Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

2014.6.30 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 June 30, 2014



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 x	Accelerated filer o
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 July 31, 2014, was 30,639,432.



		Page

PART I – FINANCIAL INFORMATION		2

Item 1. Financial Statements		2
	Consolidated and Condensed Balance Sheets as of June 30, 2014 (unaudited) and December 31, 2013 (audited)	2
	Consolidated and Condensed Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013 (unaudited)	3
	Consolidated and Condensed Statements of Capital for the Six Months Ended June 30, 2014 and 2013 (unaudited)	5
	Consolidated and Condensed Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013 (unaudited)	6
	Notes to Consolidated and Condensed Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Item 3. Quantitative and Qualitative Disclosures about Market Risk		50

Item 4. Controls and Procedures		51

PART II. OTHER INFORMATION		52

Item 1. Legal Proceedings		52

Item 1A. Risk Factors		52

Item 6. Exhibits		52

PART I – FINANCIAL INFORMATION



Item 1.	Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)



	June 30, 2014			December 31, 2013
	(Unaudited)			(Audited)
Assets
Cash	$	2,704		$	16,542
Accounts and other receivables, less allowance for doubtful accounts of $1,807 and $2,492, respectively	145,418			163,855
Product exchange receivables	4,164			2,727
Inventories	113,346			94,902
Due from affiliates	21,915			12,099
Other current assets	11,173			7,353
Total current assets	298,720			297,478

Property, plant and equipment, at cost	970,170			929,183
Accumulated depreciation	(329,772		)	(304,808		)
Property, plant and equipment, net	640,398			624,375

Goodwill	23,802			23,802
Investment in unconsolidated entities	266,445			128,662
Debt issuance costs, net	14,191			15,659
Fair value of derivatives	547			—
Other assets, net	6,653			7,943
	$	1,250,756		$	1,097,919

Liabilities and Partners’ Capital
Trade and other accounts payable	$	121,578		$	142,951
Product exchange payables	22,078			9,595
Due to affiliates	6,555			2,596
Income taxes payable	818			1,204
Other accrued liabilities	18,806			20,242
Total current liabilities	169,835			176,588

Long-term debt	692,168			658,695
Other long-term obligations	2,020			2,219
Total liabilities	864,023			837,502

Commitments and contingencies
Partners’ capital	386,733			260,417
	$	1,250,756		$	1,097,919

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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Revenues:
Terminalling and storage *	$	34,167		$	27,420		$	65,968		$	56,311
Marine transportation *	22,153			25,497			45,563			50,477
Sulfur services	3,038			3,001			6,075			6,002
Product sales: *
Natural gas services	248,601			187,200			581,938			446,309
Sulfur services	59,543			57,895			110,713			125,279
Terminalling and storage	51,443			57,175			105,716			107,496
	359,587			302,270			798,367			679,084
Total revenues	418,945			358,188			915,973			791,874

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	238,622			181,523			559,320			430,301
Sulfur services *	45,315			44,786			83,168			97,583
Terminalling and storage *	46,806			50,273			94,835			94,088
	330,743			276,582			737,323			621,972
Expenses:
Operating expenses *	48,256			43,035			92,152			86,395
Selling, general and administrative *	8,745			6,383			17,351			13,413
Depreciation and amortization	14,594			12,353			28,586			24,246
Total costs and expenses	402,338			338,353			875,412			746,026

Other operating income	99			424			54			796
Operating income	16,706			20,259			40,615			46,644

Other income (expense):
Equity in earnings (loss) of unconsolidated entities	1,938			73			1,642			(301		)
Interest expense	(11,441		)	(10,940		)	(22,892		)	(19,998		)
Debt prepayment premium	(7,767		)	—			(7,767		)	—
Other, net	(50		)	(14		)	(117		)	(23		)
Total other expense	(17,320		)	(10,881		)	(29,134		)	(20,322		)

Net income (loss) before taxes	(614		)	9,378			11,481			26,322
Income tax expense	(354		)	(300		)	(654		)	(607		)
Net income (loss)	(968		)	9,078			10,827			25,715
Less general partner's interest in net (income) loss	19			(181		)	(217		)	(514		)
Less (income) loss allocable to unvested restricted units	3			(23		)	(29		)	(66		)
Limited partners' interest in net income (loss)	$	(946	)	$	8,874		$	10,581		$	25,135

Net income (loss) per unit attributable to limited partners - basic	$	(0.03	)	$	0.33		$	0.38		$	0.95
Weighted average limited partner units - basic	28,924			26,558			27,757			26,561

Net income (loss) per unit attributable to limited partners - diluted	$	(0.03	)	$	0.33		$	0.38		$	0.95
Weighted average limited partner units - diluted	28,924			26,579			27,791			26,577

See accompanying notes to consolidated and condensed financial statements.

*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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Revenues:
Terminalling and storage	$	18,743	$	17,485	$	36,753	$	34,813
Marine transportation	6,415		6,042		12,264		12,885
Product Sales	3,709		1,839		5,601		3,048
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	10,808		7,036		19,261		15,592
Sulfur services	4,452		4,441		9,317		8,975
Terminalling and storage	6,553		14,189		16,397		26,150
Expenses:
Operating expenses	19,248		17,534		37,487		35,508
Selling, general and administrative	5,489		4,170		10,873		8,588

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)



	Partners’ Capital
	Common Limited					General Partner Amount
	Units		Amount			General Partner Amount			Total
Balances - January 1, 2013	26,566,776		$	349,490		$	8,472		$	357,962
Net income	—		25,201			514			25,715
Issuance of restricted units	63,750		—			—			—
Forfeiture of restricted units	(250	)	—			—			—
General partner contribution	—		—			37			37
Cash distributions	—		(41,135		)	(917		)	(42,052		)
Unit-based compensation	—		479			—			479
Purchase of treasury units	(6,000	)	(250		)	—			(250		)
Balances - June 30, 2013	26,624,276		$	333,785		$	8,106		$	341,891

Balances - January 1, 2014	26,625,026		$	254,028		$	6,389		$	260,417
Net income	—		10,610			217			10,827
Issuance of common units	4,017,156		160,514			—			160,514
Issuance of restricted units	6,900		—			—			—
Forfeiture of restricted units	(3,250	)	—			—			—
General partner contribution	—		—			3,407			3,407
Cash distributions	—		(42,192		)	(953		)	(43,145		)
Unit-based compensation	—		387			—			387
Excess purchase price over carrying value of acquired assets	—		(5,397		)	—			(5,397		)
Purchase of treasury units	(6,400	)	(277		)	—			(277		)
Balances - June 30, 2014	30,639,432		$	377,673		$	9,060		$	386,733

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)



	Six Months Ended
	June 30,
	2014			2013
Cash flows from operating activities:
Net income	$	10,827		$	25,715
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	28,586			24,246
Amortization of deferred debt issuance costs	4,588			2,075
Amortization of debt discount	1,305			153
Amortization of premium on notes payable	(82		)	—
Gain on sale of property, plant and equipment	(54		)	(796		)
Equity in (earnings) loss of unconsolidated entities	(1,642		)	301
Non-cash mark-to-market on derivatives	(547		)	—
Unit-based compensation	387			479
Preferred dividends on MET investment	1,116			—
Other	—			6
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	15,962			66,658
Product exchange receivables	(1,437		)	1,694
Inventories	(18,444		)	4,946
Due from affiliates	(9,816		)	(17,657		)
Other current assets	(1,430		)	(3,530		)
Trade and other accounts payable	(23,574		)	(29,256		)
Product exchange payables	12,483			(1,211		)
Due to affiliates	3,959			89
Income taxes payable	(386		)	53
Other accrued liabilities	(1,449		)	7,694
Change in other non-current assets and liabilities	597			(563		)
Net cash provided by continuing operating activities	20,949			81,096
Net cash used in discontinued operating activities	—			(8,678		)
Net cash provided by operating activities	20,949			72,418
Cash flows from investing activities:
Payments for property, plant and equipment	(41,237		)	(28,621		)
Acquisitions	(1,991		)	(63,004		)
Payments for plant turnaround costs	(3,910		)	—
Proceeds from sale of property, plant and equipment	702			4,719
Proceeds from involuntary conversion of property, plant and equipment	2,475			—
Investment in unconsolidated entities	(134,413		)	(15,000		)
Return of investments from unconsolidated entities	2,425			1,357
Contributions to unconsolidated entities	(3,070		)	(15,578		)
Net cash used in investing activities	(179,019		)	(116,127		)
Cash flows from financing activities:
Payments of long-term debt	(885,000		)	(439,000		)
Payments of notes payable and capital lease obligations	—			(160		)
Proceeds from long-term debt	917,250			529,000
Net proceeds from issuance of common units	160,514			—
General partner contribution	3,407			37
Purchase of treasury units	(277		)	(250		)
Payment of debt issuance costs	(3,120		)	(9,011		)
Excess purchase price over carrying value of acquired assets	(5,397		)	—
Cash distributions paid	(43,145		)	(42,052		)
Net cash provided by financing activities	144,232			38,564
Net decrease in cash	(13,838		)	(5,145		)
Cash at beginning of period	16,542			5,162
Cash at end of period	$	2,704		$	17
Non-cash additions to property, plant and equipment	$	3,111		$	—

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)

June 30, 2014

(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 “U.S.” 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, 2013, filed with the Securities and Exchange Commission (the “SEC”) on March 3, 2014, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2013 filed on March 28, 2014.

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.

Prior to August 30, 2013, Martin Resource Management owned 100% of the Partnership's general partner. 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”), the 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.


(2)	New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is evaluating the effect that ASU 2014-09 will have on its consolidated and condensed financial statements and related disclosures. The Partnership has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

In April 2014, the FASB issued No. ASU 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The ASU changes the requirements for reporting discontinued operations. A discontinued operation may include a component of an entity or a group of components of an entity, or a business. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. Examples include a disposal of a major geographic area, a major line of business or a major equity method investment. Additionally, the update requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income and expenses of discontinued operations. This update is effective prospectively for the Partnership's fiscal year beginning January 1, 2015 and early adoption is permitted. The standard primarily involves presentation and disclosure and therefore is not expected to have a material impact on the Partnership's financial condition, results of operations or cash flows.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)


(3)	Acquisitions

NGL Storage Assets

On May 31, 2014, the Partnership acquired certain NGL storage assets from a subsidiary of Martin Resource Management for $7,388. 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 the purchase in the following allocation:



Property, plant and equipment	2,004
Current liabilities	(13		)
	$	1,991

The excess of the purchase price over the carrying value of the assets of $5,397 was recorded as an adjustment to "Partners' capital". This transaction was funded with borrowings under the Partnership's revolving credit facility. As no individual line item of the historical financial statements of the assets was in excess of 3% of the Partnership's relative financial statement captions, the Partnership elected not to retrospectively recast the historical financial information of these assets.

West Texas LPG Pipeline Limited Partnership

On May 14, 2014, the Partnership acquired from a subsidiary of Atlas Pipeline Partners L.P. ("Atlas"), all of the outstanding membership interests in Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC (collectively, "Atlas Holdings") for cash of approximately $134,400, subject to certain post-closing adjustments. This transaction was recorded in "Investments in unconsolidated entities" in the Partnership's Consolidated and Condensed Balance Sheet through a preliminary purchase price allocation. The final allocation is expected to be completed by December 31, 2014. Atlas Holdings owns a 19.8% limited partnership interest and a 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). WTLPG is operated by Chevron Pipe Line Company, which owns the remaining 80.0% interest. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This acquisition will enable the Partnership to participate in the transportation of the growing NGL production of West Texas and other basins along the WTLPG pipeline route. This acquisition of the WTLPG business complements the Partnership's existing East Texas NGL pipeline that delivers Y-grade NGLs from East Texas production areas into Beaumont, Texas on a smaller scale. This transaction was funded with borrowings under the Partnership's revolving credit facility.

The following unaudited pro forma consolidated results of operations have been prepared as if the acquisition of WTLPG occurred at the beginning of fiscal 2013:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)



	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014		2013
Revenue:
As reported	$	418,945		$	358,188	$	915,973	$	791,874
Pro forma	$	418,945		$	358,188	$	915,973	$	791,874
Net income attributable to limited partners:
As reported	$	(946	)	$	8,874	$	10,581	$	25,135
Pro forma	$	(334	)	$	9,719	$	11,897	$	26,815
Net income per unit attributable to limited partners - basic
As reported	$	(0.03	)	$	0.33	$	0.38	$	0.95
Pro forma	$	(0.01	)	$	0.37	$	0.43	$	1.01
Net income per unit attributable to limited partners - diluted
As reported	$	(0.03	)	$	0.33	$	0.38	$	0.95
Pro forma	$	(0.01	)	$	0.37	$	0.43	$	1.01

The pro forma amounts have been determined by calculating the Partnership's equity in earnings WTLPG and adjusting the results to reflect additional interest expense and amortization of the investment in excess of the underlying net assets.

Marine Transportation Equipment Purchase

On September 30, 2013, the Partnership acquired two previously leased 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 (“Cactus”) 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 $479 and net income of $43 for the three months ended June 30, 2014 and revenues of $1,146 and net income of $234 for the six months ended June 30, 2014.

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

by the Partnership were recorded in the Terminalling and Storage segment at fair value of $12,148 in the following purchase price allocation:



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 from the NLG acquisition included revenues of $4,111 and net income of $112 for the three months ended June 30, 2014 and revenues of $521 and net loss of $156 for the three months ended June 30, 2013. Results of operations included revenues of $7,763 and net income of $130 for the six months ended June 30, 2014 and revenues of $521 and net loss of $156 for the six months ended June 30, 2013.

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.


(4)	Discontinued operations and divestitures

On July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas 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.

Cash flows resulting from balances existing at December 31, 2012 were reported in the Consolidated and Condensed Statements of Cash Flows as discontinued operations for the six months ended June 30, 2013.


(5)	Inventories

Components of inventories at June 30, 2014 and December 31, 2013 were as follows:



	June 30, 2014		December 31, 2013
Natural gas liquids	$	46,693	$	31,859
Sulfur	14,398		8,912
Sulfur based products	14,603		17,584
Lubricants	34,594		33,847
Other	3,058		2,700
	$	113,346	$	94,902


(6)	Investments in Unconsolidated Entities and Joint Ventures

On May 14, 2014, the Partnership acquired from a subsidiary of Atlas, all of the outstanding membership interests in Atlas Holdings for cash of approximately $134,400, subject to certain post-closing adjustments. Atlas Holdings owns a 19.8% limited partnership interest and a 0.2% general partnership interest in WTLPG. WTLPG is operated by Chevron Pipe Line Company, which owns the remaining 80.0% interest. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. At the acquisition date, the carrying value of the 20% interest in WTLPG exceeded the Partnership’s share of the underlying net assets of WTLPG by approximately $96,000. The Partnership’s preliminary analysis determined that approximately $48,000 of the difference is attributable to property plant and equipment and the remaining $48,000 to equity method goodwill. The Partnership expects to complete its final analysis by December 31, 2014. The excess attributable to property, plant and equipment will be amortized over approximately 35 years. Such amortization amounted to $171 for the three and six months ended June 30, 2014. The Partnership recognizes its 20% interest in WTLPG as "Investment in unconsolidated entities" on its Consolidated and Condensed Balance Sheets. The Partnership accounts for its ownership interest in WTLPG under the equity method of accounting, with recognition of its ownership interest in the income of WTLPG as "Equity in earnings of unconsolidated entities" on its Consolidated and Condensed Statements of Operations.

At June 30, 2014, the Partnership owned an unconsolidated 42.17% interest in Cardinal Gas Storage Partners LLC (“Cardinal”).

During the fourth quarter of 2013, the Partnership sold its 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

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:



	June 30, 2014		December 31, 2013
WTLPG	$	135,182	$	—
Cardinal	116,263		113,662
MET	15,000		15,000
Total investment in unconsolidated entities	$	266,445	$	128,662



	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014			2013
Equity in earnings of WTLPG	$	769	$	—		$	769		$	—
Equity in earnings (loss) of Cardinal	608		(362		)	(243		)	(578		)
Equity in earnings of MET	561		594			1,116			594
Equity in loss of Caliber	—		(159		)	—			(317		)
Equity in earnings of unconsolidated entities	$	1,938	$	73		$	1,642		$	(301	)

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



	As of June 30,				Three Months Ended June 30,					Six Months Ended June 30,
	Total Assets		Members' Equity		Revenues		Net Income			Revenues		Net Income (Loss)
2014
WTLPG	$	208,657	$	195,693	$	25,950	$	10,071		$	47,914	$	20,601
Cardinal	$	646,424	$	353,511	$	16,914	$	2,353		$	35,343	$	(605	)
	As of December 31,
2013
Cardinal	$	661,816	$	346,584	$	10,708	$	(392	)	$	18,795	$	59

As of June 30, 2014 and December 31, 2013, the Partnership’s interest in cash of the unconsolidated equity-method investees was $8,652 and $3,703, respectively.


(7)	Derivative Instruments and Hedging Activities

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

(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 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. The Partnership did not have any commodity derivative instruments outstanding during the six months ended June 30, 2014 or 2013.

(b) Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit facility and it's senior unsecured notes. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings.

As of June 30, 2014, we had a combined notional principal amount of $200,000 of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with a portion of the Partnership's 2021 senior unsecured notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. Each of the Partnership's swap agreements have a termination date that corresponds to the maturity date of the 2021 senior unsecured notes and, as of June 30, 2014, the maximum length of time over which the Partnership has hedged a portion of its exposure to the variability in the value of this debt due to interest rate risk is through February of 2021.

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

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



	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	June 30, 2014		December 31, 2013		Balance Sheet Location	June 30, 2013		December 31, 2013
Derivatives not designated as hedging instruments:	Non Current:					Non Current:
Interest rate contracts	Fair value of derivatives	$	547	$	—	Fair value of derivatives	$	—	$	—
Total derivatives not designated as hedging instruments		$	547	$	—		$	—	$	—

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

Effect of Derivative Instruments on the Consolidated and Condensed Statement of Operations

For the Three Months Ended June 30, 2014 and 2013



	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income on Derivatives
		2014		2013
Derivatives not designated as hedging instruments:
Interest rate contracts	Interest expense	$	2,927	$	—
Total derivatives not designated as hedging instruments		$	2,927	$	—

Effect of Derivative Instruments on the Consolidated and Condensed Statement of Operations

For the Six Months Ended June 30, 2014 and 2013



	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income on Derivatives
		2014		2013
Derivatives not designated as hedging instruments:
Interest rate contracts	Interest expense	$	2,927	$	—
Total derivatives not designated as hedging instruments		$	2,927	$	—

On April 1, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements with an aggregate notional amount of $100,000 each to hedge its exposure to changes in the fair value of its senior unsecured notes. On May 14, the Partnership terminated these swaps and received a termination benefit of $2,380 upon cancellation of these swap agreements. Additionally, subsequent to the termination on May 14, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements on May 14, 2014 with an aggregate notional amount of $100,000 each to hedge its exposure to changes in the fair value of its senior unsecured notes.


(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)

June 30, 2014

(Unaudited)

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at June 30, 2014 and December 31, 2013:



	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	June 30, 2014		(Level 1)		(Level 2)		(Level 3)
Assets
Interest rate contracts	$	547	$	—	$	547	$	—
Total assets	$	547	$	—	$	547	$	—

Liabilities
2021 Senior unsecured notes	$	424,876	$	—	$	424,876	$	—
Total liabilities	$	424,876	$	—	$	424,876	$	—



	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, 2013		(Level 1)		(Level 2)		(Level 3)
Liabilities
2018 Senior unsecured notes	$	185,816	$	—	$	185,816	$	—
2021 Senior unsecured notes	258,004		—		258,004		—
Total liabilities	$	443,820	$	—	$	443,820	$	—

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.


(9)	Other Accrued Liabilities

Components of other accrued liabilities were as follows:



	June 30, 2014		December 31, 2013
Accrued interest	$	10,966	$	11,038
Property and other taxes payable	5,402		6,785
Accrued payroll	2,169		2,186
Other	269		233
	$	18,806	$	20,242

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)


(10)	Long-Term Debt

At June 30, 2014 and December 31, 2013, long-term debt consisted of the following:



	June 30, 2014		December 31, 2013
$900,000³ Revolving credit facility at variable interest rate (2.97%¹ weighted average at June 30, 2014), 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	$	290,000	$	235,000
$200,000² Senior notes, 8.875% interest, net of unamortized discount of $0 and $1,305, respectively, issued March 2010 and due April 2018, unsecured	—		173,695
$400,000 Senior notes, 7.250% interest, including unamortized premium of $2,168 and $0, issued $250,000 February 2013 and $150,000 April 2014, due February 2021, unsecured²	402,168		250,000
Total long-term debt	692,168		658,695
Less current installments	—		—
Long-term debt, net of current installments	$	692,168	$	658,695

¹ 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 at June 30, 2014 is 2.75%. The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Partnership's omnibus agreement with Martin Resource Management (the "Omnibus Agreement"). The Partnership is permitted to make quarterly distributions so long as no event of default exists.

² Pursuant to the Indenture under which the Senior Notes due in 2018 were issued, the Partnership had 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 1, 2014, the Partnership redeemed the remaining $175,000 of the 8.875% senior unsecured notes due in 2018 from all holders. On April 1, 2014, the Partnership completed a private placement add-on of $150,000 in aggregate principal amount of 7.250% senior unsecured notes due February 2021 to qualified institutional buyers under Rule 144A. The Partnership filed with the SEC a registration statement to exchange these notes for substantially identical notes that are registered under the Securities Act and commenced an exchange offer on April 28, 2014. The exchange offer was completed during the second quarter of 2014. In conjunction with this redemption, the Partnership incurred a debt prepayment premium of $7,767, on the Partnership's Consolidated and Condensed Statement of Operations for the three and six months ended June 30, 2014. Also in conjunction with the redemption, the Partnership expensed $2,643 and $1,228 of unamortized debt issuance costs and unamortized discount on notes payable, respectively, which is included in "Interest expense" on the Partnership's Consolidated and Condensed Statement of Operations for the three and six months ended June 30, 2014.

³ On June 27, 2014, the Partnership increased the maximum amount of borrowings and letters of credit available under the Partnership's revolving credit facility from $637,500 to $900,000.

The Partnership paid cash interest in the amount of $6,735 and $9,391 for the three months ended June 30, 2014 and 2013, respectively. The Partnership paid cash interest in the amount of $18,424 and $11,608 for the six months ended June 30, 2014 and 2013, respectively. Capitalized interest was $335 and $238 for the three months ended June 30, 2014 and 2013, respectively. Capitalized interest was $723 and $418 for the six months ended June 30, 2014 and 2013, respectively.


(11)	Partners' Capital

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

As of June 30, 2014, partners’ capital consisted of 30,639,432 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 16.6% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2% general partnership interest. Martin Resource Management controls the Partnership's general partner, by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner.

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 May 12, 2014, the Partnership completed a public offering of 3,600,000 common units at a price of $41.51 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 3,600,000 common units, net of underwriters' discounts, commissions and offering expenses were $143,431. The Partnership's general partner contributed $3,049 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 pay down outstanding amounts under the Partnership's revolving credit facility.

In March 2014, the Partnership entered into an equity distribution agreement with multiple underwriters (the “Sales Agents”) for the ongoing distribution of the Partnership's common units. Pursuant to this program, the Partnership offered and sold common unit equity through the Sales Agents for aggregate proceeds of $11,848 and $17,083 during the three and six months ended June 30, 2014, respectively. Common units issued were at market prices prevailing at the time of the sale. The Partnership also received capital contributions from the general partner of $243 and $356 during the three and six months ended June 30, 2014, respectively, to maintain its 2.0% general partner interest in the Partnership. The net proceeds from the common unit issuances were used to pay down outstanding amounts under the Partnership's revolving credit facility.

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. Additionally, on May 5, 2014, the owner of our general partner agreed to forego an additional $3,000 in incentive distributions. No incentive distributions were allocated to the general partner from July 1, 2012 through June 30, 2014. As of June 30, 2014, the amount of incentive distributions the general partner has foregone is $14,187, resulting in an amount remaining of $6,813.

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.

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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

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 allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net income (loss) attributable to Martin Midstream Partners L.P.	$	(968	)	$	9,078		$	10,827		$	25,715
Less general partner’s interest in net income:
Distributions payable on behalf of general partner interest	482			461			954			917
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	(501		)	(280		)	(737		)	(403		)
Less income allocable to unvested restricted units	(3		)	23			29			66
Limited partners’ interest in net income (loss)	$	(946	)	$	8,874		$	10,581		$	25,135

The weighted average units outstanding for basic net income per unit were 28,923,513 and 27,757,304 for the three and six months ended June 30, 2014, respectively, and 26,558,028 and 26,561,218 for the three and six months ended June 30, 2013, respectively. All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. All common unit equivalents were antidilutive for the three months ended June 30, 2014 because the limited partners were allocated a net loss in this period. For diluted net income per unit, the weighted average units outstanding were increased by 33,350 for the six months ended June 30, 2014, and 21,284 and 15,496 for the three and six months ended June 30, 2013, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.


(12)	Related Party Transactions

As of June 30, 2014, Martin Resource Management owned 5,093,267 of the Partnership’s common units representing approximately 16.6% of the Partnership’s outstanding limited partnership units. Martin Resource Management controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. 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 June 30, 2014, of approximately 16.6% 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:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

Omnibus Agreement

Omnibus Agreement. The Partnership and its general partner are parties to the Omnibus Agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain Martin Resource Management 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;

•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 environmental consulting company;


◦	operating an engineering services company;


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


◦	operating a natural gas optimization 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)


•	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 of the board of directors of the general partner of the Partnership (the "Conflicts Committee"); and

•

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

Services. Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

Effective January 1, 2014, through December 31, 2014, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $12,535. The Partnership reimbursed Martin Resource Management for $3,134 and $2,655 of indirect expenses for the three months ended June 30, 2014 and 2013, respectively. The Partnership reimbursed Martin Resource Management for $6,268 and $5,311 of indirect expenses for the six months ended June 30, 2014 and 2013, 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. 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 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. 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

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.

Indemnification. Martin Transport, Inc. has indemnified the Partnership against all claims arising out of the negligence or willful misconduct of Martin Transport, Inc. and its officers, employees, agents, representatives and subcontractors. The Partnership indemnified Martin Transport, Inc. against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport, Inc. and the Partnership, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.

Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. 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 a 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 Marine & Fuel LLC ("Talens") 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 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

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 a second amended and restated sulfuric acid sales agency agreement dated August 5, 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.

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 June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Revenues:
Terminalling and storage	$	18,743	$	17,485	$	36,753	$	34,813
Marine transportation	6,415		6,042		12,264		12,885
Product sales:
Natural gas services	2,217		—		3,046		9
Sulfur services	1,268		1,518		2,223		2,651
Terminalling and storage	224		321		332		388
	3,709		1,839		5,601		3,048
	$	28,867	$	25,366	$	54,618	$	50,746

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

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	$	10,808	$	7,036	$	19,261	$	15,592
Sulfur services	4,452		4,441		9,317		8,975
Terminalling and storage	6,553		14,189		16,397		26,150
	$	21,813	$	25,666	$	44,975	$	50,717

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



Operating Expenses:
Marine transportation	$	8,823	$	9,505	$	18,487	$	19,563
Natural gas services	798		469		1,404		954
Sulfur services	2,034		1,935		3,520		4,290
Terminalling and storage	7,593		5,625		14,076		10,701
	$	19,248	$	17,534	$	37,487	$	35,508

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



Selling, general and administrative:
Marine transportation	$	7	$	15	$	15	$	30
Natural gas services	1,146		409		2,104		988
Sulfur services	820		806		1,663		1,612
Terminalling and storage	343		283		728		644
Indirect overhead allocation, net of reimbursement	3,173		2,657		6,363		5,314
	$	5,489	$	4,170	$	10,873	$	8,588


(13)	Income Taxes

The operations of the Partnership are generally not subject to income taxes because its income is taxed directly to its partners.

The Partnership is subject to the Texas margin tax which 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 $354 and $300 were recorded in income tax expense for the three months ended June 30, 2014 and 2013, respectively. State income taxes attributable to the Texas margin tax of $654 and $607 were recorded in income tax expense for the six months ended June 30, 2014 and 2013, respectively.


(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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

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, 2013, filed with the SEC on March 3, 2014, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2013 filed on March 28, 2014. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Three Months Ended June 30, 2014
Terminalling and storage	$	86,917	$	(1,307	)	$	85,610	$	9,415	$	8,365		$	13,798
Natural gas services	248,670		—			248,670		675		5,815			74
Sulfur services	62,581		—			62,581		2,031		7,886			1,633
Marine transportation	23,282		(1,198		)	22,084		2,473		(522		)	4,258
Indirect selling, general and administrative	—		—			—		—		(4,838		)	—
Total	$	421,450	$	(2,505	)	$	418,945	$	14,594	$	16,706		$	19,763



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Three Months Ended June 30, 2013
Terminalling and storage	$	85,762	$	(1,167	)	$	84,595	$	7,297	$	8,635		$	12,319
Natural gas services	188,715		—			188,715		554		4,930			—
Sulfur services	60,896		—			60,896		1,957		7,701			422
Marine transportation	25,021		(1,039		)	23,982		2,545		2,541			1,165
Indirect selling, general and administrative	—		—			—		—		(3,548		)	—
Total	$	360,394	$	(2,206	)	$	358,188	$	12,353	$	20,259		$	13,906



Six Months Ended June 30, 2014	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Terminalling and storage	$	174,214	$	(2,530	)	$	171,684	$	18,390	$	16,676		$	29,396
Natural gas services	582,303		—			582,303		1,179		15,280			574
Sulfur services	116,788		—			116,788		4,014		15,954			3,081
Marine transportation	47,396		(2,198		)	45,198		5,003		2,440			8,186
Indirect selling, general and administrative	—		—			—		—		(9,735		)	—
Total	$	920,701	$	(4,728	)	$	915,973	$	28,586	$	40,615		$	41,237

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)



Six Months Ended June 30, 2013	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Terminalling and storage	$	166,115	$	(2,308	)	$	163,807	$	14,393	$	18,618		$	26,368
Natural gas services	448,154		—			448,154		846		13,392			115
Sulfur services	131,281		—			131,281		3,923		17,045			623
Marine transportation	50,253		(1,621		)	48,632		5,084		5,080			1,515
Indirect selling, general and administrative	—		—			—		—		(7,491		)	—
Total	$	795,803	$	(3,929	)	$	791,874	$	24,246	$	46,644		$	28,621

The Partnership's assets by reportable segment as of June 30, 2014 and December 31, 2013, are as follows:



	June 30, 2014		December 31, 2013
Total assets:
Terminalling and storage	$	471,891	$	461,160
Natural gas services	455,515		320,631
Sulfur services	159,361		151,982
Marine transportation	163,989		164,146
Total assets	$	1,250,756	$	1,097,919


(15)	Unit Based Awards

The Partnership recognizes compensation cost related to unit-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to unit-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 June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Employees	$	156	$	155	$	284	$	351
Non-employee directors	52		68		103		128
Total unit-based compensation expense	$	208	$	223	$	387	$	479

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 (the "Compensation Committee").

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

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 six months ended June 30, 2014 is provided below:



	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	72,998			$	33.08
Granted	6,900			$	41.10
Vested	(5,750		)	$	39.67
Forfeited	(3,250		)	$	31.06
Non-Vested, end of period	70,898			$	33.40

Aggregate intrinsic value, end of period	$	2,940

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 six months ended June 30, 2014 and 2013 are provided below:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Aggregate intrinsic value of units vested	$	—	$	—	$	249	$	153
Fair value of units vested	$	—	$	—	$	247	$	157

As of June 30, 2014, there was $1,426 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.97 years.

Unit Options. The plan currently permits the grant of options covering common units. As of July 31, 2014, 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2014

(Unaudited)

Since December 31, 2012, the Partnership has added Redbird Gas Storage LLC, MOP Midstream Holdings LLC, Martin Midstream NGL Holdings, LLC and Martin Midstream NGL Holdings II, LLC as subsidiary guarantors to its outstanding senior unsecured 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)	Subsequent Events

Quarterly Distribution. On July 24, 2014, the Partnership declared a quarterly cash distribution of $0.7925 per common unit for the second quarter of 2014, or $3.17 per common unit on an annualized basis, which will be paid on August 14, 2014 to unitholders of record as of August 7, 2014.



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, 2013, filed with the Securities and Exchange Commission (the “SEC”) on March 3, 2014, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2013 filed on March 28, 2014, 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 June 30, 2014, Martin Resource Management owned 16.6% 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”), the 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.

We entered into 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 our use of certain of Martin Resource Management’s trade names and trademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business and operating our assets.

The historical operation of our business segments by Martin Resource Management provides us with several decades of experience and a demonstrated track record of customer service across our operations. Our current lines of business have been developed and systematically integrated over this period of more than 60 years, including natural gas services (1950s); sulfur (1960s); marine transportation (late 1980s); and terminalling and storage (early 1990s). This development of a diversified and integrated set of assets and operations has produced a complementary portfolio of midstream services that facilitates the maintenance of long-term customer relationships and encourages the development of new customer relationships.

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 across our multiple business platforms.

Amendment to Revolving Credit Facility. On June 27, 2014, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $637.5 million to $900.0 million. In addition, we amended certain financial covenants that govern our credit facility.

NGL Storage Assets. On May 31, 2014, we acquired certain NGL storage assets from Martin Resource Management for $7.4 million. This transaction was funded with borrowings under our revolving credit facility.

West Texas LPG Pipeline Limited Partnership. On May 14, 2014, we acquired from a subsidiary of Atlas Pipeline Partners L.P. ("Atlas"), all of the outstanding membership interests in Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC (collectively, "Atlas Holdings") for cash of approximately $134.4 million, subject to certain post-closing adjustments. Atlas Holdings owns a 19.8% limited partnership interest and a 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). WTLPG is operated by Chevron Pipe Line Company, which owns the remaining 80.0% interest. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This transaction was funded with borrowings under our revolving credit facility.

Public Offering. On May 12, 2014, the Partnership completed a public offering of 3,600,000 common units at a price of $41.51 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 3,600,000 common units, net of underwriters' discounts, commissions and offering expenses were $143.4 million. Our general partner contributed $3.1 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 under our revolving credit facility.

Issuance of 7.250% Senior Unsecured Notes Due 2021. On April 1, 2014, we completed a private placement add-on of $150.0 million of the 7.250% senior unsecured notes. We filed with the SEC a registration statement on Form S-4 to exchange these notes for substantially identical notes that are registered under the Securities Act and commenced an exchange offer on April 28, 2014. The exchange offer was completed during the second quarter of 2014.

Redemption of 8.875% Senior Unsecured Notes Due 2018. On April 1, 2014, we redeemed all $175.0 million of the 8.875% senior unsecured notes due in 2018 from their holders. In conjunction with the redemption, the Partnership incurred a debt prepayment premium of $7.8 million and a non-cash charge of $3.9 million for the write-off of unamortized debt issuance costs and unamortized debt discount related to the redemption of the senior unsecured notes.

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, 2013. The following table evaluates the potential impact of estimates utilized during the periods ended June 30, 2014 and 2013:



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 $0.2 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 $5.9 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 June 30, 2014 and 2013. 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.
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 environmental consulting company;


•	operating an engineering services company;


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


•	operating a natural gas optimization 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 approximately 16.6% of the outstanding limited partner units. In addition, Martin Resource Management controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, the 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 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 $43.4 million of direct costs and expenses for the three months ended June 30, 2014 compared to $44.7 million for the three months ended June 30, 2013.We reimbursed Martin Resource Management for $87.0 million of direct costs and expenses for the six months ended June 30, 2014 compared to $89.5 million for the six months ended June 30, 2013. 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 June 30, 2014 and 2013, the conflicts committee of our general partner (“Conflicts Committee”) approved reimbursement amounts of $3.1 million and $2.7 million, respectively, reflecting our allocable share of such expenses. For the six months ended June 30, 2014 and 2013, the Conflicts Committee approved reimbursement amounts of $6.3 million and $5.3 million, respectively. 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, 2013, filed with the SEC on March 3, 2014, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2013 filed on March 28, 2014.

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.

In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 7% and 9% of our total cost of products sold during the three months ended June 30, 2014 and 2013, respectively. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 6% and 8% of our total cost of products sold during the six months ended June 30, 2014 and 2013, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

In the aggregate, the impact of related party transactions included in revenues accounted for approximately 7% of our total revenues for both the three months ended June 30, 2014 and 2013, respectively. Our sales to Martin Resource Management accounted for approximately 6% of our total revenues for both the six months ended June 30, 2014 and 2013, respectively.

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, 2013, filed with the SEC on March 3, 2014, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2013 filed on March 28, 2014.

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 six months ended June 30, 2014 and 2013.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013

Net income (loss)	$	(968	)	$	9,078		$	10,827		$	25,715
Adjustments:
Interest expense	11,441			10,940			22,892			19,998
Income tax expense	354			300			654			607
Depreciation and amortization	14,594			12,353			28,586			24,246
EBITDA	25,421			32,671			62,959			70,566
Adjustments:
Equity in (earnings) loss of unconsolidated entities	(1,938		)	(73		)	(1,642		)	301
Gain on sale of property, plant and equipment	(99		)	(424		)	(54		)	(796		)
Debt prepayment premium	7,767			—			7,767			—
Distributions from unconsolidated entities	561			1,436			1,341			1,961
Unit-based compensation	208			223			387			479
Adjusted EBITDA	31,920			33,833			70,758			72,511
Adjustments:
Interest expense	(11,441		)	(10,940		)	(22,892		)	(19,998		)
Income tax expense	(354		)	(300		)	(654		)	(607		)
Amortization of debt discount	1,228			77			1,305			153
Amortization of debt premium	(82		)	—			(82		)	—
Amortization of deferred debt issuance costs	3,778			806			4,588			2,075
Non-cash mark-to-market on derivatives	547			—			547			—
Payments of installment notes payable and capital lease obligations	—			(79		)	—			(160		)
Payments for plant turnaround costs	(1,746		)	—			(3,910		)	—
Maintenance capital expenditures	(4,616		)	(2,822		)	(8,954		)	(4,500		)
Distributable Cash Flow	$	19,234		$	20,575		$	40,706		$	49,474

Results of Operations

The results of operations for the six months ended June 30, 2014 and 2013 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 six months ended June 30, 2014 and 2013. The results of operations for these interim periods 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.

Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Three Months Ended June 30, 2014
Terminalling and storage	$	86,917	$	(1,307	)	$	85,610	$	9,174		$	(809	)	$	8,365
Natural gas services	248,670		—			248,670		4,822			993			5,815
Sulfur services	62,581		—			62,581		9,212			(1,326		)	7,886
Marine transportation	23,282		(1,198		)	22,084		(1,664		)	1,142			(522		)
Indirect selling, general and administrative	—		—			—		(4,838		)	—			(4,838		)
Total	$	421,450	$	(2,505	)	$	418,945	$	16,706		$	—		$	16,706



Three Months Ended June 30, 2013	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Terminalling and storage	$	85,762	$	(1,167	)	$	84,595	$	8,936		$	(301	)	$	8,635
Natural gas services	188,715		—			188,715		4,560			370			4,930
Sulfur services	60,896		—			60,896		8,860			(1,159		)	7,701
Marine transportation	25,021		(1,039		)	23,982		1,451			1,090			2,541
Indirect selling, general and administrative	—		—			—		(3,548		)	—			(3,548		)
Total	$	360,394	$	(2,206	)	$	358,188	$	20,259		$	—		$	20,259

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Six Months Ended June 30, 2014
Terminalling and storage	$	174,214	$	(2,530	)	$	171,684	$	18,207		$	(1,531	)	$	16,676
Natural gas services	582,303		—			582,303		13,460			1,820			15,280
Sulfur services	116,788		—			116,788		18,401			(2,447		)	15,954
Marine transportation	47,396		(2,198		)	45,198		282			2,158			2,440
Indirect selling, general and administrative	—		—			—		(9,735		)	—			(9,735		)
Total	$	920,701	$	(4,728	)	$	915,973	$	40,615		$	—		$	40,615



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Six Months Ended June 30, 2013
Terminalling and storage	$	166,115	$	(2,308	)	$	163,807	$	19,605		$	(987	)	$	18,618
Natural gas services	448,154		—			448,154		12,664			728			13,392
Sulfur services	131,281		—			131,281		18,906			(1,861		)	17,045
Marine transportation	50,253		(1,621		)	48,632		2,960			2,120			5,080
Indirect selling, general and administrative	—		—			—		(7,491		)	—			(7,491		)
Total	$	795,803	$	(3,929	)	$	791,874	$	46,644		$	—		$	46,644

Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended June 30, 2014 and 2013



	Three Months Ended June 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	35,474	$	28,587	$	6,887		24%
Products	51,443		57,175		(5,732		)	(10)%
Total revenues	86,917		85,762		1,155			1%

Cost of products sold	47,310		51,139		(3,829		)	(7)%
Operating expenses	20,370		17,739		2,631			15%
Selling, general and administrative expenses	731		748		(17		)	(2)%
Depreciation and amortization	9,415		7,297		2,118			29%
	9,091		8,839		252			3%
Other operating income	83		97		(14		)	(14)%
Operating income	$	9,174	$	8,936	$	238		3%

Lubricant sales volumes (gallons)	8,814		10,450		(1,636		)	(16)%
Shore-based throughput volumes (gallons)	61,466		67,069		(5,603		)	(8)%
Smackover refinery throughput volumes (BBL per day)	7,102		7,010		92			1%
Corpus Christi crude terminal (BBL per day)	166,971		105,986		60,985			58%

Services revenues. Services revenue increased primarily due to a $3.2 million increase at our crude terminal in Corpus Christi, Texas, which is attributable to volume increases. In addition, revenue at our Smackover refinery increased $2.6 million due to higher tolling fees and pipeline revenue.

Products revenues. A 21% decrease in sales volumes at our blending and packaging facilities resulted in a $9.2 million decrease to product revenues. The decline in volumes resulted primarily from increased price competition. The average sales price from our blending and packaging assets increased 10%, resulting in a $4.0 million increase in product revenues.

Cost of products sold. A 21% decrease in sales volumes at our blending and packaging facilities resulted in an $8.5 million decrease. The sales price increase of 10% resulted in a $5.2 million increase in cost of goods sold.

Operating expenses. Expenses at our specialty terminals increased $1.6 million, primarily due to a $0.7 million increase in wharfage and $0.3 million of regulatory fees and increased compensation costs. Expenses at the Smackover refinery increased $1.3 million, primarily attributable to higher pipeline throughput fees.

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.

Other operating income. Other operating income represents gains from the disposition of property, plant and equipment.

Comparative Results of Operations for the Six Months Ended June 30, 2014 and 2013



	Six Months Ended June 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	68,498	$	58,619	$	9,879		17%
Products	105,716		107,496		(1,780		)	(2)%
Total revenues	174,214		166,115		8,099			5%

Cost of products sold	95,835		95,409		426			—%
Operating expenses	40,122		35,433		4,689			13%
Selling, general and administrative expenses	1,698		1,443		255			18%
Depreciation and amortization	18,390		14,393		3,997			28%
	18,169		19,437		(1,268		)	(7)%
Other operating income	38		168		(130		)	(77)%
Operating income	$	18,207	$	19,605	$	(1,398	)	(7)%

Lubricant sales volumes (gallons)	17,977		19,247		(1,270		)	(7)%
Shore-based throughput volumes (gallons)	122,618		142,017		(19,399		)	(14)%
Smackover refinery throughput volumes (BBL per day)	5,132		6,730		(1,598		)	(24)%
Corpus Christi crude terminal (BBL per day)	153,732		107,677		46,055			43%

Services revenues. Services revenue increased $9.9 million related to specialty terminals, including $4.8 million attributable to volume increases at our crude terminal in Corpus Christi, Texas. In addition, revenue at our Smackover refinery increased $3.7 million due to higher tolling fees and pipeline revenue.

Products revenues. A 9% decrease in sales volumes at our blending and packaging facilities resulted in a $7.1 million decrease to product revenues. The decline in volumes resulted primarily from increased price competition. The average sales price from our blending and packaging assets increased 6%, resulting in a $4.6 million increase in product revenues.

Cost of products sold. Costs at our shore-based facilities increased $0.7 million due to a 1% increase in prices and 2% in volumes, which was offset by a decrease of $0.3 million at our blending and packaging facilities.

Operating expenses. Costs at our Smackover refinery increased $2.7 million primarily due to pipeline throughput fees. Costs at our Corpus Christi crude terminal increased $1.6 million primarily as a result of increased wharfage and regulatory fees.

Selling, general and administrative expenses. The increase in selling, general, and administrative expenses is primarily related to costs associated with a potential acquisition.

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

Other operating income. Other operating income represents gains from the disposition of property, plant and equipment.

Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended June 30, 2014 and 2013



	Three Months Ended June 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues:
Marine transportation	$	69	$	1,515	$	(1,446	)	(95)%
Products	248,601		187,200		61,401			33%
Total revenues	248,670		188,715		59,955			32%

Cost of products sold	239,114		181,893		57,221			31%
Operating expenses	2,318		990		1,328			134%
Selling, general and administrative expenses	1,741		718		1,023			142%
Depreciation and amortization	675		554		121			22%
Operating income	$	4,822	$	4,560	$	262		6%

Distributions from unconsolidated entities	$	561	$	1,436	$	(875	)	(61)%

NGL sales volumes (Bbls)	4,039		3,016		1,023			34%

Cost of products sold. Our average cost per barrel increased $1.11, or 2%. Our margins increased $0.59 per barrel during the period, primarily as a result of improved market conditions in the Louisiana butane market during 2014.

Operating expenses. Operating expenses increased primarily as a result of increased activity at our NGL marine facility in Corpus Christi, Texas.

Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily 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.

Comparative Results of Operations for the Six Months Ended June 30, 2014 and 2013



	Six Months Ended June 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues:
Marine transportation	$	365	$	1,845	$	(1,480	)	(80)%
Products	581,938		446,309		135,629			30%
Total revenues	582,303		448,154		134,149			30%

Cost of products sold	560,254		431,029		129,225			30%
Operating expenses	4,233		1,971		2,262			115%
Selling, general and administrative expenses	3,177		1,644		1,533			93%
Depreciation and amortization	1,179		846		333			39%
Operating income	$	13,460	$	12,664	$	796		6%

Distributions from unconsolidated entities	$	1,341	$	1,961	$	(620	)	(32)%

NGL sales volumes (Bbls)	8,997		6,721		2,276			34%

Revenues. The decrease in marine transportation revenue is the result of redeploying marine transportation assets acquired in February 2013. The assets were originally engaged in marine transportation activities but are being utilized for floating product storage at one of our terminal locations. Natural gas services sales volumes increased 34%, positively impacting revenues $147.2 million. The increase in volumes was a result of a colder winter season in 2014 compared to 2013. Additionally, we experienced increased volume as a result of being in the second full year of operations in the Louisiana butane market. Our NGL average sales price per barrel decreased $1.72, or 3%, resulting in an offsetting decrease to revenues of $11.6 million.

Cost of products sold. Our average cost per barrel decreased $1.86, or 3%. Our margins increased $0.14 per barrel during the period as a result of decreased market prices.

Operating expenses. Operating expenses increased primarily as a result of increased activity at our NGL marine facility in Corpus Christi, Texas.

Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily as a result of increased compensation expense of $1.1 million and increased property taxes of $0.2 million.

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

Sulfur Services Segment

Comparative Results of Operations for the Three Months Ended June 30, 2014 and 2013



	Three Months Ended June 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	3,038	$	3,001	$	37		1%
Products	59,543		57,895		1,648			3%
Total revenues	62,581		60,896		1,685			3%

Cost of products sold	45,406		44,877		529			1%
Operating expenses	4,809		4,186		623			15%
Selling, general and administrative expenses	1,123		1,016		107			11%
Depreciation and amortization	2,031		1,957		74			4%
Operating income	$	9,212	$	8,860	$	352		4%

Sulfur (long tons)	204.1		209.1		(5.0		)	(2)%
Fertilizer (long tons)	89.8		71.3		18.5			26%
Total sulfur services volumes (long tons)	293.9		280.4		13.5			5%

Revenues. Product revenues were most negatively impacted by lower market prices in our fertilizer business. Revenues increased $2.7 million due to a 5% increase in sales volumes. Additionally, revenues declined $1.1 million as a result of a 2% decrease in average sales price.

Cost of products sold. A 3% decrease in prices reduced cost of products sold by $1.5 million. A 5% increase in volumes increased our costs by an additional $2.0 million. Margin per ton increased $1.67, or 4%, resulting in a increase in gross margin of $1.1 million.

Operating expenses. Our operating expenses increased as a result of higher tug/barge expense.

Selling, general and administrative expenses. Selling, general and administrative expenses increased as a result of higher employee benefit costs.

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

Comparative Results of Operations for the Six Months Ended June 30, 2014 and 2013



	Six Months Ended June 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	6,075	$	6,002	$	73		1%
Products	110,713		125,279		(14,566		)	(12)%
Total revenues	116,788		131,281		(14,493		)	(11)%

Cost of products sold	83,349		97,764		(14,415		)	(15)%
Operating expenses	8,786		8,625		161			2%
Selling, general and administrative expenses	2,238		2,063		175			8%
Depreciation and amortization	4,014		3,923		91			2%
Operating income	$	18,401	$	18,906	$	(505	)	(3)%

Sulfur (long tons)	394.5		403.1		(8.6		)	(2)%
Fertilizer (long tons)	181.0		175.0		6.0			3%
Total sulfur services volumes (long tons)	575.5		578.1		(2.6		)	—%

Revenues. Product revenue declined $14.1 million attributable to a 11% decrease in prices. A reduction in sales volumes resulted in decreased revenue of $0.5 million.

Cost of products sold. Cost of products sold decreased $14.0 million due to a 14% reduction in prices. A slight decline in volumes resulted in a $0.4 million decrease in cost of products sold. Our margin per ton remained constant for both periods.

Operating expenses. Our operating expenses increased primarily as a result of higher tug/barge expenses.

Selling, general and administrative expenses. Selling, general and administrative expenses increased as a result of higher employee benefit costs.

Depreciation and amortization. Depreciation and amortization remained consistent.

Marine Transportation Segment

Comparative Results of Operations for the Three Months Ended June 30, 2014 and 2013



	Three Months Ended June 30,					Variance			Percent Change
	2014			2013		Variance			Percent Change
	(In thousands)
Revenues	$	23,282		$	25,021	$	(1,739	)	(7)%
Operating expenses	22,177			20,999		1,178			6%
Selling, general and administrative expenses	312			353		(41		)	(12)%
Depreciation and amortization	2,473			2,545		(72		)	(3)%
	(1,680		)	1,124		(2,804		)	(249)%
Other operating income	16			327		(311		)	(95)%
Operating income (loss)	$	(1,664	)	$	1,451	$	(3,115	)	(215)%

Inland revenues. A $0.7 million increase in inland revenues is primarily attributable to $1.2 million from increased utilization of the inland fleet. Offsetting this increase was a reduction of $0.5 million in ancillary charges, primarily rebill expenses.

Offshore revenues. A $2.6 million decrease in offshore revenue consists of $1.9 million related to decreased utilization of the offshore fleet which is a result of regulatory shipyard inspections and maintenance. The additional, $0.7 million is due to lower ancillary charges, primarily the rebill of fuel.

Operating expenses. Operating expenses increased as a result of increased repairs and maintenance expense of $3.4 million, offset by decreases in fuel expense of $1.0 million, property taxes of $0.4 million, and barge lease rental of $0.3 million.

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

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.

Other operating income. Other operating income represents gains from the disposition of property, plant and equipment.

Comparative Results of Operations for the Six Months Ended June 30, 2014 and 2013



	Six Months Ended June 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues	$	47,396	$	50,253	$	(2,857	)	(6)%
Operating expenses	41,624		42,065		(441		)	(1)%
Selling, general and administrative expenses	503		772		(269		)	(35)%
Depreciation and amortization	5,003		5,084		(81		)	(2)%
	266		2,332		(2,066		)	(89)%
Other operating income	16		628		(612		)	(97)%
Operating income	$	282	$	2,960	$	(2,678	)	(90)%

Inland revenues. Inland revenues increased $1.0 million as a result of $1.8 million related to increased utilization of the inland fleet. Offsetting this increase was a reduction of $0.8 million in ancillary charges, primarily rebill expenses.

Offshore revenues. A decrease in offshore revenues of $4.2 million is primarily due to decreased utilization of the offshore fleet as a result of regulatory shipyard inspections and maintenance.

Operating expenses. The decrease in operating expenses is includes declines in outside towing of $1.0 million, compensation and benefits of $0.9 million, fuel of $0.8 million, barge rental of $0.8 million, and barge cleaning of $0.7 million. These decreases are partially offset by a $3.7 million increase in repair and maintenance costs.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased primarily as a result of an increase in the management fee charged to certain divisions of the Partnership that operate marine assets.

Depreciation and amortization. Depreciation and amortization remained consistent.

Other operating income. Other operating income represents gains from the disposition of property, plant and equipment.

Equity in Earnings (Loss) of Unconsolidated Entities for the Three Months Ended June 30, 2014 and 2013



	Three Months Ended June 30,					Variance			Percent Change
	2014		2013			Variance			Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	769	$	—		$	769
Equity in earnings (loss) of Cardinal	608		(362		)	970			268%
Equity in earnings of MET	561		594			(33		)	(6)%
Equity in loss of Caliber	—		(159		)	159			100%
Equity in earnings of unconsolidated entities	$	1,938	$	73		$	1,865		2,555%

The investment in WTLPG was acquired in May 2014.

Equity in earnings of Cardinal increased $1.0 million. This increase was attributable to improved Cardinal results of operations primarily due to Cadeville Gas Storage, LLC ("Cadeville") and Perryville Gas Storage, LLC ("Perryville"), both of which were completed late in second quarter of 2013. Cadeville and Perryville are subsidiaries of Cardinal.

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 investment in Caliber Gathering, LLC (“Caliber”) was sold in November 2013.

Equity in Earnings (Loss) of Unconsolidated Entities for the Six Months Ended June 30, 2014 and 2013



	Six Months Ended June 30,						Variance		Percent Change
	2014			2013			Variance		Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	769		$	—		$	769
Equity in loss of Cardinal	(243		)	(578		)	335		58%
Equity in earnings of MET	1,116			594			522		88%
Equity in loss of Caliber	—			(317		)	317		100%
Equity in earnings (loss) of unconsolidated entities	$	1,642		$	(301	)	$	1,943	646%

The investment in WTLPG was acquired in May 2014.

Equity in earnings of Cardinal increased $0.3 million due primarily to improved results of operations attributable to Cadeville and Perryville.

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 investment in Caliber was sold in November 2013.

Interest Expense

Comparative Components of Interest Expense for the Three Months Ended June 30, 2014 and 2013



	Three Months Ended June 30,						Variance			Percent Change
	2014			2013			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	2,207		$	1,686		$	521		31%
8.875% Senior notes	—			3,883			(3,883		)	(100)%
7.250% Senior notes	7,220			4,632			2,588			56%
Amortization of deferred debt issuance costs	3,778			806			2,972			369%
Amortization of debt discount and premium	1,146			77			1,069			1,388%
Impact of interest rate derivative activity	(2,927		)	—			(2,927		)
Other	352			94			258			274%
Capitalized interest	(335		)	(238		)	(97		)	(41)%
Total interest expense	$	11,441		$	10,940		$	501		5%

Interest expense includes includes $2.6 million and $1.2 million, respectively, of non-cash charges for the write-off of unamortized debt issuance costs and unamortized discount on notes payable, respectively. These charges relate to the April 1, 2014 redemption of the entire $175.0 million balance of 8.875% senior unsecured notes due in 2018. In addition, we incurred a debt prepayment premium of $7.8 million related to the senior note redemption. This transaction is recorded as “Debt prepayment premium" in the Consolidated and Condensed Statements of Operations for both the three and six months ended June 30, 2014.

Comparative Components of Interest Expense for the Six Months Ended June 30, 2014 and 2013



	Six Months Ended June 30,						Variance			Percent Change
	2014			2013			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	4,606		$	3,262		$	1,344		41%
8.875 % Senior notes	3,882			7,766			(3,884		)	(50)%
7.250 % Senior notes	11,751			6,998			4,753			68%
Amortization of deferred debt issuance costs	4,588			2,075			2,513			121%
Amortization of debt discount and premium	1,223			153			1,070			699%
Impact of interest rate derivative activity	(2,927		)	—			(2,927		)
Other	492			162			330			204%
Capitalized interest	(723		)	(418		)	(305		)	73%
Total interest expense	$	22,892		$	19,998		$	2,894		14%

Indirect Selling, General and Administrative Expenses



	Three Months Ended June 30,				Variance		Percent Change	Six Months Ended June 30,				Variance		Percent Change
	2014		2013		Variance		Percent Change	2014		2013		Variance		Percent Change
	(In thousands)							(In thousands)
Indirect selling, general and administrative expenses	$	4,838	$	3,548	$	1,290	36%	$	9,735	$	7,491	$	2,244	30%

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 June 30,				Variance		Percent Change	Six Months Ended June 30,				Variance		Percent Change
	2014		2013		Variance		Percent Change	2014		2013		Variance		Percent Change
	(In thousands)							(In thousands)
Conflicts Committee approved reimbursement amount	$	3,134	$	2,655	$	479	18%	$	6,268	$	5,311	$	957	18%

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.

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, 2013, filed with the SEC on March 3, 2014, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2013 filed on March 28, 2014, as well as our updated risk factors contained in “Part II - Other Information, Item 1A. Risk Factors” set forth elsewhere herein, for a discussion of such risks.

Debt Financing Activities

In April 2014, we completed a $150.0 million private placement add-on of 7.250% senior unsecured notes due in 2021. We filed with the SEC a registration statement to exchange these notes for substantially identical notes that are registered under the Securities Act and commenced an exchange offer on April 28, 2014. The exchange offer was completed during the second quarter of 2014.

On April 1, 2014, we redeemed all $175.0 million of the 8.875% senior unsecured notes due in 2018 from their holders.

On June 27, 2014, we increased the maximum amount of borrowings and letters of credit under our revolving credit facility from $637.5 million to $900.0 million utilizing the accordion feature of our revolving credit facility.

Equity Offerings

On May 12, 2014, we completed a public offering of 3,600,000 common units at a price of $41.51 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 3,600,000 common units, net of underwriters' discounts, commissions and offering expenses were $143.4 million. Our general partner contributed $3.1 million in cash to us in conjunction with the

issuance in order to maintain its 2% general partner interest in us. The net proceeds from the common unit issuances were used to pay down outstanding amounts under our revolving credit facility.

In March 2014, we entered into an equity distribution agreement with multiple underwriters (the “Sales Agents”) for the ongoing distribution of our common units. Pursuant to this program, we offered and sold common unit equity through the Sales Agents for aggregate proceeds of $11.8 million and $17.1 million during the three and six months ended June 30, 2014, respectively. Common units issued were at market prices prevailing at the time of the sale. We also received capital contributions from our general partner of $0.2 million and $0.4 million during the three and six months ended June 30, 2014, respectively, to maintain its 2.0% general partner interest in us. The net proceeds from the common unit issuances were used to pay down outstanding amounts under our revolving credit facility.

Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2014.

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, 2013, filed with the SEC on March 3, 2014, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2013 filed on March 28, 2014, as well as our updated risk factors contained in “Part II - Other Information, Item 1A. Risk Factors” set forth elsewhere herein, for a discussion of such risks.

Cash Flows - Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

The following table details the cash flow changes between the six months ended June 30, 2014 and 2013:



	Six Months Ended June 30,						Variance			Percent Change
	2014			2013			Variance			Percent Change
	(In thousands)
Net cash provided by (used in):
Operating activities	$	20,949		$	72,418		$	(51,469	)	(71)%
Investing activities	(179,019		)	(116,127		)	(62,892		)	(54)%
Financing activities	144,232			38,564			105,668			274%
Net decrease in cash and cash equivalents	$	(13,838	)	$	(5,145	)	$	(8,693	)	(169)%

Net cash provided by operating activities for the six months ended June 30, 2014 decreased compared to the prior year period primarily due to a $53.6 million unfavorable variance in the change in working capital. The primary negative working capital impact was the change in accounts and other receivables related to decreased commodity prices in our Natural Gas Services segment and the timing of receipts from our customers. In addition, a debt prepayment premium of $7.8 million related to the redemption of the 8.875% unsecured senior notes negatively impacted net income for the six months ended June 30, 2014.

Net cash used in investing activities for the six months ended June 30, 2014 increased compared to the prior year period due to a $119.4 million increase in investments in unconsolidated entities in 2014. This additional investment is due primarily to our $134.4 million acquisition of interests in WTLPG. In addition, cash paid for acquisitions decreased $61.0 million in the 2014 period.

Net cash provided by financing activities for the six months ended June 30, 2014 increased compared to the prior period mainly due to $160.5 million in net proceeds related to the issuance of common units during 2014 offset by a $57.8 million decrease in net long-term debt borrowings in the current 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 our capital expenditure activity, excluding amounts paid for acquisitions, for the periods presented:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(In thousands)				(In thousands)
Expansion capital expenditures	$	15,147	$	11,084	$	32,283	$	24,121
Maintenance capital expenditures	4,616		2,822		8,954		4,500
Plant turnaround costs	1,746		—		3,910		—
Total	$	21,509	$	13,906	$	45,147	$	28,621

Expansion capital expenditures were made primarily in our Terminalling and Storage and Marine Transportation segments during the three and six months ended June 30, 2014. 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. Within our Marine Transportation segment, expenditures were made related to the construction of new barges. Maintenance capital expenditures were made primarily in our Marine Transportation, Terminalling and Storage, and Sulfur Services segments to maintain our existing assets and operations during the three and six months ended June 30, 2014. For the three and six months ended June 30, 2014, plant turnaround costs relate to our Smackover refinery.

Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three and six months ended June 30, 2013. Within our Terminalling and Storage segment, expenditures were made primarily at our Corpus Christi crude terminal and Smackover refinery. Maintenance capital expenditures were made primarily in our Terminalling and Storage and Marine Transportation segments to maintain our existing assets and operations during the three and six months ended June 30, 2013.

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 June 30, 2014, we had $692.2 million of outstanding indebtedness, consisting of outstanding borrowings of $402.2 million (including unamortized premium) under our Senior Notes due in 2021 and $290.0 million under our revolving credit facility.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of June 30, 2014, is as follows:



	Payments due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Revolving credit facility	$	290,000	$	—	$	—	$	290,000	$	—
2021 Senior unsecured notes	402,168		—		—		—		402,168
Throughput commitment	41,880		5,030		10,549		11,238		15,063
Operating leases	43,138		11,629		19,577		6,379		5,553
Interest expense: ¹
Revolving credit facility	32,247		8,623		17,246		6,378		—
2021 Senior unsecured notes	193,333		29,000		58,000		58,000		48,333
Total contractual cash obligations	$	1,002,766	$	54,282	$	105,372	$	371,995	$	471,117

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

Letter of Credit. At June 30, 2014, we had outstanding irrevocable letters of credit in the amount of $10.6 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

For a description of our 2021, 7.250% senior unsecured notes, 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, 2013.

Revolving Credit Facility

On November 10, 2005, we entered into a $225.0 million multi-bank credit facility, which was subsequently amended most recently on June 27, 2014 when we increased our maximum amount of borrowings to $900.0 million utilizing the accordion feature of our revolving credit facility.

As of June 30, 2014, we had $290.0 million outstanding under the revolving credit facility and $10.6 million of letters of credit issued, leaving a maximum available to be borrowed under our credit facility for future revolving credit borrowings and letters of credit of $599.4 million. Subject to the financial covenants contained in our credit facility and based on our existing EBITDA (as defined in our credit facility) calculations, as of June 30, 2014, we have the ability to incur approximately $90.0 million of that amount.

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 six months ended June 30, 2014, the level of outstanding draws on our credit facility has ranged from a low of $220.0 million to a high of $297.0 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	0.75	%	1.75	%	1.75	%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00	1.00	%	2.00	%	2.00	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00	1.25	%	2.25	%	2.25	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00	1.50	%	2.50	%	2.50	%
Greater than or equal to 4.50 to 1.00	1.75	%	2.75	%	2.75	%

The applicable margin for revolving loans that are LIBOR loans ranges from 1.75% to 2.75% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.75% to 1.75%. The applicable margin for LIBOR borrowings at June 30, 2014 is 2.75%.

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 with a temporary springing provision to 5.50 to 1.00 under certain scenarios. 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 July 31, 2014, our outstanding indebtedness includes $280.0 million under our credit facility.

We are subject to interest rate risk on our credit facility due to the variable interest rate and may enter into interest rate swaps to reduce this variable rate 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 six months ended June 30, 2014 or 2013. 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 six months ended June 30, 2014 or 2013.



Item 3.	Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk. We are exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. From time to time, we enter into interest rate swaps to manage interest rate risk associated with our variable rate credit facility.

We are exposed to variable interest rate risk as a result of borrowings under our revolving credit facility, which had a weighted-average interest rate of 2.97% as of June 30, 2014. As of July 31, 2014, we had total indebtedness outstanding under our credit facility of $280.0 million, all of which was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on June 30, 2014, 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 $2.9 million annually.

We are not exposed to changes in interest rates with respect to our senior unsecured notes due in 2021 as these obligations are fixed rates. The estimated fair value of our senior unsecured notes was approximately $424.9 million as of June 30, 2014, based on market prices of similar debt at June 30, 2014. 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 $20.3 million decrease in fair value of our long-term debt at June 30, 2014.

We have entered into interest rate swap agreements to reduce the amount of interest we pay on our senior unsecured notes due in February of 2021. Pursuant to the terms of these interest rate swap agreements, we pay a variable rate interest payment based on the three-month LIBOR and receive a fixed rate. The net difference to be paid or received from the counterparties under the interest rate swap agreement is settled semiannually and is recognized as an adjustment to interest expense. The risk associated with these interest rate swaps exposes us to an increase in interest rates which would result in an increase in interest expense and a corresponding decrease in net income. The impact of a 1% increase in interest rates would result in an decrease in the fair value of our interest rate swaps of $13.0 million.

At June 30, 2014, we are a party to interest rate swap agreements as shown below:



Interest Rate Swaps
As of June 30, 2014
(Dollars in Thousands)
Date of Swap	Bank	Maturity	Notional Amount		Interest Rate We Pay	Interest Rate We Receive	Fair Value Asset		Fair Value Liability
May 2014	Wells Fargo	February 2021	$	100,000	3 MO LIBOR plus 4.925%	7.25%	$	274	$	—
May 2014	SunTrust	February 2021	100,000		3 MO LIBOR plus 4.925%	7.25%	273		—
			$	200,000			$	547	$	—



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 3, 2014, as amended, by Amendment No. 1 on Form10-K/A for the year ended December 31, 2013 filed on March 28, 2014.



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
		Its General Partner

Date: July 31, 2014	By:	/s/ Robert D. Bondurant
		Robert D. Bondurant
		Executive Vice President, Treasurer, Chief Financial Officer, and Principal Accounting 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).
3.11*	Certificate of Formation of Martin Midstream NGL Holdings, LLC, dated April 21, 2011, as amended.
3.12*	Limited Liability Company Agreement of Martin Midstream NGL Holdings, LLC, dated May 15, 2014.
3.13*	Certificate of Formation of Martin Midstream NGL Holdings II, LLC, dated April 21, 2011, as amended.
3.14*	Limited Liability Company Agreement of Martin Midstream NGL Holdings II, LLC, dated May 15, 2014.
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 (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).
4.4*	First Supplemental Indenture, to the Indenture dated as of February 11, 2013 dated as of July 21, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee.
10.1	Second Amendment to Third Amended and Restated Credit Agreement, dated as of May 5, 2014, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed May 6, 2014, and incorporated herein by reference).
10.2	Third Amendment to Third Amended and Restated Credit Agreement, dated as of June 27, 2014, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed July 1, 2014, and incorporated herein by reference).



10.3	Purchase and Sale Agreement of Membership Interests of Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC by and between Atlas Pipeline Mid-Continent Holdings, LLC and Martin Operating Partnership L.P., dated as of May 5, 2014, filed as exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed May 5, 2014, and incorporated herein by reference).
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, 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