Facility

On August 5, 2013, the Partnership acquired a plant nutrient sulfur production facility in Cactus, Texas for $4,118. The transaction was accounted for under the acquisition method of accounting in accordance with ASC 805 relating to business combinations. This transaction was funded by borrowings under the Partnership's revolving credit facility. Assets acquired and liabilities assumed were recorded in the Sulfur Services segment at fair value as follows:



Inventory	$	162
Property, plant and equipment	4,000
Current liabilities	(44		)
Total	$	4,118

The Partnership's results of operations from these assets included revenues of $104 and a net loss of $80 for both the three and nine months ended September 30, 2013.

NL Grease, LLC

On June 13, 2013, the Partnership acquired certain assets of NL Grease, LLC (“NLG”) for $12,148. NLG is a Kansas City, Missouri based grease manufacturer that specializes in private-label packaging of commercial and industrial greases. The transaction was accounted for under the acquisition method of accounting in accordance with ASC 805 relating to business combinations. This transaction was funded by borrowings under the Partnership's revolving credit facility. The assets acquired by the Partnership were recorded in the Terminalling and Storage segment at fair value of $12,148 in the following purchase price allocation:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



Inventory and other current assets	$	1,513
Property, plant and equipment	6,136
Other assets	5,113
Other accrued liabilities	(168		)
Other long-term obligations	(446		)
Total	$	12,148

The purchase price allocation resulted in the recognition of $5,113 in definite-lived intangible assets with no residual value, including $2,418 of technology, $2,218 attributable to a customer list, and $477 attributable to a non-compete agreement. The amounts assigned to technology, the customer list, and the non-compete agreement are amortized over the estimated useful life of ten years, three years, and five years, respectively. The weighted average life over which these acquired intangibles will be amortized is approximately six years.

The Partnership completed the purchase price allocation during the third quarter of 2013, which resulted in an adjustment to working capital from the preliminary purchase price allocation in the amount of $55.

The Partnership's results of operations included revenues of $4,101 and net income of $166 for the three months ended September 30, 2013 and revenues of $4,622 and net income of $10 for the nine months ended September 30, 2013 related to the NLG acquisition.

NGL Marine Equipment Purchase

On February 28, 2013, the Partnership purchased from affiliates of Florida Marine Transporters, Inc. six liquefied petroleum gas pressure barges and two commercial push boats for approximately $50,801, of which the commercial push boats totaling $8,201 were allocated to property, plant and equipment in the Partnership's Marine Transportation segment and the six pressure barges totaling $42,600 were allocated to property, plant and equipment in the Partnership's Natural Gas Services segment. This transaction was funded with borrowings under the Partnership's revolving credit facility.

Talen's Marine & Fuel LLC

On December 31, 2012, the Partnership acquired all of the outstanding membership interests in Talen's Marine & Fuel LLC (“Talen's”) from QEP Marine Fuel Investment, LLC and QEP Marine Fuel Holdings, Inc. (collectively referred to as “Quintana Energy Partners”) for $103,368, subject to certain post-closing adjustments, including the assumption of a note payable in the amount of $2,971. The transaction was accounted for under the acquisition method of accounting in accordance with ASC 805 relating to business combinations. Additionally, as required by ASC 805, the Partnership expensed acquisition related costs, of which $58 were recorded in selling, general and administrative expenses for the nine months ended September 30, 2013. Through this acquisition, the Partnership acquired certain terminalling facilities and other terminalling related assets located along the Texas and Louisiana gulf coast. This transaction was funded by borrowings under the Partnership's revolving credit facility. Simultaneous with the acquisition, the Partnership sold certain working capital-related assets and a customer relationship intangible asset to Martin Energy Services LLC (“MES”), a wholly-owned subsidiary of Martin Resource Management for $56,000. Due to the Talen's acquisition, MES entered into various service agreements with Talen's pursuant to which the Partnership provides certain terminalling and marine services to MES. The excess carrying value of the assets over the purchase price paid by Martin Resource Management at the sales date was $4,268 and was recorded as an adjustment to partners' capital. The remaining net assets retained by the Partnership were recorded in the Terminalling and Storage segment at fair value of $43,100 in the following preliminary purchase price allocation:



Purchase price paid to acquire Talen's	$	103,368
Less proceeds received from Martin Resource Management for assets sold (described above)	(56,000		)
Less excess of carrying value of assets sold to Martin Resource Management over the purchase price paid by Martin Resource Management	(4,268		)
Total	$	43,100

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



Cash	$	5,096
Accounts and other receivables, net	2,682
Other current assets	1,547
Assets held for sale	3,578
Property, plant and equipment	23,838
Goodwill	11,279
Notes payable	(2,971		)
Current liabilities	(1,480		)
Other long-term obligations	(469		)
Total	$	43,100

Goodwill recognized from the acquisition primarily relates to the expected contributions of the entity to the overall corporate strategy in addition to synergies and acquired workforce, which are not separable from goodwill.

The Partnership's results of operations included revenues of $1,228 and net income of $153 for the three months ended September 30, 2013 and revenues of $3,900 and net income of $710 for the nine months ended September 30, 2013 related to the Talen's acquisition.

The Partnership has not obtained all of the information necessary to finalize the purchase price allocation. The final purchase price allocation is expected to be completed during 2013.

Lubricant Blending and Packaging Assets

On October 2, 2012, the Partnership purchased the Blending and Packaging Assets from Cross. The consideration consisted of $121,767 in cash at closing, plus a final net working capital adjustment of $907 paid in October of 2012. This transaction 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 the Blending and Packaging assets was recorded at the historical carrying value of the assets at the acquisition date, which were as follows:



Accounts and other receivables, net	$	20,599
Inventory	18,730
Other current assets	769
Property, plant and equipment, net	24,692
Current liabilities	(2,424		)
Total	$	62,366

The excess purchase price over the historical carrying value of the assets at the acquisition date was $60,308 and was recorded as an adjustment to partners' capital.

Redbird Class A Interests

On October 2, 2012, the Partnership acquired from MUS all of the remaining Class A interests in Redbird for $150,000 in cash. The Partnership began making Class A investments in Redbird during the fourth quarter of 2011. Prior to the transaction, the Partnership owned a 10.74% Class A interest and a 100% Class B interest in Redbird. This transaction 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 interests was recorded at the historical carrying value of the interests at the acquisition date. The Partnership recorded an investment in unconsolidated entities of $68,233 and the excess of the purchase price over the carrying value of the Class A interests of $81,767 was recorded as an adjustment to partners' capital.


(4)	Discontinued operations and divestitures

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

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 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 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 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 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			2012
Total revenues from third parties¹	$	9,269		$	66,842
Total costs and expenses, excluding depreciation and amortization	(9,296		)	(64,556		)
Depreciation and amortization	—			(2,320		)
Other operating income²	62,251			61,421
Equity in earnings of Waskom, Matagorda, and PIPE	377			4,611
Income from discontinued operations before income taxes	62,601			65,998
Income tax benefit	(1,002		)	(1,314		)
Income from discontinued operations, net of income taxes	$	63,603		$	67,312

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

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


(5)	Inventories

Components of inventories at September 30, 2013 and December 31, 2012 were as follows:



	September 30, 2013		December 31, 2012
Natural gas liquids	$	53,005	$	33,610
Sulfur	5,859		14,892
Sulfur based products	14,517		17,824
Lubricants	27,112		27,366
Other	6,290		2,295
	$	106,783	$	95,987


(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 in 2012. The equity in earnings associated with these investments during the period owned is recorded in income from discontinued operations for the three and nine months ended September 30, 2012.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

On May 1, 2008, certain assets and liabilities were contributed to acquire a 50% ownership interest in Cardinal. In conjunction with this transaction, ECP contributed cash for a 50% ownership interest in Cardinal.

The initial carrying amount of the investment in Cardinal was less than the contributed underlying net assets. Of the basis difference, $1,250 relates to differences in the carrying value of fixed assets contributed as compared to amounts recorded by Cardinal, and is being amortized over 40 years, the approximate useful life of the underlying assets. Such amortization amounted to $8 and $23 for each of the three and nine months ended September 30, 2013 and 2012, respectively. The remaining basis difference is a permanent difference that will be realized upon sale of the investment in Cardinal.

On May 24, 2011, Redbird was formed to hold membership interests in Cardinal. On May 27, 2011, initial contributions consisted of all of Martin Resource Management’s membership interests in Cardinal for 100% of the Class A interests in Redbird. Simultaneously, the Partnership acquired 100% of the Class B interests in Redbird for approximately $59,319. Concurrent with the closing of this transaction, Redbird contributed the cash to Cardinal which used the cash, along with a contribution from ECP, to acquire all of the outstanding equity interests in Monroe Gas Storage Company, LLC as well as an option on development rights to an adjacent depleted reservoir facility. As discussed in Note 3, on October 2, 2012, the Partnership, acquired the remaining Class A interests in Redbird from MUS. As this acquisition is considered a transfer of net assets between entities under common control, the acquisition is recorded at the historical carrying value of these assets at the acquisition date. The Partnership is required to retrospectively update its historical financial statements to include the activities of the Class A interests in Redbird as of the date of common control. The Partnership's accompanying historical financial statements for the three and nine months ended September 30, 2012 have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the Redbird Class A interests as if the Partnership owned these assets for these periods.

At September 30, 2013, Redbird owned an unconsolidated 42.21% interest in Cardinal. Redbird utilized the investments by the Partnership to invest in Cardinal to fund projects for natural gas storage facilities.

At September 30, 2013, the Partnership owned an unconsolidated 50% interest in Caliber Gathering, LLC (“Caliber”).

During March 2013, the Partnership acquired 100% of the preferred interests in Martin Energy Trading LLC (“MET”), a subsidiary of Martin Resource Management, for $15,000.

During the second quarter of 2012, the Partnership acquired an unconsolidated 50% interest in Pecos Valley Producer Services LLC (“Pecos Valley”). The Partnership sold its interest in Pecos Valley during the third quarter of 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, 2013		December 31, 2012
Redbird	$	166,514	$	153,749
MET	15,000		—
Caliber	72		560
Total investment in unconsolidated entities	$	181,586	$	154,309

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Equity in earnings of Waskom¹	$	—		$	287		$	—		$	4,172
Equity in earnings of PIPE¹	—			10			—			(60		)
Equity in earnings of Matagorda¹	—			80			—			499
Equity in earnings of discontinued operations	—			377			—			4,611
Equity in earnings of Redbird	(984		)	(709		)	(1,561		)	355
Equity in earnings of MET	577			—			1,171			—
Equity in earnings of Caliber	(170		)	(98		)	(488		)	(119		)
Equity in earnings of Pecos Valley	—			32			—			20
Equity in earnings of unconsolidated entities	(577		)	(775		)	(878		)	256
Total equity in earnings of unconsolidated entities	$	(577	)	$	(398	)	$	(878	)	$	4,867

¹ For the three and nine months ended September 30, 2012, the financial information for Waskom, Matagorda, and PIPE is included in the Consolidated and Condensed Statements of Operations and Cash Flows as discontinued operations.

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



	As of December 31,				Three Months Ended September 30,				Nine Months Ended September 30,
	Total Assets		Partners' Capital		Revenues		Net Income		Revenues		Net Income
2012
Waskom	$	—	$	—	$	8,171	$	668	$	66,662	$	8,986



	As of September 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	Total Assets		Partners' Capital		Revenues		Net Income			Revenues		Net Income
2013
Cardinal	$	802,068	$	473,076	$	17,341	$	(2,300	)	$	36,136	$	(2,241	)
	As of December 31,
2012
Cardinal	$	694,767	$	457,297	$	8,089	$	(272	)	$	25,156	$	(2,005	)

As of September 30, 2013 and December 31, 2012, the Partnership’s interest in cash of the unconsolidated equity-method investees was $8,448 and $1,265, 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.

(a) Commodity Derivative Instruments

The Partnership has from time to time used 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 potential commodity risk exposure. These hedging arrangements have been in the form of swaps for crude oil, natural gas and natural

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

gasoline. In addition, the Partnership has 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 during 2012, the Partnership terminated and settled all of its commodity derivative instruments during the second quarter of 2012. 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 (income from discontinued operations) and in accumulated other comprehensive income as a component of partners’ capital.

(b) Impact of Commodity Cash Flow Hedges

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

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

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

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

The Partnership is exposed to market risks associated with interest rates. From time to time, the Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt and term loan credit facilities.

Tabular Presentation of Gains and Losses on Derivative Instruments and Related Hedged Items



Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations For the Three Months Ended September 30, 2013 and 2012
					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
	2013		2012			2013		2012			2013		2012
Derivatives designated as hedging instruments:
Commodity contracts	$	—	$	—	Income from Discontinued Operations	$	—	$	63	Income from Discontinued Operations	$	—	$	—
Total derivatives designated as hedging instruments	$	—	$	—		$	—	$	63		$	—	$	—

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2013		2012
Derivatives not designated as hedging instruments:
Commodity contracts	Income from Discontinued Operations	$	—	$	(18	)
Total derivatives not designated as hedging instruments		$	—	$	(18	)



Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations For the Nine Months Ended September 30, 2013 and 2012
					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
	2013		2012			2013		2012			2013		2012
Derivatives designated as hedging instruments:
Commodity contracts	$	—	$	126	Income from Discontinued Operations	$	—	$	748	Income from Discontinued Operations	$	—	$	4
Total derivatives designated as hedging instruments	$	—	$	126		$	—	$	748		$	—	$	4



	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2013		2012
Derivatives not designated as hedging instruments:
Commodity contracts	Income from Discontinued Operations	$	—	$	1,623
Total derivatives not designated as hedging instruments		$	—	$	1,623


(8)	Fair Value Measurements

The Partnership follows the provisions of ASC 820 related to fair value measurements and disclosures, which established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of this guidance had no impact on the Partnership’s financial position or results of operations.

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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at September 30, 2013 and December 31, 2012:



	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	September 30, 2013		(Level 1)		(Level 2)		(Level 3)
Liabilities
2018 Senior unsecured notes	$	186,747	$	—	$	186,747	$	—
2021 Senior unsecured notes	254,928		—		254,928		—
Total liabilities	$	441,675	$	—	$	441,675	$	—



	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, 2012		(Level 1)		(Level 2)		(Level 3)
Liabilities
2018 Senior unsecured notes	$	187,066	$	—	$	187,066	$	—
Total liabilities	$	187,066	$	—	$	187,066	$	—

FASB ASC 825-10-65, 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, accrued interest 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, and as such these have been excluded from the table above.

•

Long-term debt including current portion: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The estimated fair value of the senior unsecured notes is based on market prices of similar debt. The carrying amount of the Partnership's note payable to bank as of September 30, 2013 is not deemed to be significantly different than the fair value.


(9)	Other Accrued Liabilities

Components of other accrued liabilities were as follows:



	September 30, 2013		December 31, 2012
Accrued interest	$	10,277	$	4,492
Property and other taxes payable	6,609		2,770
Accrued payroll	1,200		1,991
Other	245		236
	$	18,331	$	9,489


(10)	Long-Term Debt and Capital Leases

At September 30, 2013 and December 31, 2012, long-term debt consisted of the following:



	September 30, 2013		December 31, 2012
$600,000 Revolving credit facility at variable interest rate (3.13%* weighted average at September 30, 2013), due March 2018 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	$	219,000	$	296,000
$200,000** Senior notes, 8.875% interest, net of unamortized discount of $1,381 and $1,612, respectively, issued March 2010 and due April 2018, unsecured	173,619		173,388
$250,000 Senior notes, 7.250% interest, issued February 2013 and due February 2021, unsecured	250,000		—
$3,315 Note payable to bank, interest rate at 4.75%, maturity date of October 2029, unsecured	2,885		2,971
Capital lease obligations	5,673		5,839
Total long-term debt and capital lease obligations	651,177		478,198
Less current installments	3,173		3,206
Long-term debt and capital lease obligations, net of current installments	$	648,004	$	474,992

* 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 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing LIBOR borrowings is 2.50%. Effective October 1, 2013, the applicable margin for existing LIBOR borrowings remained at 2.50%. Effective January 1, 2014, the applicable margin for existing LIBOR borrowings will increase to 3.00%. As of November 4, 2013, the Partnership's weighted average interest rate on its revolving loan facility is 2.80%.

** Pursuant to the Indenture under which the Senior Notes due in 2018 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.

Effective March 28, 2013, the Partnership increased the maximum amount of borrowings and letters of credit available under the Credit Facility from $400,000 to $600,000 and extended the maturity date of the facility from April 2016 to March 2018.

On February 11, 2013, the Partnership completed a private placement of $250,000 in aggregate principal amount of 7.250% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. The Partnership filed with the

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

SEC a registration statement to exchange the 2021 Notes for substantially identical notes that are registered under the Securities Act, and completed the exchange offer on July 31, 2013.

The Partnership paid cash interest in the amount of $11,289 and $4,696 for the three months ended September 30, 2013 and 2012, respectively. The Partnership paid cash interest in the amount of $22,897 and $19,039 for the nine months ended September 30, 2013 and 2012, respectively. Capitalized interest was $326 and $175 for the three months ended September 30, 2013 and 2012, respectively. Capitalized interest was $744 and $799 for the nine months ended September 30, 2013 and 2012, respectively.


(11)	Partners' Capital

As of September 30, 2013, partners’ capital consisted of 26,624,276 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owned 5,093,267 of the Partnership's common limited partnership units representing approximately 19.1% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2% general partnership interest.

The partnership agreement of the Partnership (the “Partnership Agreement”) contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

Issuance of Common Units

On November 26, 2012, the Partnership completed a public offering of 3,450,000 common units at a price of $31.16 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 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $102,809. The Partnership's general partner contributed $2,194 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

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. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

Incentive Distribution Rights

The Partnership’s general partner, MMGP, 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, 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. On October 2, 2012, the Partnership Agreement was amended to provide that the general partner shall forego the next $18,000 in incentive distributions that it would otherwise be entitled to receive. No incentive distributions were allocated to the general partner from July 1, 2012 (which would have been payable to the general partner on November 14, 2012 for the third quarter of 2012 distribution) through September 30, 2013. As of September 30, 2013, the amount of incentive distributions the general partner has foregone is $7,490, resulting in an amount remaining of $$10,510.

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, 2013 and 2012, the general partner received no incentive distributions. For the nine months ended September 30, 2013 and 2012, the general partner received $0 and $2,857, respectively, in incentive distributions.

Distributions of Available Cash

The Partnership distributes all of its available cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Net Income per Unit

The Partnership follows the provisions of the FASB 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 general partner 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. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.

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 weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method. The following 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,
	2013			2012			2013			2012
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	192		$	8,646		$	25,907		$	27,432
Less pre-acquisition income allocated to Parent	—			(152		)	—			4,622
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—			(1,536		)	—			723
Distributions payable on behalf of general partner interest	467			(320		)	1,384			295
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	(463		)	526			(866		)	147
Less income allocable to unvested restricted units	1			—			67			—
Limited partners’ interest in net income	$	187		$	10,128		$	25,322		$	21,645

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	—	$	63,603	$	—	$	67,312
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		1,536		—		2,134
Distributions payable on behalf of general partner interest	—		709		—		872
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	—		533		—		432
Limited partners’ interest in net income	$	—	$	60,825	$	—	$	63,874

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 26,552,028 and 26,561,406 for the three and nine months ended September 30, 2013, respectively, and 23,101,233 and 22,929,172 for the three and nine months ended September 30, 2012, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 26,632 and 19,757 for the three and nine months ended September 30, 2013, respectively, and 3,596 and 3,164 for the three and nine months ended September 30, 2012, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.


(12)	Related Party Transactions

As of September 30, 2013, Martin Resource Management owned 5,093,267 of the Partnership’s common units representing approximately 19.1% of the Partnership’s outstanding limited partnership units. The Partnership’s general partner, MMGP, owns a 2.0% general partner interest in the Partnership and the Partnership’s IDRs. 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, 2013, of approximately 19.1% 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 agreements and 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 (the “Omnibus Agreement”) 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 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

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 and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;

•providing marine transportation of petroleum products and by-products;

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

•distributing NGLs; and

•manufacturing and selling sulfur-based fertilizer products and other sulfur-related 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 crude oil gathering business in Stephens, Arkansas;


◦	providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;


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


◦	operating an environmental consulting company;


◦	operating an engineering services company;


◦	building and marketing sulfur processing equipment;


◦	supplying employees and services for the operation of the Partnership's business;


◦	operating, for its account and the Partnership's account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at the Partnership's Stanolind terminal; and


◦	operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.


•	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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

Effective October 1, 2012, through December 31, 2013, 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 $10,622. The Partnership reimbursed Martin Resource Management for $2,655 and $7,966 of indirect expenses for the three and nine months ended September 30, 2013, respectively. 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 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, engineering, legal, 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 Partnership's general partner. 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 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. 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 as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGL's as well as other liquid products.

Term and Pricing. 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. These rates are subject to any adjustments which are mutually agreed upon 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, 2013

(Unaudited)

Resource Management on a spot-contract basis at applicable market rates. 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.

Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of 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.

Talen's Agreements. In connection with the Talen's acquisition, three new agreements were executed, all with effective dates of December 31, 2012. Under the terms of these contracts, Talen's provides terminal services and marine transportation services to Martin Resource Management. The terminal services agreements both have five-year terms and provide a per gallon throughput rate, which may be adjusted annually based on a price index. The marine transportation agreement has an initial term of one year with automatic successive one-year renewals unless either party elects not to do so. Contract rates are based on the horsepower and capacity of the marine vessels.

Other Agreements

Cross Tolling Agreement. The Partnership is a party to an agreement with Cross, originally dated November 25, 2009, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement, which has subsequently been amended, has a 22 year term which expires November 25, 2031. Under this tolling agreement, Cross 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, Cross 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 second amended and restated sulfuric acid sales agency agreement dated August 13, 2013, 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, as amended, 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, 2013

(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 and Condensed 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 and condensed 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 and condensed financial statements as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Revenues:
Terminalling and storage	$	18,044	$	18,531	$	52,857	$	48,611
Marine transportation	5,943		3,979		18,828		13,282
Product sales:
Natural gas services	—		—		9		105
Sulfur services	809		1,469		3,460		4,829
Terminalling and storage	155		168		543		850
	964		1,637		4,012		5,784
	$	24,951	$	24,147	$	75,697	$	67,677

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



Cost of products sold:
Natural gas services	$	7,799	$	6,761	$	23,391	$	18,783
Sulfur services	4,539		4,111		13,514		12,512
Terminalling and storage	13,488		13,165		39,638		36,509
	$	25,826	$	24,037	$	76,543	$	67,804

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



Expenses:
Operating expenses
Marine transportation	$	9,697	$	7,236	$	29,260	$	21,217
Natural gas services	542		453		1,496		1,368
Sulfur services	2,115		1,494		6,405		4,796
Terminalling and storage	5,548		4,917		16,249		14,927
	$	17,902	$	14,100	$	53,410	$	42,308

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



Selling, general and administrative:
Marine transportation	$	15	$	15	$	45	$	47
Natural gas services	635		366		1,623		1,052
Sulfur services	748		737		2,360		2,183
Terminalling and storage	291		—		935		39
Indirect overhead allocation, net of reimbursement	2,667		1,646		7,981		4,937
	$	4,356	$	2,764	$	12,944	$	8,258


(13)	Income Taxes

Except as discussed below, the operations of a partnership are generally not subject to income taxes because its income is taxed directly to its partners. The activities of the Blending and Packaging Assets prior to the acquisition by the Partnership were subject to federal and state income taxes. Accordingly, income taxes have been included in the Blending and Packaging Assets' operating results for the three and nine months ended September 30, 2012.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

Woodlawn Pipeline Co., Inc (“Woodlawn”), a former subsidiary of the Partnership, was subject to income taxes due to its corporate structure. The assets of Woodlawn were included in the Prism Assets disposed of during 2012. The entity was liquidated on December 31, 2012. Income tax expense related to Woodlawn is recorded in discontinued operations. A current state income tax expense of $90 and $95 related to Woodlawn was recorded for the three and nine months ended September 30, 2012, respectively.

The Partnership established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired Woodlawn assets and liabilities at the date of acquisition. The basis differences related primarily to property, plant and equipment. 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. The deferred tax liability related to the Prism Assets was reversed upon the sale of those assets.

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 and Condensed Statements of Operations. The Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the 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 $303 and $910 were recorded in continuing operations current income tax expense for the three and nine months ended September 30, 2013 and $238 and $810 for the three and nine months ended September 30, 2012, respectively.

The components of income tax expense (benefit) from operations recorded for the three and nine months ended September 30, 2013 and 2012 are as follows:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
Current:
Federal	$	—	$	5,933		$	—	$	7,642
State	303		844			910		1,703
	303		6,777			910		9,345
Deferred:
Federal	—		(7,238		)	—		(7,293		)
Total income tax expense (benefit)	$	303	$	(461	)	$	910	$	2,052

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,
	2013		2012		2013		2012
Current:
Federal	$	—	$	130	$	—	$	1,835
State	303		276		910		1,129
	303		406		910		2,964
Deferred:
Federal	—		135		—		402
Total income tax expense from continuing operations	$	303	$	541	$	910	$	3,366

Income tax expense (benefit) from discontinued operations:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
Current:
Federal	$	—	$	5,803		$	—	$	5,807
State	—		568			—		574
	—		6,371			—		6,381
Deferred:
Federal	—		(7,373		)	—		(7,695		)
Total income tax benefit from discontinued operations	$	—	$	(1,002	)	$	—	$	(1,314	)


(14)	Business Segments

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

The accounting policies of the operating segments are the same as those described in Note 2 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 4, 2013. 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.



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Three Months Ended September 30, 2013
Terminalling and storage	$	90,205	$	(1,199	)	$	89,006	$	8,532	$	7,350		$	33,563
Natural gas services	204,926		—			204,926		598		5,466			2,398
Sulfur services	42,097		—			42,097		2,024		(527		)	2,068
Marine transportation	24,751		(1,164		)	23,587		2,544		3,733			1,943
Indirect selling, general and administrative	—		—			—		—		(3,779		)	—
Total	$	361,979	$	(2,363	)	$	359,616	$	13,698	$	12,243		$	39,972

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(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	$	81,845	$	(1,191	)	$	80,654	$	5,829	$	6,858		$	10,775
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	$	356,058	$	(1,968	)	$	354,090	$	10,292	$	16,246		$	20,178

Nine Months Ended September 30, 2013	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Terminalling and storage	$	256,320	$	(3,507	)	$	252,813	$	22,925	$	25,968		$	59,930
Natural gas services	653,080		—			653,080		1,444		18,858			2,513
Sulfur services	173,378		—			173,378		5,947		16,518			2,690
Marine transportation	75,004		(2,785		)	72,219		7,628		8,813			3,458
Indirect selling, general and administrative	—		—			—		—		(11,270		)	—
Total	$	1,157,782	$	(6,292	)	$	1,151,490	$	37,944	$	58,887		$	68,591

Nine Months Ended September 30, 2012	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Terminalling and storage	$	246,219	$	(3,542	)	$	242,677	$	16,028	$	20,536		$	54,309
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	$	1,042,038	$	(5,776	)	$	1,036,262	$	30,315	$	55,242		$	71,550

The Partnership's assets by reportable segment as of September 30, 2013 and December 31, 2012, are as follows:



	September 30, 2013		December 31, 2012
Total assets:
Terminalling and storage	$	435,484	$	376,330
Natural gas services	375,817		331,064
Sulfur services	145,447		155,639
Marine transportation	163,454		149,963
Total assets	$	1,120,202	$	1,012,996

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)


(15)	Unit Based Awards

The Partnership recognizes compensation cost related to stock-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to stock-based awards to directors under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees. Amounts recognized in selling, general, and administrative expense in the consolidated and condensed financial statements with respect to these plans are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Employees	$	181	$	196	$	533	$	234
Non-employee directors	76		65		204		145
Total unit-based compensation expense	$	257	$	261	$	737	$	379

Long-Term Incentive Plans

The Partnership's general partner has a long term incentive plan for employees and directors of the general partner and its affiliates who perform services for the Partnership.

The plan consists of two components, restricted units and unit options. The plan currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit options. The plan is administered by the Compensation Committee of the general partner’s board of directors.

Restricted Units. A restricted unit is a unit that is granted to grantees with certain vesting restrictions. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. In addition, the restricted units will vest upon a change of control of the Partnership, the general partner or Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units. The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally cliff vest after three years of service.

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the nine months ended September 30, 2013 is provided below:



	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	13,248			$	41.84
Granted	63,750			$	32.55
Vested	(4,500		)	$	41.27
Forfeited	(250		)	$	31.06
Non-Vested, end of period	72,248			$	33.72

Aggregate intrinsic value, end of period	$	3,391

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the three and nine months ended September 30, 2013 and 2012 are provided below:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Aggregate intrinsic value of units vested	$	—	$	—	$	153	$	214
Fair value of units vested	$	—	$	—	$	157	$	214

As of September 30, 2013, there was $1,859 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.33 years.

Unit Options. The plan currently permits the grant of options covering common units. As of November 4, 2013, the Partnership has not granted any common unit options to directors or employees of the Partnership's general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. Unit options will have an exercise price that, in the discretion of the Compensation Committee, may not be less than the fair market value of the units on the date of grant. In addition, the unit options will become exercisable upon a change in control of the Partnership's general partner, Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.


(16)	Condensed Consolidating Financial Information

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. The guarantees that have been issued are 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.

Since December 31, 2012, the Partnership has added Redbird and MOP Midstream Holdings, LLC as subsidiary guarantors to its outstanding senior notes and has transferred substantially all of Talen's assets to certain of the Partnership's other subsidiary guarantors. Therefore, the Partnership no longer presents condensed consolidating financial information for any non-subsidiary guarantors.


(17)	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.


(18)	Prior Period Correction of an Immaterial Error

The Partnership's Consolidated and Condensed Statements of Operations for the three and nine months ended September 30, 2012 has been revised to correct an immaterial error in the earnings (loss) of unconsolidated entities of ($97) and ($514), respectively. The following financial statement captions in the Consolidated and Condensed Statements of Operations were affected by this correction:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2013

(Unaudited)



	Three Months Ended September, 30, 2012						Difference			Nine Months Ended September 30, 2012						Difference
	As Previously Reported			As Corrected			Difference			As Previously Reported			As Corrected			Difference
	(In thousands)									(In thousands)
Equity in earnings (loss) of unconsolidated entities	$	(678	)	$	(775	)	$	(97	)	$	770		$	256		$	(514	)
Total other expense	$	(6,962	)	$	(7,059	)	$	(97	)	$	(23,930	)	$	(24,444	)	$	(514	)
Income from continuing operations	$	8,743		$	8,646		$	(97	)	$	27,946		$	27,432		$	(514	)
Net income	$	72,346		$	72,249		$	(97	)	$	95,258		$	94,744		$	(514	)
Pre-acquisition income allocated to parent	$	(55	)	$	(152	)	$	(97	)	$	5,136		$	4,622		$	(514	)

Additionally, the Consolidated and Condensed Statements of Cash Flows for the nine months ended September 30, 2012 has been revised to correct an immaterial error of $2,208 in the equity in loss of unconsolidated entities (which is an adjustment to reconcile net income to net cash provided by operating activities) and affiliate funding of investments in unconsolidated entities (which is included in cash flows from financing activities). The correction of this immaterial error decreases net cash provided by operating activities, increases net cash provided by financing activities, and had no effect on the Partnership's cash and cash equivalents, investments in unconsolidated entities, net income or partners' capital.


(19)	Subsequent Events

Sale of Investment in Unconsolidated Entity. On November 1, 2013, the Partnership sold its 50% investment in Caliber for $750.

Quarterly Distribution. On October 24, 2013, the Partnership declared a quarterly cash distribution of $0.7825 per common unit for the third quarter of 2013, or $3.13 per common unit on an annualized basis, which will be paid on November 14, 2013 to unitholders of record as of November 7, 2013.



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, 2012, filed with the Securities and Exchange Commission (the “SEC”) on March 4, 2013, and in this report.

Overview

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


•	Terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;


•	Natural gas liquids distribution services and natural gas storage;


•	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 U.S. Gulf Coast region. 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 petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of September 30, 2013, Martin Resource Management owned 19.1% of our total outstanding common limited partner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC (“MMGP”), our general partner, by virtue of its 51% voting interest in MMGP Holdings,

LLC (“Holdings”), a sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operation through its ownership interests in and control of our general partner.

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.

We continually adjust our business strategy to focus on maximizing liquidity, maintaining a stable asset base which generates fee based revenues not sensitive to commodity prices, and improving profitability by increasing asset utilization and 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. Over the next two years, we plan to increase expansion capital expenditures primarily in our Terminalling and Storage and Natural Gas Services segments.

Marine Transportation Equipment Purchase. On September 30, 2013, we acquired two inland tank barges from Martin Resource Management for $7.1 million. This transaction was funded with borrowings under our revolving credit facility.

Sale of general partner interest. On August 30, 2013, Martin Resource Management completed the sale of a 49% non-controlling voting interest (50% economic interest) in Holdings, a newly-formed sole member of MMGP, the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners (“Alinda”). Upon closing the transaction, Alinda appointed two representatives to serve as directors of the general partner.

Sulfur Production Facility. On August 5, 2013, we purchased a plant nutrient sulfur production facility in Cactus, Texas for $4.1 million. This transaction was funded by borrowings under our revolving credit facility.

NL Grease, LLC. On June 13, 2013, we acquired certain assets of NL Grease, LLC (“NLG”) for approximately $12.1 million. NLG is a Kansas City, Missouri based grease manufacturer that specializes in private-label packaging of commercial and industrial greases. This transaction was funded by borrowings under our revolving credit facility.

Amendment to Revolving Credit Facility. On March 28, 2013, we made certain strategic amendments to our credit facility which, among other things, increased our borrowing capacity from $400.0 million to $600.0 million and extended the maturity date of the facility from April 15, 2016 to March 28, 2018.

NGL Marine Equipment Purchase. On February 28, 2013, we purchased from affiliates of Florida Marine Transporters, Inc., six liquefied petroleum gas pressure barges and two commercial push boats (“Florida Marine Assets”) for approximately $50.8 million. This transaction was funded with borrowings under our revolving credit facility.

Issuance of 2021 Senior Unsecured Notes. On February 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.250% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $245.1 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility. On July 1, 2013, we filed a registration statement on Form S-4 with the SEC to exchange the Notes for registered 7.250% senior unsecured notes due February 2021. The exchange offer was completed on July 31,2013.

Talen's Marine & Fuel LLC. On December 31, 2012, we acquired all of the outstanding membership interests in Talen's Marine & Fuel LLC (“Talen's”) from QEP Marine Fuel Investment, LLC and QEP Marine Fuel Holdings, Inc. (collectively referred to as “Quintana Energy Partners”) for $103.4 million, subject to certain post-closing adjustments. Simultaneous with the acquisition, we sold certain working capital-related assets to Martin Energy Services LLC (“MES”), a wholly-owned subsidiary of Martin Resource Management for $56.0 million, reducing our investment in Talen's to $47.4 million. This transaction was funded with borrowings under our revolving credit facility. In conjunction with its purchase of

certain working capital-related assets, MES entered into various service agreements with Talen's pursuant to which we provide certain terminalling and marine services to MES.

Critical Accounting Policies and Estimates

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 United States generally accepted accounting principles (“U.S. GAAP” or “GAAP”). 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. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from these estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations or cash flows. You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements included within our Annual Report on Form 10-K for the year ended December 31, 2012. The following table evaluates the potential impact of estimates utilized during the periods ended September 30, 2013 and 2012:



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Allowance for Doubtful Accounts
We evaluate our allowance for doubtful accounts on an ongoing basis and record adjustments when, in management's judgment, circumstances warrant. Reserves are recorded to reduce receivables to the amount ultimately expected to be collected.	We evaluate the collectability of our accounts receivable based on factors such as the customer's ability to pay, the age of the receivable and our historical collection experience. A deterioration in any of these factors could result in an increase in the allowance for doubtful accounts balance.	If actual collection results are not consistent with our judgments, we may experience increase in uncollectible receivables. A 10% increase in our allowance for doubtful accounts would result in a decrease in net income of approximately $0.3 million.
Depreciation
Depreciation expense is computed using the straight-line method over the useful life of the assets.	Determination of depreciation expense requires judgment regarding estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, estimates are reviewed to determine if any changes in the underlying assumptions are needed.	The lives of our fixed assets range from 3 - 25 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $5.4 million, resulting in a corresponding reduction in net income.
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.	Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.	Applying this impairment review methodology, we have recorded no impairment charges during the periods ended September 30, 2013 and 2012. If actual events are not consistent with our estimates and assumptions or our estimates and assumptions change due to new information, we may incur an impairment charge.
Impairment of Goodwill
Goodwill is subject to a fair-value based impairment test on an annual basis, or more frequently if events or changes in circumstances indicate that the fair value of any of our reporting units is less than its carrying amount.	We determine fair value using accepted valuation techniques, including discounted cash flow, the guideline public company method and the guideline transaction method. These analyses require management to make assumptions and estimates regarding industry and economic factors, future operating results and discount rates. We conduct impairment testing using present economic conditions, as well as future expectations.	We completed the most recent annual review of goodwill as of August 31, 2013 and determined there was no impairment. Additionally, management is aware of no change in circumstances which indicate a need for an interim impairment evaluation.



Impairment of Investments in Unconsolidated Entities
We evaluate our investments in unconsolidated entities for impairment when, in management's opinion, events or changes in circumstances indicate that the carrying value of an investment may have experienced a decline. If evidence of loss has occurred, we compare the estimated fair value of the investment to the carrying value to determine whether an impairment has occurred.	Our evaluation requires management to apply judgment in estimating future cash flows, asset fair values, useful lives of the assets, selection of a risk-adjusted discount rate and assessing the probability of differing outcomes.	Utilizing the methodology described herein, we have recorded no impairment charges on investments in unconsolidated entities during the periods ended September 30, 2013 and 2012. If our evaluation indicated the fair value is less than the carrying value, the excess amount would be recorded as an impairment.
Purchase Price Allocations
We allocate the purchase price of an acquired business to its identifiable assets (including identifiable intangible assets) and liabilities based on their fair values at the date of acquisition. Any excess of purchase price in excess of amounts allocated to identifiable assets and liabilities is recorded as goodwill. As additional information becomes available, we may adjust the preliminary allocation for a period of up to one year.	The determination of fair values of acquired assets and liabilities requires a significant level of management judgment. Fair values are estimated using various methods as deemed appropriate. For significant transactions, third party assessments may be engaged to assist in the valuation process.	If subsequent factors indicate that estimates and assumptions used to allocate costs to acquired assets and liabilities differ from actual results, the allocation between goodwill, other intangible assets and fixed assets could significantly differ. Any such differences could impact future earnings through depreciation and amortization expense. Additionally, if estimated results supporting the valuation of goodwill or other intangible assets are not achieved, impairments could result.
Asset Retirement Obligations
Asset retirement obligations (“AROs”) associated with a contractual or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and depreciated over the life of the related asset or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled.	Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate.	If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.
Environmental Liabilities
We estimate environmental liabilities using both internal and external resources. Activities include feasibility studies and other evaluations management considers appropriate. Environmental liabilities are recorded in the period in which the obligation can be reasonably estimated.	Estimating environmental liabilities requires significant management judgment as well as possible use of third party specialists knowledgeable in such matters.	Environmental liabilities have not adversely affected our results of operations or financial condition in the past, and we do not anticipate that they will in the future.

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, Florida, Mississippi and Texas;


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


•	providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;


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


•	operating an environmental consulting company;


•	operating an engineering services company;


•	building and marketing of sulfur processing equipment;


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


•	operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal; and


•	operating, solely for our account, the 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 19.1% limited partnership interest in us. In addition, Martin Resource Management controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, a sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights.

Management

Martin Resource Management directs our business operations through its ownership interests in 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

The omnibus agreement with Martin Resource Management 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 $45.4 million of direct costs and expenses for the three months ended September 30, 2013 compared to $39.3 million for the three months ended September 30, 2012. We reimbursed Martin Resource Management for $134.9 million of direct costs and expenses for the nine months ended September 30, 2013 compared to $113.4 million for the nine months ended September 30, 2012. 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. For the three months ended September 30, 2013 and 2012, the conflicts committee of our general partner (“Conflicts Committee”) approved reimbursement amounts of $2.7 and $1.6 million, respectively, reflecting our allocable share of such expenses. For the nine months ended September 30, 2013 and 2012, the Conflicts Committee approved reimbursement amounts of $8.0 million and $4.9 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee of our general partner's board of directors will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical, engineering, legal, 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’s 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.

The agreements include, but are not limited to, motor carrier agreements, marine transportation agreements, terminal services agreements, a tolling agreement, a sulfuric acid agreement, and various other miscellaneous agreements. Pursuant to

the terms of the omnibus agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee of our general partner’s board of directors.

For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions – Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 4, 2013.

Commercial

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

We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 1.4 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, the impact of related party transactions included in cost of products sold accounted for approximately 9% and 8% of our total cost of products sold during the three and nine months ended September 30, 2013, respectively. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 8% of our total cost of products sold during both the three and nine months ended September 30, 2012. 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 7% of our total revenues for the three months ended September 30, 2013 and 2012, respectively. Our sales to Martin Resource Management accounted for approximately 7% of our total revenues for the nine months ended September 30, 2013 and 2012, respectively. We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, MES, and MES provides terminal services to us to handle lubricants, greases and drilling fluids. Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

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, 2012, filed with the SEC on March 4, 2013.

Approval and Review of Related Party Transactions

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

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements other than our financial statements prepared in accordance with U.S. GAAP to analyze our performance. These include: (1) net income before interest expense, income tax expense, and depreciation and amortization (“EBITDA”), (2) adjusted EBITDA and (3) distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and the ability to generate and distribute cash flow, and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.

EBITDA and Adjusted EBITDA. Certain items excluded from EBITDA and adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and adjusted EBITDA because they provide investors and management with additional information to better understand the following: financial performance of our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared to those of other similarly situated entities; and the viability of acquisitions and capital expenditure projects. Our method of computing adjusted EBITDA may not be the same method used to compute similar measures reported by other entities. The economic substance behind our use of adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. Distributable cash flow is a significant performance measure used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit's yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

EBITDA, adjusted EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, cash flows from operating activities, or any other measure presented in accordance with U.S. GAAP. Our method of computing these measures may not be the same method used to compute similar measures reported by other entities.

Non-GAAP Financial Measures

The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the three and nine months ended September 30, 2013 and 2012, which represents EBITDA, Adjusted EBITDA and Distributable Cash Flow from continuing operations.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012

Net income	$	192		$	72,249		$	25,907		$	94,744
Less: Income from discontinued operations, net of income taxes	—			(63,603		)	—			(67,312		)
Income from continuing operations	192			8,646			25,907			27,432
Adjustments:
Interest expense	11,060			6,789			31,058			23,284
Income tax expense	303			541			910			3,366
Depreciation and amortization	13,698			10,292			37,944			30,315
EBITDA	25,253			26,268			95,819			84,397
Adjustments:
Equity in (earnings) loss of unconsolidated entities	577			775			878			(256		)
(Gain) loss on sale of property, plant and equipment	—			4			(796		)	7
(Gain) loss on equity method investment	—			(486		)	—			(486		)
Debt prepayment premium	—			—			—			2,470
Distributions from unconsolidated entities	761			836			2,722			3,114
Mont Belvieu indemnity escrow payment	—			—			—			(375		)
Unit-based compensation	258			261			737			379
Adjusted EBITDA	26,849			27,658			99,360			89,250
Adjustments:
Interest expense	(11,060		)	(6,789		)	(31,058		)	(23,284		)
Income tax expense	(303		)	(541		)	(910		)	(3,366		)
Amortization of deferred debt issuance costs	815			680			2,890			2,611
Amortization of debt discount	77			77			230			504
Payments of installment notes payable and capital lease obligations	(91		)	(81		)	(251		)	(256		)
Deferred income taxes	—			135			—			402
Payments for plant turnaround costs	—			(175		)	—			(2,578		)
Maintenance capital expenditures	(2,973		)	(1,325		)	(7,473		)	(3,603		)
Distributable Cash Flow	$	13,314		$	19,639		$	62,788		$	59,680

Results of Operations

The results of operations for the three and nine months ended September 30, 2013 and 2012 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, 2013 and 2012. 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.

Our consolidated and condensed results of operations are presented 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.

The Natural Gas Services segment information below excludes the discontinued operations of the Prism Assets for all periods.

Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
	(In thousands)
Three Months Ended September 30, 2013
Terminalling and storage	$	90,205	$	(1,199	)	$	89,006	$	8,052		$	(702	)	$	7,350
Natural gas services	204,926		—			204,926		4,590			876			5,466
Sulfur services	42,097		—			42,097		753			(1,280		)	(527		)
Marine transportation	24,751		(1,164		)	23,587		2,627			1,106			3,733
Indirect selling, general and administrative	—		—			—		(3,779		)	—			(3,779		)
Total	$	361,979	$	(2,363	)	$	359,616	$	12,243		$	—		$	12,243

Three Months Ended September 30, 2012	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Terminalling and storage	$	81,845	$	(1,191	)	$	80,654	$	7,513		$	(655	)	$	6,858
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	$	356,058	$	(1,968	)	$	354,090	$	16,246		$	—		$	16,246

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Nine Months Ended September 30, 2013
Terminalling and storage	$	256,320	$	(3,507	)	$	252,813	$	27,657		$	(1,689	)	$	25,968
Natural gas services	653,080		—			653,080		17,254			1,604			18,858
Sulfur services	173,378		—			173,378		19,659			(3,141		)	16,518
Marine transportation	75,004		(2,785		)	72,219		5,587			3,226			8,813
Indirect selling, general and administrative	—		—			—		(11,270		)	—			(11,270		)
Total	$	1,157,782	$	(6,292	)	$	1,151,490	$	58,887		$	—		$	58,887



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Nine Months Ended September 30, 2012
Terminalling and storage	$	246,219	$	(3,542	)	$	242,677	$	22,499		$	(1,963	)	$	20,536
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	$	1,042,038	$	(5,776	)	$	1,036,262	$	55,242		$	—		$	55,242

Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended September 30, 2013 and 2012



	Three Months Ended September 30,				Variance			Percent Change
	2013		2012		Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	30,151	$	25,066	$	5,085		20%
Products	60,054		56,779		3,275			6%
Total revenues	90,205		81,845		8,360			10%

Cost of products sold	53,215		52,697		518			1%
Operating expenses	19,427		14,372		5,055			35%
Selling, general and administrative expenses	979		1,434		(455		)	(32)%
Depreciation and amortization	8,532		5,829		2,703			46%
Operating income	$	8,052	$	7,513	$	539		7%

Lubricant sales volumes (gallons)	10,638		9,475		1,163			12%
Shore-based throughput volumes (gallons)	65,516		54,728		10,788			20%
Smackover refinery throughput volumes (BBL per day)	6,878		7,404		(526		)	(7)%
Corpus Christi crude terminal (BBL per day)	101,921		49,400		52,521			106%

Services revenues. Services revenue increased primarily due to $3.2 million of additional revenue attributable to our new crude terminal in Corpus Christi, Texas, which was placed into service in May 2012. In addition, $1.2 million of the increase is due to revenues generated by Talen's, which was acquired on December 31, 2012.

Products revenues. A 25% increase in sales volumes at our blending and packaging facilities resulted in an $8.7 million positive impact on product revenues. Product sales volumes from our shore-based terminals decreased 16%, resulting in $3.3 million reduction in product revenues. The average sales price from our blending and packaging assets decreased 6%, resulting in a $2.0 million decrease in product revenues. The average sales price at our shore-based terminals decreased 1%, resulting in a $0.1 million decrease in product revenues.

Cost of products sold. A 25% increase in sales volumes at our blending and packaging facilities resulted in a $7.6 million increase in cost of products sold, which was partially offset by a 16% decrease in sales volumes from at our shore-based terminals, resulting in a $3.0 million decrease in cost of products sold. Decreased average cost at our blending and packaging facilities of 10%, resulted in a decrease of $3.5 million in cost of products sold. Decreased average cost at our shore-based terminals of 3%, resulted in a decrease of $0.6 million in cost of products sold.

Operating expenses. The increase consists of $1.7 million related to our specialty terminals, primarily the Corpus Christi crude terminal placed in service in May 2012. Higher expenses at the Smackover refinery accounted for $2.5 million of the increase, including an increase in utilities and chemicals of $0.6 million, increased repairs and maintenance of $0.5 million, and increased leasing expense of $0.6 million. Additionally, $0.8 million relates to increased expense at our shore-based terminals primarily due to expenses associated with the Talen's terminals.

Selling, general and administrative expenses. The decrease in selling, general, and administrative expenses is primarily related to decreased advertising expense in our lubricants operations of $0.2 million and decreased compensation expense at our specialty terminals of $0.3 million.

Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Comparative Results of Operations for the Nine Months Ended September 30, 2013 and 2012



	Nine Months Ended September 30,				Variance			Percent Change
	2013		2012		Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	88,770	$	68,649	$	20,121		29%
Products	167,550		177,570		(10,020		)	(6)%
Total revenues	256,320		246,219		10,101			4%

Cost of products sold	148,624		161,850		(13,226		)	(8)%
Operating expenses	54,860		42,339		12,521			30%
Selling, general and administrative expenses	2,422		3,898		(1,476		)	(38)%
Depreciation and amortization	22,925		16,028		6,897			43%
	27,489		22,104		5,385			24%
Other operating income	168		395		(227		)	(57)%
Operating income	$	27,657	$	22,499	$	5,158		23%

Lubricant sales volumes (gallons)	29,885		29,319		566			2%
Shore-based throughput volumes (gallons)	207,533		165,701		41,832			25%
Smackover refinery throughput volumes (BBL per day)	6,780		5,879		901			15%
Corpus Christi crude terminal (BBL per day)	105,759		40,122		65,637			164%

Services revenues. Services revenue increased primarily due to $15.4 million attributable to our new crude terminal in Corpus Christi, Texas, which was placed into service in May 2012. In addition, $3.9 million of the increase is due to revenues generated by Talen's, which was acquired on December 31, 2012.

Products revenues. A 7% increase in sales volumes at our blending and packaging facilities resulted in a $7.3 million positive impact on product revenues. Product sales volumes from our shore-based terminals decreased 10%, resulting in $5.6 million reduction in product revenues. The average sales price from our blending and packaging assets decreased 7%, resulting in an $8.2 million decrease in product revenues. The average sales price at our shore-based terminals decreased 6%, resulting in a $3.4 million decrease in product revenues.

Cost of products sold. A 7% increase in sales volumes at our blending and packaging facilities resulted in a $6.3 million increase in cost of products sold, which was partially offset by a 10% decrease in sales volumes from at our shore-based terminals, resulting in a $5.2 million decrease in cost of products sold. Decreased average cost at our blending and packaging facilities of 10%, resulted in a decrease of $10.3 million in cost of products sold. Decreased average cost at our shore-based terminals of 7%, resulted in a decrease of $4.0 million in cost of products sold.

Operating expenses. Increased expenses for the specialty terminals, primarily attributable to the Corpus Christi crude terminal, accounted for $5.7 million of the increase. Our shore-based terminal expenses increased $1.8 million primarily due to the Talen's terminals. In addition, $5.0 million of the increase is attributable to the Smackover refining assets, primarily as a result of increased utilities and repairs and maintenance expense.

Selling, general and administrative expenses. The decrease in selling, general, and administrative expenses is primarily related to decreased advertising expense in our lubricants operations.

Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Other operating income. Other operating income decreased primarily due to the final indemnity payment related to the 2009 sale of our Mont Belvieu facility. This payment of $0.4 million was recorded in the second quarter of 2012. Other operating income for the nine months ended September 30, 2013 represents gain on the disposition of property, plant and equipment.

Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended September 30, 2013 and 2012



	Three Months Ended September 30,				Variance			Percent Change
	2013		2012		Variance			Percent Change
	(In thousands)
Revenues:
Marine transportation	$	630	$	—	$	630
Products	204,296		190,738		13,558			7%
Total revenues	204,926		190,738		14,188			7%

Cost of products sold	196,719		186,080		10,639			6%
Operating expenses	1,863		847		1,016			120%
Selling, general and administrative expenses	1,156		786		370			47%
Depreciation and amortization	598		149		449			301%
Operating income	$	4,590	$	2,876	$	1,714		60%

Distributions from unconsolidated entities	$	761	$	836	$	(75	)	(9)%

NGL sales volumes (Bbls)	3,162		3,092		70			2%

Revenues. The marine transportation revenue is attributable to our acquisition of the Florida Marine Assets on February 28, 2013. Natural gas services sales volumes increased 2%, resulting in a positive impact on revenues of $4.5 million. Our NGL average sales price per barrel increased $2.92, or 5%, resulting in an increase to revenue of $9.0 million.

Cost of products sold. Our average cost per barrel increased $2.03, or 3%. Our margins increased $0.89 per barrel during the period, primarily as a result of improved market conditions experienced during the three months ended September 30, 2013 compared to the same period of 2012 in the Louisiana butane market.

Operating expenses. Operating expenses increased primarily as a result of outside towing and tankerman expenses associated with the newly acquired Florida Marine Assets of $0.6 million, higher property and liability premiums of $0.2 million, and increased pipeline maintenance expenses of $0.1 million.

Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily as a result of increased compensation expense of $0.3 million and property taxes of $0.2 million.

Depreciation and amortization. Depreciation and amortization increased as a result of the acquisition of the Florida Marine Assets during the first quarter of 2013.

Comparative Results of Operations for the Nine Months Ended September 30, 2013 and 2012



	Nine Months Ended September 30,				Variance			Percent Change
	2013		2012		Variance			Percent Change
	(In thousands)
Revenues:
Marine transportation	$	2,475	$	—	$	2,475
Products	650,605		527,666		122,939			23%
Total revenues	653,080		527,666		125,414			24%

Cost of products sold	627,748		517,083		110,665			21%
Operating expenses	3,834		2,603		1,231			47%
Selling, general and administrative expenses	2,800		2,242		558			25%
Depreciation and amortization	1,444		436		1,008			231%
Operating income	$	17,254	$	5,302	$	11,952		225%

Distributions from unconsolidated entities	$	2,722	$	3,114	$	(392	)	(13)%

NGL sales volumes (Bbls)	9,883		7,825		2,058			26%

Revenues. The marine transportation revenue is attributable to our acquisition of the Florida Marine Assets on February 28, 2013. Natural gas services sales volumes increased 26%, positively impacting revenues $135.5 million, primarily as a result of us entering the Louisiana butane market during April 2012. Our NGL average sales price per barrel decreased $1.60, or 2%, resulting in an offsetting decrease to revenues of $12.5 million.

Cost of products sold. Our average cost per barrel decreased $2.56, or 4%. Our margins increased $0.96 per barrel during the period, primarily as a result of increased margins gained through our entrance into the Louisiana butane market in April 2012.

Operating expenses. Operating expenses increased primarily as a result of outside towing, tankerman, and fuel expenses associated with the newly acquired Florida Marine Assets of $0.7 million, higher property and liability premiums of $0.2 million, and increased pipeline maintenance expenses of $0.1 million.

Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily as a result of increased compensation expense of $0.5 million and property taxes of $0.2 million.

Depreciation and amortization. Depreciation and amortization increased as a result of the acquisition of the Florida Marine Assets during the first quarter of 2013.

Sulfur Services Segment

Comparative Results of Operations for the Three Months Ended September 30, 2013 and 2012



	Three Months Ended September 30,					Variance			Percent Change
	2013		2012			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	3,001	$	2,926		$	75		3%
Products	39,096		57,670			(18,574		)	(32)%
Total revenues	42,097		60,596			(18,499		)	(31)%

Cost of products sold	34,085		47,362			(13,277		)	(28)%
Operating expenses	4,166		4,357			(191		)	(4)%
Selling, general and administrative expenses	1,069		1,008			61			6%
Depreciation and amortization	2,024		1,750			274			16%
	753		6,119			(5,366		)	(88)%
Other operating income	—		(5		)	5			(100)%
Operating income	$	753	$	6,114		$	(5,361	)	(88)%

Sulfur (long tons)	211.8		200.8			11.0			5%
Fertilizer (long tons)	44.8		61.2			(16.4		)	(27)%
Total sulfur services volumes (long tons)	256.6		262.0			(5.4		)	(2)%

Revenues. Service revenue was substantially identical to the same period in 2012. Product revenues were most negatively impacted by lower market prices in our fertilizer business. Revenue declined $17.8 million as a result of a 31% decrease in average sales price. Reduced sales prices of agricultural products is the primary factor causing the decline in fertilizer sales prices negatively affecting our margins. Additionally, revenues decreased $0.8 million due to a 2% decline in sales volumes.

Cost of products sold. A 27% decrease in prices reduced cost of products sold by $12.6 million. A 2% decrease in volumes reduced our cost by an additional $0.7 million. Margin per ton decreased $19.82, or 50%, resulting in a decline in gross margin of $5.3 million, primarily attributable to the decline in market prices discussed above. Also contributing to the decline in the gross margin of our fertilizer business was significant downtime attributable to plant turnarounds at our Plainview and Neches production facilities. Costs associated with these turnarounds were $1.2 million higher than the same period of 2012.

Operating expenses. Our operating expenses decreased as a result of lower outside towing expenses.

Selling, general and administrative expenses. Selling, general and administrative expenses remained consistent.

Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Comparative Results of Operations for the Nine Months Ended September 30, 2013 and 2012



	Nine Months Ended September 30,					Variance			Percent Change
	2013		2012			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	9,003	$	8,777		$	226		3%
Products	164,375		193,464			(29,089		)	(15)%
Total revenues	173,378		202,241			(28,863		)	(14)%

Cost of products sold	131,849		149,853			(18,004		)	(12)%
Operating expenses	12,791		13,164			(373		)	(3)%
Selling, general and administrative expenses	3,132		2,945			187			6%
Depreciation and amortization	5,947		5,325			622			12%
	19,659		30,954			(11,295		)	(36)%
Other operating loss	—		(27		)	27			(100)%
Operating income	$	19,659	$	30,927		$	(11,268	)	(36)%

Sulfur (long tons)	614.9		781.2			(166.3		)	(21)%
Fertilizer (long tons)	219.8		238.7			(18.9		)	(8)%
Total sulfur services volumes (long tons)	834.7		1,019.9			(185.2		)	(18)%

Revenues. The increase in service revenue is attributable to increased contract rates. Product revenue declined $36.5 million as a result of a 18% decrease in volumes. The volume reduction was primarily related to the conversion of a buy/sell contract with a major customer to a fee-based handling contract. This reduction was partially offset by a $7.4 million increase in revenues attributable to a 4% increase in prices, of which our sulfur products saw an increase of 1% and our fertilizer products saw a decrease of 3%.

Cost of products sold. Cost of products sold decreased $29.3 million due to an 18% decline in volumes. This reduction was partially offset by an $11.3 million increase in cost of products sold due to an 8% increase in prices. Our margin per ton decreased $3.79, or 9%, primarily attributable to the decline in market prices in our fertilizer business. Also contributing to the decline in the gross margin of our fertilizer business was significant downtime attributable to plant turnarounds at our Plainview and Neches production facilities during the third quarter of 2013 compared to the same period of 2012.

Operating expenses. Our operating expenses decreased primarily as a result of lower outside towing expenses.

Selling, general and administrative expenses. Selling, general and administrative expenses increased as a result of increased compensation expense.

Depreciation and amortization. The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Marine Transportation Segment

Comparative Results of Operations for the Three Months Ended September 30, 2013 and 2012



	Three Months Ended September 30,				Variance			Percent Change
	2013		2012		Variance			Percent Change
	(In thousands)
Revenues	$	24,751	$	22,879	$	1,872		8%
Operating expenses	19,352		18,026		1,326			7%
Selling, general and administrative expenses	228		580		(352		)	(61)%
Depreciation and amortization	2,544		2,564		(20		)	(1)%
Operating income	$	2,627	$	1,709	$	918		54%

Inland revenues. A $2.8 million increase in inland revenues is primarily attributable to $1.9 million from the Talen's acquisition and $1.3 million from the Florida Marine Assets. Offsetting these increases was a reduction of $0.5 million in ancillary charges, primarily the rebill of fuel.

Offshore revenues. A $1.1 million decrease in offshore revenue consists of $0.4 million in decreased utilization of the offshore fleet and $0.7 million due to lower ancillary charges, primarily the rebill of fuel.

Operating expenses. Operating expenses increased $2.1 million as a result of costs and expenses associated with the acquisitions of Talen's and Florida Marine Assets. Offsetting this increase are decreases in outside towing expense of $0.5 million and repairs and maintenance of $0.3 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased primarily as a result of decreased legal and consulting fees.

Depreciation and amortization. Depreciation and amortization decreased slightly as a result of certain marine assets becoming fully depreciated and the disposal of equipment, offset by increases in depreciable assets related to recent capital expenditures.

Comparative Results of Operations for the Nine Months Ended September 30, 2013 and 2012



	Nine Months Ended September 30,				Variance			Percent Change
	2013		2012		Variance			Percent Change
	(In thousands)
Revenues	$	75,004	$	65,912	$	9,092		14%
Operating expenses	61,417		52,773		8,644			16%
Selling, general and administrative expenses	1,000		1,366		(366		)	(27)%
Depreciation and amortization	7,628		8,526		(898		)	(11)%
	4,959		3,247		1,712			53%
Other operating income	628		—		628
Operating income	$	5,587	$	3,247	$	2,340		72%

Inland revenues. An $8.6 million increase in inland revenues is primarily attributable to $6.4 million from the Talen's acquisition and $1.6 million from the Florida Marine Assets, offset by a decrease of $0.5 million related to decreased utilization of our legacy inland marine transportation fleet. In addition, we saw $1.1 million in higher ancillary charges, primarily the rebill of fuel and barge cleaning repairs.

Offshore revenues. An increase in offshore revenues of $0.3 million is primarily due to the full utilization of the fleet and increased transportation rates, offset by lower ancillary charges of $0.6 million, primarily the rebill of fuel.

Operating expenses. Operating expenses increased primarily as a result of $5.7 million of costs and expenses associated with the acquisitions of Talen's and Florida Marine Assets, increased crew wages of $1.5 million and $0.8 million related to property taxes.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased primarily as a result of decreased legal and consulting fees.

Depreciation and amortization. Depreciation and amortization decreased as a result of certain marine assets becoming fully depreciated and the disposal of equipment, partially offset by increases in depreciable assets related to recent capital expenditures.

Other operating income. Other operating income includes the gain on disposition of property, plant and equipment.

Equity in Earnings (Loss) of Unconsolidated Entities



	Three Months Ended September 30,						Variance			Percent Change
	2013			2012			Variance			Percent Change
	(In thousands)
Equity in earnings of Redbird	$	(984	)	$	(709	)	$	(275	)	(39)%
Equity in earnings of MET	577			—			577
Equity in earnings of Caliber	(170		)	(98		)	(72		)	(73)%
Equity in earnings of Pecos Valley	—			32			(32		)	(100)%
Equity in earnings (loss) of unconsolidated entities	$	(577	)	$	(775	)	$	198		26%

Equity in earnings of Redbird Gas Storage Partners LLC ("Redbird") decreased $0.3 million. The 2013 period includes a one-time charge for incentive payments resulting from the completion of the Cadeville Gas Storage, LLC (“Cadeville”) and Perryville Gas Storage, LLC (“Perryville”) projects ahead of schedule and under budget. Additionally, 2013 includes another one-time charge for employee severance costs related to the discontinuation of Cardinal's gas consulting business. The aggregate impact of these charges to the Partnership was $1.8 million. Improved Cardinal results of operations in 2013 attributable to Cadeville and Perryville partially offset the one-time charges.

Equity in earnings of Martin Energy Trading LLC (“MET”), recorded initially in April 2013, represent dividends on our 100% investment in its preferred interests. The MET investment was acquired in March 2013.

The $0.1 million decrease in equity in earnings of Caliber is attributable to Caliber's decrease in earnings for the three months ended September 30, 2013.

The Pecos Valley Producer Services LLC “Pecos Valley” investment was sold in September 2012.



	Nine Months Ended September 30,						Variance			Percent Change
	2013			2012			Variance			Percent Change
	(In thousands)
Equity in earnings of Redbird	$	(1,561	)	$	355		$	(1,916	)	(540)%
Equity in earnings of MET	1,171			—			1,171
Equity in earnings of Caliber	(488		)	(119		)	(369		)	(310)%
Equity in earnings of Pecos Valley	—			20			(20		)	(100)%
Equity in earnings (loss) of unconsolidated entities	$	(878	)	$	256		$	(1,134	)	(443)%

Equity in earnings of Redbird decreased $1.9 million. The 2013 period includes a one-time charge for incentive payments resulting from the completion of the Cadeville and Perryville projects ahead of schedule and under budget. Additionally, 2013 includes another one-time charge for employee severance costs related to the discontinuation of Cardinal's gas consulting business. The aggregate impact of these charges to the Partnership was $1.8 million. A $2.2 million milestone payment is included in Redbird's equity in earnings in the nine months ended September 30, 2012. No milestone payments were received in 2013. Improved Cardinal results of operations in 2013 resulting from Cadeville and Perryville partially offset the one-time charges and lack of a milestone payment in 2013.

Equity in earnings of MET, recorded initially in April 2013, represent dividends on our 100% investment in its preferred interests. The MET investment was acquired in March 2013.

Initial equity in earnings of Caliber Gathering, LLC “Caliber” were recorded in June 2012 while the nine month period ended September 30, 2013 includes the Partnership's share of Caliber results for all months.

The Pecos Valley Producer Services LLC “Pecos Valley” investment was sold in September 2012.

Interest Expense

Comparative Components of Interest Expense for the Three Months Ended September 30, 2013 and 2012



	Three Months Ended September 30,						Variance			Percent Change
	2013			2012			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	2,010		$	1,810		$	200		11%
8.875 % Senior notes	3,883			3,840			43			1%
7.250 % Senior notes	4,531			—			4,531
Amortization of deferred debt issuance costs	815			680			135			20%
Amortization of debt discount	77			77			—			—%
Interest costs attributable to the recast financial information of certain blending and packaging assets	—			526			(526		)	(100)%
Other	70			31			39			126%
Capitalized interest	(326		)	(175		)	(151		)	86%
Total interest expense	$	11,060		$	6,789		$	4,271		63%

Comparative Components of Interest Expense for the Nine Months Ended September 30, 2013 and 2012



	Nine Months Ended September 30,						Variance			Percent Change
	2013			2012			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	5,273		$	6,677		$	(1,404	)	(21)%
8.875 % Senior notes	11,648			12,530			(882		)	(7)%
7.250 % Senior notes	11,530			—			11,530
Amortization of deferred debt issuance costs	2,890			2,611			279			11%
Amortization of debt discount	230			504			(274		)	(54)%
Interest costs attributable to the recast financial information of certain blending and packaging assets	—			1,549			(1,549		)	(100)%
Other	231			212			19			9%
Capitalized interest	(744		)	(799		)	55			(7)%
Total interest expense	$	31,058		$	23,284		$	7,774		33%

Indirect Selling, General and Administrative Expenses



	Three Months Ended September 30,				Variance		Percent Change	Nine Months Ended September 30,				Variance		Percent Change
	2013		2012		Variance		Percent Change	2013		2012		Variance		Percent Change
	(In thousands)							(In thousands)
Indirect selling, general and administrative expenses	$	3,779	$	1,966	$	1,813	92%	$	11,720	$	6,733	$	4,987	74%

For both periods, indirect selling, general and administrative expenses increased primarily as a result of higher allocated overhead expenses from Martin Resource Management.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office 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. GAAP also permits 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 allocation for these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The Conflicts Committee of our general partner approved the following reimbursement amounts:



	Three Months Ended September 30,				Variance		Percent Change	Nine Months Ended September 30,				Variance		Percent Change
	2013		2012		Variance		Percent Change	2013		2012		Variance		Percent Change
	(In thousands)							(In thousands)
Conflicts Committee approved reimbursement amount	$	2,655	$	1,646	$	1,009	61%	$	7,966	$	4,937	$	3,029	61%

The amounts reflected above represent our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

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. We have recently completed several transactions that have improved our liquidity position, helping fund our acquisitions and organic growth projects. In February 2013, we received net proceeds of $245.1 million from a private placement of senior notes. In July 2012, we completed the sale of certain gas gathering and processing assets for approximately $273.3 million. We received $102.8 million and $91.4 million from follow on public offerings of common units in January and November 2012, respectively. Additionally, in March 2013, we made certain strategic amendments to our credit facility which provide for a maximum borrowing capacity of $600.0 million.

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, 2012, filed with the SEC on March 4, 2013, 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 March 28, 2013, we amended and restated our credit facility to (i) increase the maximum amount of borrowings and letters of credit under the Credit Agreement from $400.0 million to $600.0 million, (ii) extend the maturity date of all amounts outstanding under the Credit Agreement from April 15, 2016 to March 28, 2018, (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 us and certain of our 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.

On February 11, 2013, we completed a private placement of $250.0 million in aggregate principal amount of 7.250% senior unsecured notes due 2021 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $245.1 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility. On July 1, 2013, we filed a registration statement on Form S-4 with the SEC to exchange the Notes for registered 7.250% senior unsecured notes due February 2021. The exchange offer was completed on July 31, 2013.

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.

Equity Offerings

On November 26, 2012, we completed a public offering of 3,450,000 common units at a price of $31.16 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 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $102.8 million. Our general partner contributed $2.2 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

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. All of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

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, 2012, filed with the SEC on March 4, 2013, 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 - Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

The following table details the cash flow changes between the nine months ended September 30, 2013 and 2012:



	Nine Months Ended September 30,						Variance			Percent Change
	2013			2012			Variance			Percent Change
	(In thousands)
Net cash provided by (used in):
Operating activities	$	62,168		$	(9,461	)	$	71,629		757%
Investing activities	(167,119		)	181,397			(348,516		)	(192)%
Financing activities	99,834			(172,175		)	272,009			158%
Net decrease in cash and cash equivalents	$	(5,117	)	$	(239	)	$	(4,878	)	2,041%

Net cash provided by (used in) operating activities for the nine months ended September 30, 2013 increased compared to the prior year period mainly due to a $71.5 million favorable variance in the change in working capital. The primary working capital change that positively affected cash provided by operating activities during the nine months ended September 30, 2013 was the decrease in accounts and other receivables from December 31, 2012 to September 30, 2013. Revenues for the month of December were higher than the month of September in our Natural Gas Services segment due to seasonality, resulting in a decrease in receivables over the period. We saw an offsetting decrease in trade and other accounts payable as a result of seasonality in our Natural Gas Services segment, providing an unfavorable effect on cash flows provided by operating activities. Working capital changes negatively affecting cash provided by operating activities for the nine months ended September 30, 2012 include increases in product inventories in our terminalling and storage segments combined with decreases in accounts payable principally due to the timing of payments to vendors.

Net cash provided by (used in) investing activities for the nine months ended September 30, 2013 decreased compared to the prior year period mainly due to the proceeds received from the sale of our natural gas gathering and processing operations in the prior period of $275.0 million and $73.9 million in cash paid for acquisitions in the current year period.

Net cash provided by (used in) financing activities for the nine months ended September 30, 2013 increased compared to the prior period mainly due to (i) $250.0 million provided by the issuance of the 7.250% Senior Notes in the current period; (ii) $92.0 million in increased borrowings under our revolving credit facility in the current period; and (iii) offset by $91.4 million provided by the issuance common units during the previous period.

Capital Expenditures

Our operations require continual investment to upgrade or enhance operations and to ensure compliance with safety, operational, and environmental regulations. Our capital expenditures consist primarily of:

•maintenance capital expenditures made to maintain existing assets and operations

•expansion capital expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs

•plant turnaround costs made at our refinery to perform maintenance, overhaul and repair operations and to inspect, test and replace process materials and equipment.

The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In thousands)				(In thousands)
Expansion capital expenditures	$	36,999	$	18,852	$	61,118	$	67,947
Maintenance capital expenditures	2,973		1,325		7,473		3,603
Plant turnaround costs	—		175		—		2,578
Total	$	39,972	$	20,352	$	68,591	$	74,128

Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three and nine months ended September 30, 2013. Within our Terminalling and Storage segment, expenditures were made primarily at our Corpus Christi crude terminal, Smackover refinery, and certain smaller organic growth projects ongoing in our specialty terminalling operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Sulfur Services segments to maintain our existing assets and operations during the three and nine months ended September 30, 2013.

Expansion capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Sulfur Services segments during the three and nine months ended September 30, 2012. Within our Terminalling and Storage segment, expenditures were made primarily at our Corpus Christi crude terminal and Smackover refinery. Within our Marine Transportation segment, expenditures were made to upgrade certain assets in the inland fleet. Within our Sulfur Services segment, expenditures were made to expand operations at our Neches prilling facility. Maintenance capital expenditures were made primarily in our Terminalling and Storage and Sulfur Services segments to maintain our existing assets and operations during the three and nine months ended September 30, 2012. For the nine months ended September 30, 2012, plant turnaround costs include refinery turnaround expenditures at our Smackover refinery.

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, 2013, we had $651.2 million of outstanding indebtedness, consisting of outstanding borrowings of $423.6 million (net of unamortized discount) under our Senior Notes due in 2018 and 2021, $219.0 million under our revolving credit facility, $5.7 million under capital lease obligations, and $2.9 million under a note payable.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2013, 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	$	219,000	$	—	$	—	$	219,000	$	—
2018 Senior unsecured notes	173,619		—		—		173,619		—
2021 Senior unsecured notes	250,000		—		—		—		250,000
Note payable	2,885		2,885		—		—		—
Capital leases including current maturities	5,673		288		5,385		—		—
Non-competition agreements	50		50		—		—		—
Throughput commitment	45,554		4,912		10,301		10,974		19,367
Operating leases	48,947		11,873		20,749		9,665		6,660
Interest expense: ¹
Revolving credit facility	30,731		6,848		13,696		10,187		—
2018 Senior unsecured notes	71,184		15,531		31,062		24,591		—
2021 Senior unsecured notes	134,427		18,125		36,250		36,250		43,802
Note payable	71		71		—		—		—
Capital leases	2,425		881		1,544		—		—
Total contractual cash obligations	$	984,566	$	61,464	$	118,987	$	484,286	$	319,829

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

Letter of Credit. At September 30, 2013, 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

2021 Senior Notes

We and Martin Midstream Finance Corp., a subsidiary of us (collectively, the “Issuers”), entered into (i) an Indenture, dated as of February 11, 2013 (the “Indenture”) among the Issuers, certain subsidiary guarantors (the “Guarantors”) and Wells Fargo Bank, National Association, as trustee (the “Trustee”) and (ii) a Registration Rights Agreement, dated as of February 11, 2013 (the “Registration Rights Agreement”), among the Issuers, the Guarantors and Wells Fargo Securities, LLC, RBC Capital Markets, LLC, RBS Securities Inc., SunTrust Robinson Humphrey, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of a group of initial purchasers, in connection with a private placement to eligible purchasers of $250.0 million in aggregate principal amount of the Issuers' 7.250% senior unsecured notes due 2021 (the “2021 Notes”).

Interest and Maturity. On February 11, 2013, the Issuers issued the 2021 Notes pursuant to the Indenture in a transaction exempt from registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 2021 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 2021 Notes will mature on February 15, 2021. The interest payment dates are February 15 and August 15, beginning on August 15, 2013.

Optional Redemption. Prior to February 15, 2016, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the 2021 Notes issued under the Indenture, at a redemption price of 107.250% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the 2021 Notes with the proceeds of certain equity offerings. Prior to February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the

2021 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 February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the 2021 Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.625% for the twelve-month period beginning on February 15, 2017, 101.813% for the twelve-month period beginning on February 15, 2018 and 100.00% for the twelve-month period beginning on February 15, 2019 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2021 Notes.

Certain Covenants. The Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our 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 our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our 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 2021 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 2021 Notes; (ii) default in payment when due of the principal of, or premium, if any, on the 2021 Notes; (iii) failure by us to comply with certain covenants relating to asset sales, repurchases of the 2021 Notes upon a change of control and mergers or consolidations; (iv) failure by us for 180 days after notice to comply with our reporting obligations under the Securities Exchange Act of 1934; (v) failure by us 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 $20.0 million or more, subject to a cure provision; (vii) failure by us or any of our restricted subsidiaries to pay final judgments aggregating in excess of $20.0 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 2021 Notes, by notice to the Issuers and the Trustee, may declare the 2021 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 2021 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 2021 Notes for substantially identical notes that are registered under the Securities Act, and completed the exchange offer on July 31, 2013.

2018 Senior Notes

For a description of our 2018, 8.875% senior notes issued March 26, 2010, see “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Description of Our Long-Term Debt” in our Annual Report on Form 10-K for the year ended December 31, 2012.

Revolving 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 March 28, 2013 when we amended and restated our credit facility to (i) increase the maximum amount of borrowings and letters of credit under the credit facility from $400.0 million to $600.0 million, (ii) extend the maturity date of all amounts outstanding under the credit facility from April 15, 2016 to March 28, 2018, (iii) decrease the applicable interest rate margin on committed revolver loans under the credit facility 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 us 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.

As of September 30, 2013, we had $219.0 million outstanding under the revolving credit facility and $0.1 million of letters of credit issued, leaving $380.9 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 nine months ended September 30, 2013, the level of outstanding draws on our credit facility has ranged from a low of $40.0 million to a high of $298.0 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.

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 per annum on the unused revolving credit availability under the credit facility. The letter of credit fee, the commitment fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the 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 3.00 to 1.00	1.00	%	2.00	%	2.00	%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00	1.25	%	2.25	%	2.25	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00	1.50	%	2.50	%	2.50	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00	1.75	%	2.75	%	2.75	%
Greater than or equal to 4.50 to 1.00	2.00	%	3.00	%	3.00	%

The applicable margin for existing LIBOR borrowings is 2.50%. Effective October 1, 2013, the applicable margin for existing LIBOR borrowings remained at 2.50%. Effective January 1, 2014, the applicable margin for existing LIBOR borrowings will increase to 3.00%. As of November 4, 2013, our weighted average interest rate on our revolving credit facility is 2.80%.

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 5.25 to 1.00. The maximum permitted senior leverage ratio (as defined in the 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 3.50 to 1.00. The minimum interest coverage ratio (as defined in the 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 2.50 to 1.00.

In addition, the credit facility contains various covenants, which, among other things, limit our and our subsidiaries’ ability to: (i) grant or assume liens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur or assume indebtedness; (v) sell, transfer, assign or convey assets; (vi) 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; (vii) change the nature of our business; (viii) engage in transactions with affiliates; (ix) enter into certain burdensome agreements; (x) make

certain amendments to the omnibus agreement and our material agreements; (xi) make capital expenditures; and (xii) permit our joint ventures to incur indebtedness or grant certain liens.

The credit facility contains customary events of default, including, without limitation, (i) failure to pay any principal, interest, fees, expenses or other amounts when due; (ii) failure to meet the quarterly financial covenants; (iii) 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; (iv) the failure of any representation or warranty to be materially true and correct when made; (v) our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount; (vi) bankruptcy or other insolvency events involving us or any of our subsidiaries; (vii) judgments against us or any of our subsidiaries, in excess of a threshold amount; (viii) certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount; (ix) a change in control (as defined in the credit facility); and (x) the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under the credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility 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.

As of November 4, 2013, our outstanding indebtedness includes $214.0 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.

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 and the refinery blending season. The demand for fertilizers is strongest during the early spring planting season. However, our Terminalling and Storage and Marine Transportation segments and the molten sulfur business are typically not impacted by seasonal fluctuations. A significant portion of our net income is derived 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 segments.

Impact of Inflation

Inflation did not have a material impact on our results of operations for the three and nine months ended September 30, 2013 or 2012. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. 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, 2013 or 2012.



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 3.13% as of September 30, 2013. As of November 4, 2013, we had total indebtedness outstanding under our credit facility of $214.0 million, all of which was unhedged floating rate debt. As of November 4, 2013, our weighted average interest rate on our revolving credit facility is 2.80%. Based on the amount of unhedged floating rate debt owed by us on September 30, 2013, 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 $2.2 million annually.

We are not exposed to changes in interest rates with respect to our senior unsecured notes due in 2018 and 2021 as these obligations are fixed rates. The estimated fair value of our senior unsecured notes was approximately $441.7 million as of September 30, 2013, based on market prices of similar debt at September 30, 2013. 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 a $16.0 million decrease in fair value of our long-term debt at September 30, 2013.



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.

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 17 in Part I of this Form 10-Q.



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 4, 2013.



Item 6.	Exhibits

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

SIGNATURES

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



	Martin Midstream Partners L.P.

	By:	Martin Midstream GP LLC
		It’s General Partner

Date: November 4, 2013	By:	/s/ Ruben S. Martin
		Ruben S. Martin
		President and Chief Executive Officer

INDEX TO EXHIBITS



Exhibit Number	Exhibit Name

3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated 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 (SEC File No. 000-50056), 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 (SEC File No. 000-50056), 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 (SEC File No. 000-50056), 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 (SEC File No. 000-50056), 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	Amended and Restated Limited Liability Company Agreement of the General Partner, dated August 30, 2013 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (Reg. No. 000-50056), filed September 3, 2013, 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).
3.10	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 (SEC File No. 000-50056), filed March 26, 2010, and incorporated herein by reference).
4.4	First Supplemental Indenture, to the Indenture dated as of March 26, 2010, dated as of February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed March 4, 2013, and incorporated herein by reference).
4.5	Indenture (including form of 7.250% Senior Notes due 2021), dated as of February 11, 2013, 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 (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).
10.1	Third Amended and Restated Credit Agreement, dated March 28, 2013, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders set forth therein (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed April 3, 2013 and incorporated herein by reference).
10.2 *¹	Second Amended and Restated Sales Agency Agreement, dated August 5, 2013, between the Operating Partnership and Martin Product Sales, LLC.
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 September 30, 2013, formatted in Extensible Business Reporting Language: (1) the Consolidated and Condensed Balance Sheets; (2) the Consolidated and Condensed Statements of Income; (3) the Consolidated and Condensed Statements of Cash Flows; (4) the Consolidated and Condensed Statements of Capital; (5) the Consolidated and Condensed Statements of Other Comprehensive Income; and (6) the Notes to Consolidated and Condensed Financial Statements.

* Filed or furnished herewith

¹ Material has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended.