Martin Midstream Partners - 10-Q quarterly report FY2014 Q3

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________________________________

FORM 10-Q



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

For the quarterly period ended September 30, 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 October 29, 2014, was 35,349,699.



	Page

PART I – FINANCIAL INFORMATION	2

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk	54

Item 4. Controls and Procedures	56

PART II. OTHER INFORMATION	57

Item 1. Legal Proceedings	57

Item 1A. Risk Factors	57

Item 6. Exhibits	57

PART I – FINANCIAL INFORMATION



Item 1.	Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)



	September 30, 2014			December 31, 2013
	(Unaudited)			(Audited)
Assets
Cash	$	3,006		$	16,542
Accounts and other receivables, less allowance for doubtful accounts of $1,608 and $2,492, respectively	132,839			163,855
Product exchange receivables	6,351			2,727
Inventories	120,369			94,902
Due from affiliates	14,581			12,099
Fair value of derivatives	879			—
Other current assets	10,256			7,353
Assets held for sale	700			—
Total current assets	288,981			297,478

Property, plant and equipment, at cost	1,359,620			929,183
Accumulated depreciation	(334,150		)	(304,808		)
Property, plant and equipment, net	1,025,470			624,375

Goodwill	23,802			23,802
Investment in unconsolidated entities	135,219			128,662
Debt issuance costs, net	13,833			15,659
Note receivable - Martin Energy Trading LLC	15,000			—
Other assets, net	86,431			7,943
	$	1,588,736		$	1,097,919

Liabilities and Partners’ Capital
Trade and other accounts payable	$	120,037		$	142,951
Product exchange payables	18,860			9,595
Due to affiliates	11,713			2,596
Income taxes payable	1,002			1,204
Fair value of derivatives	542			—
Other accrued liabilities	13,041			20,242
Total current liabilities	165,195			176,588

Long-term debt	910,077			658,695
Other long-term obligations	3,174			2,219
Total liabilities	1,078,446			837,502

Commitments and contingencies
Partners’ capital	510,290			260,417
	$	1,588,736		$	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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Revenues:
Terminalling and storage *	$	31,880		$	28,956		$	97,848		$	85,267
Marine transportation *	24,282			24,217			69,845			74,694
Natural gas services	5,764			—			5,764			—
Sulfur services	3,037			3,001			9,112			9,003
Product sales: *
Natural gas services	230,294			204,296			812,232			650,605
Sulfur services	46,993			39,096			157,706			164,375
Terminalling and storage	47,735			60,050			153,451			167,546
	325,022			303,442			1,123,389			982,526
Total revenues	389,985			359,616			1,305,958			1,151,490

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	218,356			196,308			777,676			626,609
Sulfur services *	38,841			33,994			122,009			131,577
Terminalling and storage *	42,239			52,718			137,074			146,806
	299,436			283,020			1,036,759			904,992
Expenses:
Operating expenses *	48,391			43,444			140,543			129,839
Selling, general and administrative *	10,302			7,211			27,653			20,624
Depreciation and amortization	16,743			13,698			45,329			37,944
Total costs and expenses	374,872			347,373			1,250,284			1,093,399

Impairment of long-lived assets	(3,445		)	—			(3,445		)	—
Other operating income	347			—			401			796
Operating income	12,015			12,243			52,630			58,887

Other income (expense):
Equity in earnings (loss) of unconsolidated entities	2,655			(577		)	4,297			(878		)
Interest expense, net	(11,459		)	(11,060		)	(34,351		)	(31,058		)
Debt prepayment premium	—			—			(7,767		)	—
Reduction in carrying value of investment in Cardinal due to the purchase of the controlling interest	(30,102		)	—			(30,102		)	—
Other, net	286			(111		)	169			(134		)
Total other expense	(38,620		)	(11,748		)	(67,754		)	(32,070		)

Net income (loss) before taxes	(26,605		)	495			(15,124		)	26,817
Income tax expense	(300		)	(303		)	(954		)	(910		)
Net income (loss)	(26,905		)	192			(16,078		)	25,907
Less general partner's interest in net (income) loss	539			(4		)	322			(518		)
Less (income) loss allocable to unvested restricted units	62			(1		)	33			(67		)
Limited partners' interest in net income (loss)	$	(26,304	)	$	187		$	(15,723	)	$	25,322

Net income (loss) per unit attributable to limited partners - basic	$	(0.82	)	$	0.01		$	(0.54	)	$	0.95
Weighted average limited partner units - basic	32,243			26,552			29,271			26,561

Net income (loss) per unit attributable to limited partners - diluted	$	(0.82	)	$	0.01		$	(0.54	)	$	0.95
Weighted average limited partner units - diluted	32,243			26,579			29,271			26,581

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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
Revenues:
Terminalling and storage	$	19,045	$	18,044	$	55,798	$	52,857
Marine transportation	6,076		5,943		18,340		18,828
Product Sales	883		964		6,484		4,012
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	9,908		7,799		29,169		23,391
Sulfur services	4,491		4,539		13,808		13,514
Terminalling and storage	9,174		13,488		25,571		39,638
Expenses:
Operating expenses	21,013		17,902		58,500		53,410
Selling, general and administrative	7,230		4,356		18,103		12,944

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	—		25,389			518			25,907
Issuance of restricted units	63,750		—			—			—
Forfeiture of restricted units	(250	)	—			—			—
General partner contribution	—		—			37			37
Cash distributions	—		(61,902		)	(1,384		)	(63,286		)
Excess purchase price over carrying value of acquired assets	—		(301		)	—			(301		)
Unit-based compensation	—		737			—			737
Purchase of treasury units	(6,000	)	(250		)	—			(250		)
Balances - September 30, 2013	26,624,276		$	313,163		$	7,643		$	320,806

Balances - January 1, 2014	26,625,026		$	254,028		$	6,389		$	260,417
Net loss	—		(15,756		)	(322		)	(16,078		)
Issuance of common units	8,727,673		331,571			—			331,571
Issuance of restricted units	6,900		—			—			—
Forfeiture of restricted units	(3,500	)	—			—			—
General partner contribution	—		—			6,995			6,995
Cash distributions	—		(66,473		)	(1,506		)	(67,979		)
Unit-based compensation	—		589			—			589
Excess purchase price over carrying value of acquired assets	—		(4,948		)	—			(4,948		)
Purchase of treasury units	(6,400	)	(277		)	—			(277		)
Balances - September 30, 2014	35,349,699		$	498,734		$	11,556		$	510,290

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)



	Nine Months Ended
	September 30,
	2014			2013
Cash flows from operating activities:
Net income (loss)	$	(16,078	)	$	25,907
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	45,329			37,944
Amortization of deferred debt issuance costs	5,415			2,890
Amortization of debt discount	1,305			230
Amortization of premium on notes payable	(164		)	—
Gain on sale of property, plant and equipment	(54		)	(796		)
Impairment of long-lived assets	3,445			—
Equity in (earnings) loss of unconsolidated entities	(4,297		)	878
Reduction in carrying value of investment in Cardinal due to purchase of the controlling interest	30,102			—
Non-cash mark-to-market on derivatives	489			—
Unit-based compensation	589			737
Preferred dividends on MET investment	1,498			1,171
Return on investment	600			—
Other	—			7
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	32,443			43,043
Product exchange receivables	(3,624		)	(219		)
Inventories	(25,223		)	(8,362		)
Due from affiliates	(2,482		)	(5,188		)
Other current assets	1,219			(6,358		)
Trade and other accounts payable	(29,600		)	(29,641		)
Product exchange payables	9,265			936
Due to affiliates	9,117			(525		)
Income taxes payable	(202		)	(440		)
Other accrued liabilities	(7,214		)	8,842
Change in other non-current assets and liabilities	1,123			(210		)
Net cash provided by continuing operating activities	53,001			70,846
Net cash used in discontinued operating activities	—			(8,678		)
Net cash provided by operating activities	53,001			62,168
Cash flows from investing activities:
Payments for property, plant and equipment	(58,522		)	(68,591		)
Acquisitions, less cash acquired	(100,046		)	(73,921		)
Payments for plant turnaround costs	(4,000		)	—
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		)	—
Return of investments from unconsolidated entities	726			1,551
Contributions to unconsolidated entities	(3,386		)	(30,877		)
Net cash used in investing activities	(296,464		)	(167,119		)
Cash flows from financing activities:
Payments of long-term debt	(1,458,096		)	(518,000		)
Payments of notes payable and capital lease obligations	—			(251		)
Proceeds from long-term debt	1,426,250			691,000
Net proceeds from issuance of common units	331,571			—
General partner contribution	6,995			37
Purchase of treasury units	(277		)	(250		)
Payment of debt issuance costs	(3,589		)	(9,115		)
Excess purchase price over carrying value of acquired assets	(4,948		)	(301		)
Cash distributions paid	(67,979		)	(63,286		)
Net cash provided by financing activities	229,927			99,834
Net decrease in cash	(13,536		)	(5,117		)
Cash at beginning of period	16,542			5,162
Cash at end of period	$	3,006		$	45
Non-cash additions to property, plant and equipment	$	4,208		$	—

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 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. On October 29, 2014, Alinda appointed their third of three total representatives to serve as directors of the Partnership's 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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.


(3)	Acquisitions

Cardinal Gas Storage Partners LLC

On August 29, 2014, the Partnership acquired from Energy Capital Partners (“ECP”) all of ECP’s approximate 57.8% Category A membership interests in Cardinal Gas Storage Partners LLC (“Cardinal”) for cash consideration of approximately $120.0 million, subject to certain post-closing adjustments. Prior to the acquisition, the Partnership owned an approximate 42.2% interest in the Category A membership interests in Cardinal. Based on the application of purchase accounting, the Partnership reduced the carrying value of its existing investment in Cardinal at the acquisition date by $30,102, which was recognized in the Partnership's Consolidated and Condensed Statements of Operations for the three and nine months ended September 30, 2014. Concurrent with the closing of the transaction, the Partnership retired all of the project level financing of various Cardinal subsidiaries. The Partnership funded the acquisition and repayment of the project financings with borrowings under its revolving credit facility and the use of restricted cash acquired.

The total purchase price is as follows:



Cash payment for 57.8% interest in Cardinal	$	119,973
Fair value of the Partnership's previously owned 42.2% interest in Cardinal	87,613
Total	$	207,586

Assets acquired and liabilities assumed were recorded in the Natural Gas Services segment at fair value in the following preliminary purchase price allocation:



Restricted cash	$	19,216
Other current assets	9,418
Property, plant and equipment	390,352
Intangible and other assets	77,995
Project level finance debt	(282,086		)
Other current liabilities	(6,714		)
Other non-current liabilities	(595		)
Total	$	207,586

The Partnerships expects to complete the final purchase price allocation by December 31, 2014.

Intangible assets consist of above-market gas storage customer contracts which are amortized based upon the terms of the individual contracts. The weighted average life of these contracts, based upon contracted volumes, is 5.1 years.

The Partnership’s results of operations from the Cardinal acquisition include revenues of $5,764 and net income of $340 for the three and nine months ended September 30, 2014. In the third quarter, the Partnership recorded a $30,102 non-recurring, non-cash charge to its net income reflecting the reduction in the Partnership's carrying value of its investment in Cardinal as a result of the Cardinal acquisition.

Natural Gas Liquids ("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:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



Property, plant and equipment	$	2,453
Current liabilities	(13		)
	$	2,440

The excess of the purchase price over the carrying value of the assets of $4,948 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. The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. 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 owned 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.

Pro Forma Financial Information for Cardinal and WTLPG

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenue:
As reported	$	389,985		$	359,616		$	1,305,958		$	1,151,490
Pro forma	$	401,130		$	376,957		$	1,352,446		$	1,187,626
Net income (loss) attributable to limited partners:
As reported	$	(26,304	)	$	187		$	(15,723	)	$	25,322
Pro forma	$	136		$	(9,782	)	$	(5,784	)	$	455
Net income (loss) per unit attributable to limited partners - basic
As reported	$	(0.82	)	$	0.01		$	(0.54	)	$	0.95
Pro forma	$	—		$	(0.37	)	$	(0.20	)	$	0.02
Net income (loss) per unit attributable to limited partners - diluted
As reported	$	(0.82	)	$	0.01		$	(0.54	)	$	0.95
Pro forma	$	—		$	(0.37	)	$	(0.20	)	$	0.02

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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 $590 and net income of $87 for the three months ended September 30, 2014 and revenues of $1,736 and net income of $321 for the nine months ended September 30, 2014. The Partnership's results of operations from these assets included revenues of $104 and a net loss of $80 for both the three and nine months ended September 30, 2013.

NL Grease, LLC

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



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 $3,150 and net income of $124 for the three months ended September 30, 2014 and revenues of $4,101 and net income of $166 for the three months ended September 30, 2013. Results of operations included revenues of $10,914 and net income of $254 for the nine months ended September 30, 2014 and revenues of $4,622 and net income of $10 for the nine months ended September 30, 2013.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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 nine months ended September 30, 2013.


(5)	Inventories

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



	September 30, 2014		December 31, 2013
Natural gas liquids	$	59,494	$	31,859
Sulfur	9,887		8,912
Sulfur based products	14,819		17,584
Lubricants	32,830		33,847
Other	3,339		2,700
	$	120,369	$	94,902


(6)	Investments in Unconsolidated Entities and Joint Ventures

On August 29, 2014, the Partnership acquired ECP’s approximate 57.8% Category A interest in Cardinal. Prior to the acquisition, the Partnership owned an approximate 42.2% Category A interest in Cardinal which was accounted for by the equity method. See Note 3 for discussion of the acquisition of the remaining interests.

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 at closing. The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. Atlas Holdings owned 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 $343 and $514 for the three and nine months ended September 30, 2014, respectively. 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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.

During the fourth quarter of 2013, the Partnership sold its unconsolidated 50% interest in Caliber Gathering, LLC (“Caliber”). As a result, there is no equity in earnings (loss) in the 2014 period.

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. On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. See Note 12.

The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s Consolidated and Condensed Balance Sheets and the components of equity in earnings of unconsolidated entities included in the Partnership’s Consolidated and Condensed Statements of Operations:



	September 30, 2014		December 31, 2013
WTLPG	$	135,219	$	—
Cardinal	—		113,662
MET	—		15,000
Total investment in unconsolidated entities	$	135,219	$	128,662



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014		2013
Equity in earnings of WTLPG	$	1,138	$	—		$	1,907	$	—
Equity in earnings (loss) of Cardinal	1,135		(984		)	892		(1,561		)
Equity in earnings of MET	382		577			1,498		1,171
Equity in loss of Caliber	—		(170		)	—		(488		)
Equity in earnings of unconsolidated entities	$	2,655	$	(577	)	$	4,297	$	(878	)

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



	As of September 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	Total Assets		Members' Equity		Revenues		Net Income (Loss)			Revenues		Net Income (Loss)
2014
WTLPG	$	212,483	$	192,097	$	23,884	$	7,403		$	71,798	$	28,004
	As of December 31,
2013
Cardinal	$	661,816	$	346,584	$	17,341	$	(2,300	)	$	36,136	$	(2,241	)

As of September 30, 2014 and December 31, 2013, the Partnership’s interest in cash of the unconsolidated equity-method investees was $55 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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.

(a) Commodity Derivative Instruments

The Partnership has from time to time used derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure. 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 is exposed to commodity risk associated with the future purchase of natural gas. The Partnership utilizes derivatives to manage exposure associated with commodity price risk by entering into call options to place a limit on the commodity price of the future purchase of base gas. All derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings.

As of September 30, 2014, the Partnership had a notional quantity of 3,631,740 MMBtu of natural gas call options with a strike price of $4.50 per MMBtu. These options manage the purchase of base gas at Monroe Gas Storage Company, LLC for the portion of base gas that is currently leased with Credit Suisse and scheduled to be returned in January and February 2015. The options settle in two increments of 2,345,498 MMBtu and 1,286,242 MMBtu on January 31, 2015 and February 28, 2015, respectively.

For information regarding fair value amounts and gains and losses on natural gas call options, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments” below.

(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 September 30, 2014, we had a combined notional principal amount of $250,000 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. As of September 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:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	September 30, 2014		December 31, 2013		Balance Sheet Location	September 30, 2014		December 31, 2013
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	830	$	—	Fair value of derivatives	$	—	$	—
Interest rate contracts	Fair value of derivatives	49		—		Fair value of derivatives	542		—
Total derivatives not designated as hedging instruments		$	879	$	—		$	542	$	—

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

For the Three Months Ended September 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:
Commodity contracts	Other income	$	21	$	—
Interest rate contracts	Interest expense	63		—
Total derivatives not designated as hedging instruments		$	84	$	—

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

For the Nine Months Ended September 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:
Commodity contracts	Other income	$	21		$	—
Interest rate contracts	Interest expense	(2,864		)	—
Total derivatives not designated as hedging instruments		$	(2,843	)	$	—

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. In August 2014, the Partnership received a scheduled swap settlement related to these agreements totaling $976. "This amount was recorded in Interest expense, net" for the three and nine months ended September 30, 2014.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

On September 18, 2014, the Partnership entered into a fixed-to-variable interest rate swap agreement, with an aggregate notional amount of $50,000, to hedge its exposure to changes in the fair value of its senior unsecured notes.

On October 9, 2014, the Partnership terminated each of its three outstanding swaps, receiving a termination benefit of $2,125, which will be recorded in the Partnership's Consolidated Statement of Operations in the fourth quarter of 2014.

Subsequent to the termination on October 9, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements, each with an aggregate notional amount of $50,000 to hedge its exposure to changes in the fair value of its senior unsecured notes. On October 14, 2014, the Partnership terminated each of these two swaps, receiving a termination benefit of $500, which will be recorded in the Partnership's Consolidated Statement of Operations in the fourth quarter of 2014.

Subsequent to the termination on October 14, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements, each with an aggregate notional amount of $50,000 to hedge its exposure to changes in the fair value of its senior unsecured notes. On October 14, 2014, the Partnership terminated each of these two swaps, receiving a termination benefit of $710, which will be recorded in the Partnership's Consolidated Statement of Operations in the fourth quarter of 2014.


(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.

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at September 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	September 30, 2014		(Level 1)		(Level 2)		(Level 3)
Assets
Interest rate contracts	$	49	$	—	$	49	$	—
Commodity contracts	830		—		830		—
Note receivable - Martin Energy Trading	15,748		—		—		15,748
Total assets	$	16,627	$	—	$	879	$	15,748

Liabilities
2021 Senior unsecured notes	$	420,874	$	—	$	420,874	$	—
Interest rate contracts	542		—		542		—
Total liabilities	$	421,416	$	—	$	421,416	$	—

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



	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. The estimated fair value of the note receivable from Martin Energy Trading was determined by calculating the net present value of the interest payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties.


(9)	Supplemental Balance Sheet Information

Components of "Other assets, net" were as follows:



	September 30, 2014		December 31, 2013
Customer contracts and relationships	$	77,234	$	—
Other intangible assets	2,317		2,696
Other	6,880		5,247
	$	86,431	$	7,943

Components of "Other accrued liabilities" were as follows:



	September 30, 2014		December 31, 2013
Accrued interest	$	3,700	$	11,038
Property and other taxes payable	7,478		6,785
Accrued payroll	1,693		2,186
Other	170		233
	$	13,041	$	20,242


(10)	Long-Term Debt

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



	September 30, 2014		December 31, 2013
$900,000³ Revolving credit facility at variable interest rate (2.92%¹ weighted average at September 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	$	508,000	$	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 $2,086 and $0, respectively, issued $250,000 February 2013 and $150,000 April 2014, due February 2021, unsecured²	402,077		250,000
Total long-term debt	910,077		658,695
Less current installments	—		—
Long-term debt, net of current installments	$	910,077	$	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 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 existing LIBOR borrowings at September 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, recorded on the Partnership's Consolidated and Condensed Statement of Operations for the nine months ended September 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 nine months ended September 30, 2014.

³On 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 $17,346 and $11,289 for the three months ended September 30, 2014 and 2013, respectively. The Partnership paid cash interest in the amount of $35,770 and $22,897 for the nine months ended September 30, 2014 and 2013, respectively. Capitalized interest was $234 and $326 for the three months ended September 30, 2014 and 2013, respectively. Capitalized interest was $957 and $744 for the nine months ended September 30, 2014 and 2013, respectively.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)


(11)	Partners' Capital

As of September 30, 2014, partners’ capital consisted of 35,349,699 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owned 6,264,532 of the Partnership's common limited partnership units representing approximately 17.7% 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 September 29, 2014, the Partnership completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $122,587. The Partnership's general partner contributed $2,599 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.

On August 29, 2014, the Partnership closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45,000 in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10-day weighted average price of the Partnership's common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, the Partnership's general partner contributed $918 in order to maintain its 2% general partner interest in the Partnership. The proceeds from the common unit issuances were used to pay down outstanding amounts under the Partnership's revolving credit facility.

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 net proceeds of $3,467 and $20,551 during the three and nine months ended September 30, 2014, respectively. The Partnership paid $71 and $332 in compensation to the Sales Agents for the three and nine months ended September 30, 2014, respectively. Under the the program, the Partnership issued 89,252 and 506,408 common units during the three and nine months ended September 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 $72 and $428 during the three and nine months ended September 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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 September 30, 2014. As of September 30, 2014, the amount of incentive distributions the general partner has foregone is $16,963, resulting in an amount remaining of $4,037.

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.

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 September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net income (loss) attributable to Martin Midstream Partners L.P.	$	(26,905	)	$	192		$	(16,078	)	$	25,907
Less general partner’s interest in net income:
Distributions payable on behalf of general partner interest	552			467			1,506			1,384
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	(1,091		)	(463		)	(1,828		)	(866		)
Less income (loss) allocable to unvested restricted units	(62		)	1			(33		)	67
Limited partners’ interest in net income (loss)	$	(26,304	)	$	187		$	(15,723	)	$	25,322

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

The weighted average units outstanding for basic net income per unit were 32,242,571 and 29,271,205 for the three and nine months ended September 30, 2014, respectively, and 26,552,028 and 26,561,406 for the three and nine months ended September 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 and nine months ended September 30, 2014 because the limited partners were allocated a net loss in these periods. For diluted net income per unit, the weighted average units outstanding were increased by 26,632 and 19,757 for the three and nine months ended September 30, 2013, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.


(12)	Related Party Transactions

As of September 30, 2014, Martin Resource Management owned 6,264,532 of the Partnership’s common units representing approximately 17.7% 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 September 30, 2014, of approximately 17.7% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

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

Omnibus Agreement

Omnibus Agreement. The Partnership and its general partner are parties to 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;

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)


◦	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.


•	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 September 30, 2014 and 2013, respectively. The Partnership reimbursed Martin Resource Management for $9,401 and $7,966 of indirect expenses for the nine months ended September 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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

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 NGLs 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

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.

Other Agreements

Cross Tolling Agreement. The Partnership is a party to an amended and restated tolling agreement with Cross, dated October 28, 2014, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement 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, on the third, sixth and ninth anniversaries of the agreement, 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:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenues:
Terminalling and storage	$	19,045	$	18,044	$	55,798	$	52,857
Marine transportation	6,076		5,943		18,340		18,828
Product sales:
Natural gas services	—		—		3,046		9
Sulfur services	708		809		2,931		3,460
Terminalling and storage	175		155		507		543
	883		964		6,484		4,012
	$	26,004	$	24,951	$	80,622	$	75,697

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	$	9,908	$	7,799	$	29,169	$	23,391
Sulfur services	4,491		4,539		13,808		13,514
Terminalling and storage	9,174		13,488		25,571		39,638
	$	23,573	$	25,826	$	68,548	$	76,543

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



Operating Expenses:
Marine transportation	$	10,198	$	9,697	$	28,685	$	29,260
Natural gas services	1,510		542		2,914		1,496
Sulfur services	2,121		2,115		5,641		6,405
Terminalling and storage	7,184		5,548		21,260		16,249
	$	21,013	$	17,902	$	58,500	$	53,410

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	$	8	$	15	$	23	$	45
Natural gas services	2,647		635		4,751		1,623
Sulfur services	840		748		2,503		2,360
Terminalling and storage	317		291		1,045		935
Indirect overhead allocation, net of reimbursement	3,418		2,667		9,781		7,981
	$	7,230	$	4,356	$	18,103	$	12,944

Other Related Party Transactions

As discussed in Note 6, during March 2013, the Partnership acquired 100% of the preferred interests in MET, a subsidiary of Martin Resource Management, for $15,000. On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. The note is recorded in "Note receivable - Martin Energy Trading" on the Partnership's Consolidated and Condensed Balance Sheet. Interest income for the

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)

three and nine months ended September 30, 2014 was $185 and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.


(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 $300 and $303 were recorded in income tax expense for the three months ended September 30, 2014 and 2013, respectively. State income taxes attributable to the Texas margin tax of $954 and $910 were recorded in income tax expense for the nine months ended September 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.

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 September 30, 2014
Terminalling and storage	$	80,948	$	(1,333	)	$	79,615	$	9,512	$	5,920		$	9,735
Natural gas services	236,058		—			236,058		2,684		7,484			4,611
Sulfur services	50,030		—			50,030		2,078		1,635			694
Marine transportation	25,859		(1,577		)	24,282		2,469		1,455			2,245
Indirect selling, general and administrative	—		—			—		—		(4,479		)	—
Total	$	392,895	$	(2,910	)	$	389,985	$	16,743	$	12,015		$	17,285

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



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



Nine Months Ended September 30, 2014	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Terminalling and storage	$	255,162	$	(3,863	)	$	251,299	$	27,902	$	22,596		$	39,131
Natural gas services	818,361		—			818,361		3,863		22,764			5,185
Sulfur services	166,818		—			166,818		6,092		17,589			3,775
Marine transportation	73,255		(3,775		)	69,480		7,472		3,895			10,431
Indirect selling, general and administrative	—		—			—		—		(14,214		)	—
Total	$	1,313,596	$	(7,638	)	$	1,305,958	$	45,329	$	52,630		$	58,522



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

The "Impairment of long-lived assets" recorded on the Partnership's Consolidated and Condensed Statement of Operations for the three and nine months ended September 30, 2014 is included in results of operations for the Partnership's Marine Transportation segment results in the table above. The impairment is a reduction in the carrying value related to the recoverability of one offshore tow in the amount of $3,445, which was related to the tow's ability to generate cash flows in recent quarters.

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



	September 30, 2014		December 31, 2013
Total assets:
Terminalling and storage	$	463,509	$	461,160
Natural gas services	817,864		320,631
Sulfur services	148,162		151,982
Marine transportation	159,201		164,146
Total assets	$	1,588,736	$	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 September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Employees	$	145	$	181	$	429	$	533
Non-employee directors	56		76		160		204
Total unit-based compensation expense	$	201	$	257	$	589	$	737

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 ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units. The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally cliff vest after three years of service.

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the nine months ended September 30, 2014 is provided below:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)



	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	(3,500		)	$	31.06
Non-Vested, end of period	70,648			$	33.42

Aggregate intrinsic value, end of period	$	2,634

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the three and nine months ended September 30, 2014 and 2013 are provided below:



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

As of September 30, 2014, there was $1,201 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.78 years.

Unit Options. The plan currently permits the grant of options covering common units. As of September 30, 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.

The Partnership maintains as subsidiary guarantors the following entities: MOP Midstream Holdings LLC, Martin Midstream NGL Holdings, LLC and Martin Midstream NGL Holdings II, LLC, Cardinal Gas Storage Partners LLC, Perryville Gas Storage LLC, Arcadia Gas Storage, LLC, Cadeville Gas Storage LLC, and Monroe Gas Storage Company, 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2014

(Unaudited)


(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

Cardinal/Redbird Merger. On October 27, 2014, Cardinal merged with and into Redbird Gas Storage LLC ("Redbird"), and Redbird subsequently changed its name to Cardinal Gas Storage Partners LLC.

Quarterly Distribution. On October 23, 2014, the Partnership declared a quarterly cash distribution of $0.8125 per common unit for the second quarter of 2014, or $3.25 per common unit on an annualized basis, which will be paid on November 14, 2014 to unitholders of record as of November 7, 2014.

Interest Rate Swaps. On October 9, 2014, the Partnership terminated its three interest rate swaps which were outstanding at September 30, 2014. In addition, the Partnership entered into and subsequently terminated four additional interest rate swaps in October 2014. The Partnership received aggregate termination benefits of $3,335 which will be recorded in the Partnership's Consolidated Statement of Operations in the fourth quarter of 2014. See Note 7 for additional discussion of these transactions.



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 September 30, 2014, Martin Resource Management owned 17.7% 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.

Public Offering. On September 29, 2014, we completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $122.6 million. Our general partner contributed $2.6 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.

Private Placement of Common Units. On August 29, 2014, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45.0 million in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10-day weighted average price of our common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, our general partner contributed $0.9 million in order to maintain its 2% general partner interest in us. The proceeds from the common unit issuances were used to pay down outstanding amounts under our revolving credit facility.

Cardinal Gas Storage. On August 29, 2014, Redbird Gas Storage LLC (“Redbird”), a wholly owned subsidiary of the Partnership, completed the previously announced purchase of all of the outstanding Category A membership interests of Cardinal Gas Storage Partners LLC (“Cardinal”) from Energy Capital Partners I, LP, Energy Capital Partners I-A, LP, Energy Capital Partners I-B IP, LP and Energy Capital Partners I (Cardinal IP), LP (together, “ECP”) for cash of approximately $120.0 million, subject to certain post-closing adjustments. As a result of the acquisition, Redbird owns 100% of the Category A membership interests in Cardinal. Concurrent with the closing of the transaction, we retired all of the project level financing of various Cardinal subsidiaries. This transaction and repayment of the project financings was funded with borrowings under our revolving credit facility.

On October 27, 2014, Cardinal merged with and into Redbird, and Redbird subsequently changed its name to Cardinal.

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 September 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 - 50 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $6.7 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 an impairment charge of $3.4 million in our Marine Transportation Segment during the three and nine months ended September 30, 2014 related to certain offshore marine assets. No impairment was recorded for the three and nine months ended September 30, 2013.
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 are in the process of completing the most recent annual review of goodwill as of August 31, 2014. Based on preliminary results of the evaluation, no impairment is indicated.



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 17.7% 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 $48.4 million of direct costs and expenses for the three months ended September 30, 2014 compared to $45.4 million for the three months ended September 30, 2013.We reimbursed Martin Resource Management for $135.4 million of direct costs and expenses for the nine months ended September 30, 2014 compared to $134.9 million for the nine months ended September 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 September 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 nine months ended September 30, 2014 and 2013, the Conflicts Committee approved reimbursement amounts of $9.4 million and $8.0 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 8% and 9% of our total cost of products sold during the three months ended September 30, 2014 and 2013, respectively. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 7% and 8% of our total cost of products sold during the nine months ended September 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 September 30, 2014 and 2013, respectively. Our sales to Martin Resource Management accounted for approximately 6% and 7% of our total revenues for the nine months ended September 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 nine months ended September 30, 2014 and 2013.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013

Net income (loss)	$	(26,905	)	$	192		$	(16,078	)	$	25,907
Adjustments:
Interest expense	11,459			11,060			34,351			31,058
Income tax expense	300			303			954			910
Depreciation and amortization	16,743			13,698			45,329			37,944
EBITDA	1,597			25,253			64,556			95,819
Adjustments:
Equity in (earnings) loss of unconsolidated entities	(2,655		)	577			(4,297		)	878
Gain on sale of property, plant and equipment	—			—			(54		)	(796		)
Impairment of long-lived assets	3,445			—			3,445			—
Reduction in carrying value of investment in Cardinal due to the purchase of the controlling interest¹	30,102			—			30,102			—
Debt prepayment premium	—			—			7,767			—
Distributions from unconsolidated entities	982			761			2,323			2,722
Unit-based compensation	201			257			589			737
Adjusted EBITDA	33,672			26,848			104,431			99,360
Adjustments:
Interest expense	(11,459		)	(11,060		)	(34,351		)	(31,058		)
Income tax expense	(300		)	(303		)	(954		)	(910		)
Amortization of debt discount	—			77			1,305			230
Amortization of debt premium	(82		)	—			(164		)	—
Amortization of deferred debt issuance costs	827			815			5,415			2,890
Non-cash mark-to-market on derivatives	1,036			—			489			—
Payments of installment notes payable and capital lease obligations	—			(91		)	—			(251		)
Payments for plant turnaround costs	(90		)	—			(4,000		)	—
Maintenance capital expenditures	(4,306		)	(2,973		)	(13,260		)	(7,473		)
Distributable Cash Flow	$	19,298		$	13,313		$	58,911		$	62,788

¹In the third quarter, we recorded a $30.1 million non-recurring, non-cash charge to our net income reflecting the reduction in our carrying value of our investment in Cardinal as a result of the Cardinal acquisition.

Results of Operations

The results of operations for the nine months ended September 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 nine months ended September 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 following the comparative discussion of our results within each segment.

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 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 September 30, 2014
Terminalling and storage	$	80,948	$	(1,333	)	$	79,615	$	6,298		$	(378	)	$	5,920
Natural gas services	236,058		—			236,058		6,439			1,045			7,484
Sulfur services	50,030		—			50,030		3,357			(1,722		)	1,635
Marine transportation	25,859		(1,577		)	24,282		400			1,055			1,455
Indirect selling, general and administrative	—		—			—		(4,479		)	—			(4,479		)
Total	$	392,895	$	(2,910	)	$	389,985	$	12,015		$	—		$	12,015



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

Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss) after Eliminations
Nine Months Ended September 30, 2014
Terminalling and storage	$	255,162	$	(3,863	)	$	251,299	$	24,505		$	(1,909	)	$	22,596
Natural gas services	818,361		—			818,361		19,899			2,865			22,764
Sulfur services	166,818		—			166,818		21,758			(4,169		)	17,589
Marine transportation	73,255		(3,775		)	69,480		682			3,213			3,895
Indirect selling, general and administrative	—		—			—		(14,214		)	—			(14,214		)
Total	$	1,313,596	$	(7,638	)	$	1,305,958	$	52,630		$	—		$	52,630



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

Terminalling and Storage Segment

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



	Three Months Ended September 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	33,213	$	30,151	$	3,062		10%
Products	47,735		60,054		(12,319		)	(21)%
Total revenues	80,948		90,205		(9,257		)	(10)%

Cost of products sold	43,193		53,215		(10,022		)	(19)%
Operating expenses	21,506		19,427		2,079			11%
Selling, general and administrative expenses	786		979		(193		)	(20)%
Depreciation and amortization	9,512		8,532		980			11%
	5,951		8,052		(2,101		)	(26)%
Other operating income	347		—		347
Operating income	$	6,298	$	8,052	$	(1,754	)	(22)%

Lubricant sales volumes (gallons)	8,193		10,638		(2,445		)	(23)%
Shore-based throughput volumes (gallons)	64,338		65,516		(1,178		)	(2)%
Smackover refinery throughput volumes (BBL per day)	7,123		6,878		245			4%
Corpus Christi crude terminal (BBL per day)	173,315		101,921		71,394			70%

Services revenues. Services revenue increased primarily due to a $1.4 million increase at our crude terminal in Corpus Christi, Texas, which is attributable to volume increases. In addition, revenue at our Smackover refinery increased $0.8 million due to increased throughput fee and volume.

Products revenues. A 29% decrease in sales volumes at our blending and packaging facilities resulted in a $13.1 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 5%, resulting in a $2.3 million increase in product revenues.

Cost of products sold. A 29% decrease in sales volumes at our blending and packaging facilities resulted in an $11.6 million decrease. The average price per gallon increased 7%, resulting in a $2.6 million increase in cost of goods sold.

Operating expenses. Expenses at our specialty terminals increased $2.4 million, primarily due to a $1.0 million increase in pass-through expense, $0.8 million of additional repair and maintenance, and $0.3 million of increased utilities.

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 increased primarily due to business interruption insurance proceeds received related to the Stanolind tank fire.

Comparative Results of Operations for the Nine Months Ended September 30, 2014 and 2013



	Nine Months Ended September 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	101,711	$	88,770	$	12,941		15%
Products	153,451		167,550		(14,099		)	(8)%
Total revenues	255,162		256,320		(1,158		)	—%

Cost of products sold	139,028		148,624		(9,596		)	(6)%
Operating expenses	61,628		54,860		6,768			12%
Selling, general and administrative expenses	2,484		2,422		62			3%
Depreciation and amortization	27,902		22,925		4,977			22%
	24,120		27,489		(3,369		)	(12)%
Other operating income	385		168		217			129%
Operating income	$	24,505	$	27,657	$	(3,152	)	(11)%

Lubricant sales volumes (gallons)	26,170		29,885		(3,715		)	(12)%
Shore-based throughput volumes (gallons)	186,956		207,533		(20,577		)	(10)%
Smackover refinery throughput volumes (BBL per day)	5,803		6,780		(977		)	(14)%
Corpus Christi crude terminal (BBL per day)	160,332		105,783		54,549			52%

Services revenues. Services revenue increased $12.9 million, including $8.2 million attributable specialty terminals. The Corpus Christi crude terminal expansion contributed $6.3 million of this increase. In addition, revenue at our Smackover refinery increased $4.5 million due to increased pipeline fee revenue.

Products revenues. A 17% decrease in sales volumes at our blending and packaging facilities resulted in a $20.2 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 6%, resulting in a $6.8 million increase in product revenues.

Cost of products sold. A 17% decrease in sales volumes at our blending and packaging facilities resulted in an $18 million decrease. Average price per gallon increased 9%, resulting in an $8.6 million increase in cost of goods sold.

Operating expenses. Operating expenses at our Smackover refinery increased $2.7 million primarily due to increased compensation expense of $1.2 million and $1.4 million increase in pass-through expense. Operating expenses at our Corpus Christi crude terminal increased $4.5 million primarily as a result of increased wharfage and regulatory 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 increased primarily due to business interruption insurance proceeds received related to the Stanolind tank fire.

Natural Gas Services Segment

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



	Three Months Ended September 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues:
Marine transportation	$	—	$	630	$	(630	)	(100)%
Services	5,764		—		5,764
Products	230,294		204,296		25,998			13%
Total revenues	236,058		204,926		31,132			15%

Cost of products sold	218,882		196,719		22,163			11%
Operating expenses	4,546		1,863		2,683			144%
Selling, general and administrative expenses	3,507		1,156		2,351			203%
Depreciation and amortization	2,684		598		2,086			349%
Operating income	$	6,439	$	4,590	$	1,849		40%

Distributions from unconsolidated entities	$	982	$	761	$	221		29%

NGL sales volumes (Bbls)	3,737		3,162		575			18%

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. Services revenue for the three months ended September 30, 2014 represents the natural gas storage revenue related to the acquisition of Cardinal which occurred August 29, 2014. Natural gas services sales volumes increased 18%, resulting in a positive impact on revenues of $35.4 million. Our NGL average sales price per barrel decreased $2.98, or 5%, resulting in a decrease to revenue of $9.4 million.

Cost of products sold. Our average cost per barrel decreased $3.64, or 6%. Our margins increased $0.66 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 $1.7 million due to the acquisition of Cardinal. The remaining increase is primarily a result of activity at our NGL marine facility in Corpus Christi, Texas.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.8 million due to the acquisition of Cardinal. The remaining increase is primarily a result of increased compensation expense.

Depreciation and amortization. The increase in depreciation and amortization is primarily due to the acquisition of Cardinal.

Distributions from unconsolidated entities. Distributions from West Texas LPG Pipeline L.P. ("WTLPG") were $0.6 million in the 2014. The investment in WTLPG was acquired in May 2014. Distributions from Martin Energy Trading LLC ("MET") and Cardinal decreased $0.2 million each in 2014.

Comparative Results of Operations for the Nine Months Ended September 30, 2014 and 2013



	Nine Months Ended September 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues:
Marine transportation	$	365	$	2,475	$	(2,110	)	(85)%
Services	5,764		—		5,764
Products	812,232		650,605		161,627			25%
Total revenues	818,361		653,080		165,281			25%

Cost of products sold	779,136		627,748		151,388			24%
Operating expenses	8,779		3,834		4,945			129%
Selling, general and administrative expenses	6,684		2,800		3,884			139%
Depreciation and amortization	3,863		1,444		2,419			168%
Operating income	$	19,899	$	17,254	$	2,645		15%

Distributions from unconsolidated entities	$	2,323	$	2,722	$	(399	)	(15)%

NGL sales volumes (Bbls)	12,734		9,883		2,851			29%

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. Services revenue for the nine months ended September 30, 2014 represents the natural gas storage revenue related to the acquisition of Cardinal which occurred August 29, 2014. Natural gas services sales volumes increased 29%, positively impacting revenues $181.9 million. The increase in volumes was a result of additional operations in the Louisiana butane market. Our NGL average sales price per barrel decreased $2.05, or 3%, resulting in a decrease to revenues of $20.2 million.

Cost of products sold. Our average cost per barrel decreased $2.33, or 4%. Our margins increased $0.29 per barrel during the period as a result of decreased market prices.

Operating expenses. Operating expenses increased $1.7 million due to the acquisition of Cardinal. The remaining increase is primarily as a result of activity at our NGL marine facility in Corpus Christi, Texas.

Depreciation and amortization. The increase in depreciation and amortization is primarily due to the acquisition of Cardinal as well as the addition of recent capital expenditures.

Distributions from unconsolidated entities. Distributions from WTLPG were $0.6 million in 2014. The investment in WTLPG was acquired in May 2014. Distributions from MET increased $0.3 million while distributions from Cardinal decreased $1.3 million.

Sulfur Services Segment

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



	Three Months Ended September 30,				Variance		Percent Change
	2014		2013		Variance		Percent Change
	(In thousands)
Revenues:
Services	$	3,037	$	3,001	$	36	1%
Products	46,993		39,096		7,897		20%
Total revenues	50,030		42,097		7,933		19%

Cost of products sold	38,932		34,085		4,847		14%
Operating expenses	4,497		4,166		331		8%
Selling, general and administrative expenses	1,166		1,069		97		9%
Depreciation and amortization	2,078		2,024		54		3%
Operating income	$	3,357	$	753	$	2,604	346%

Sulfur (long tons)	251.0		211.8		39.2		19%
Fertilizer (long tons)	52.1		44.8		7.3		16%
Total sulfur services volumes (long tons)	303.1		256.6		46.5		18%

Revenues. Product revenues were positively impacted by rising market prices in our sulfur business. Revenues increased $7.2 million due to an 18% increase in sales volumes. Additionally, revenues increased $0.7 million as a result of a 2% increase in average sales price.

Cost of products sold. A 3% decrease in prices reduced cost of products sold by $1.1 million. An 18% increase in volumes increased our costs by an additional $6.0 million. Margin per ton increased $7.07, or 36%, resulting in an increase in gross margin of $3.1 million.

Operating expenses. Our operating expenses increased as a result of higher fuel 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 Nine Months Ended September 30, 2014 and 2013



	Nine Months Ended September 30,				Variance			Percent Change
	2014		2013		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	9,112	$	9,003	$	109		1%
Products	157,706		164,375		(6,669		)	(4)%
Total revenues	166,818		173,378		(6,560		)	(4)%

Cost of products sold	122,281		131,849		(9,568		)	(7)%
Operating expenses	13,283		12,791		492			4%
Selling, general and administrative expenses	3,404		3,132		272			9%
Depreciation and amortization	6,092		5,947		145			2%
Operating income	$	21,758	$	19,659	$	2,099		11%

Sulfur (long tons)	645.5		614.9		30.6			5%
Fertilizer (long tons)	233.1		219.8		13.3			6%
Total sulfur services volumes (long tons)	878.6		834.7		43.9			5%

Revenues. Product revenue declined $14.6 million attributable to a 9% decrease in prices. An increase in sales volumes resulted in increased revenue of $7.9 million.

Cost of products sold. Cost of products sold decreased $15.7 million due to a 12% reduction in prices. An increase in volumes resulted in a $6.1 million increase in cost of products sold. Margin per ton increased $1.35, or 3%, resulting in an increase in gross margin of $2.9 million.

Operating expenses. Our operating expenses increased primarily as a result of higher tank car lease 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 September 30, 2014 and 2013



	Three Months Ended September 30,					Variance			Percent Change
	2014			2013		Variance			Percent Change
	(In thousands)
Revenues	$	25,859		$	24,751	$	1,108		4%
Operating expenses	19,181			19,352		(171		)	(1)%
Selling, general and administrative expenses	364			228		136			60%
Depreciation and amortization	2,469			2,544		(75		)	(3)%
	3,845			2,627		1,218			46%
Impairment of long-lived assets	(3,445		)	—		(3,445		)
Operating income	$	400		$	2,627	$	(2,227	)	(85)%

Inland revenues. A $0.5 million increase in inland revenues is primarily attributable to $0.2 million from increased utilization of the inland fleet. In addition, ancillary charges, primarily the rebill of fuel, increased $0.3 million.

Offshore revenues. A $0.5 million increase in offshore revenue consists primarily of ancillary charges, related to the rebill of fuel.

Operating expenses. Operating expenses decreased as a result of decreased repairs and maintenance expense of $0.7 million, outside towing of $0.3 million, and $0.2 million of property and liability premiums. Offsetting these decreases is an increase in pass-through ancillary expenses of $1.0 million.

Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily due to an increase in legal fees.

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

Impairment of long-lived assets. Impairment of long-lived assets represents the write-down of one offshore tow.

Comparative Results of Operations for the Nine Months Ended September 30, 2014 and 2013



	Nine Months Ended September 30,					Variance			Percent Change
	2014			2013		Variance			Percent Change
	(In thousands)
Revenues	$	73,255		$	75,004	$	(1,749	)	(2)%
Operating expenses	60,805			61,417		(612		)	(1)%
Selling, general and administrative expenses	867			1,000		(133		)	(13)%
Depreciation and amortization	7,472			7,628		(156		)	(2)%
	4,111			4,959		(848		)	(17)%
Impairment of long-lived assets	(3,445		)	—		(3,445		)
Other operating income	16			628		(612		)	(97)%
Operating income	$	682		$	5,587	$	(4,905	)	(88)%

Inland revenues. Inland revenues increased $1.6 million as a result of $2.0 million related to increased utilization of the inland fleet. Offsetting this increase was a reduction of $0.4 million in ancillary charges, primarily rebill expenses.

Offshore revenues. A decrease in offshore revenues of $3.8 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 a result of decreased outside towing of $1.4 million, group life and health insurance of $1.0 million, barge rental of $1.0 million, and property insurance premiums and claims of $0.2 million. Offsetting these decreases is an increase of repairs and maintenance of $3.0 million.

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

Impairment of long-lived assets. Impairment of long-lived assets represents the write-down of one offshore tow.

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 September 30, 2014 and 2013



	Three Months Ended September 30,					Variance			Percent Change
	2014		2013			Variance			Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	1,138	$	—		1,138
Equity in earnings (loss) of Cardinal	1,135		(984		)	2,119			215%
Equity in earnings of MET	382		577			(195		)	(34)%
Equity in loss of Caliber	—		(170		)	170			100%
Equity in earnings (loss) of unconsolidated entities	$	2,655	$	(577	)	$	3,232		(560)%

The investment in WTLPG was acquired in May 2014.

The increase in equity in earnings of Cardinal is 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 the second quarter of 2013. Cadeville and Perryville are subsidiaries of Cardinal. In addition, the 2013 period includes a $1.8 million one-time charge for employee severance and incentive payments for the completion of the Cadeville and Perryville projects ahead of schedule and under budget. On August 29, 2014, the Partnership acquired the approximate 57.8% Category A interest in Cardinal it did not previously own. Results of operations are included in the Natural Gas Services segment subsequent to that date.

Equity in earnings of MET, recorded initially in April 2013, represent dividends on our 100% investment in its preferred interests. During March 2013, the Partnership acquired 100% of the preferred interests in MET, a subsidiary of Martin Resource Management, for $15,000. In August, 2014, MET converted its preferred equity to subordinated debt, resulting in a note receivable from MET.

The investment in Caliber Gathering, LLC (“Caliber”) was sold in November 2013. As a result, there is no equity in earnings (loss) in the 2014 period.

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



	Nine Months Ended September 30,					Variance		Percent Change
	2014		2013			Variance		Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	1,907	$	—		$	1,907
Equity in earnings (loss) of Cardinal	892		(1,561		)	2,453		157%
Equity in earnings of MET	1,498		1,171			327		28%
Equity in loss of Caliber	—		(488		)	488		100%
Equity in earnings (loss) of unconsolidated entities	$	4,297	$	(878	)	$	5,175	589%

The investment in WTLPG was acquired in May 2014.

The increase in equity in earnings of Cardinal is attributable to improved Cardinal results of operations primarily due to Cadeville and Perryville, both of which were completed late in the second quarter of 2013. Cadeville and Perryville are subsidiaries of Cardinal. In addition, the 2013 period includes a $1.8 million one-time charge for employee severance and incentive payments for the completion of the Cadeville and Perryville projects ahead of schedule and under budget. On August 29, 2014, the Partnership acquired the approximate 57.8% Category A interest in Cardinal it did not previously own.

The investment in Caliber was sold in November 2013. As a result, there is no equity in earnings (loss) in the 2014 period.

Interest Expense

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



	Three Months Ended September 30,						Variance			Percent Change
	2014			2013			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	3,719		$	2,010		$	1,709		85%
8.875% Senior notes	—			3,883			(3,883		)	(100)%
7.250% Senior notes	7,251			4,531			2,720			60%
Amortization of deferred debt issuance costs	827			815			12			1%
Amortization of debt discount and premium	(82		)	77			(159		)	(206)%
Impact of interest rate derivative activity	63			—			63
Other	(85		)	70			(155		)	(221)%
Capitalized interest	(234		)	(326		)	92			28%
Total interest expense	$	11,459		$	11,060		$	399		4%

Comparative Components of Interest Expense for the Nine Months Ended September 30, 2014 and 2013



	Nine Months Ended September 30,						Variance			Percent Change
	2014			2013			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	8,325		$	5,273		$	3,052		58%
8.875 % Senior notes	3,882			11,648			(7,766		)	(67)%
7.250 % Senior notes	19,002			11,530			7,472			65%
Amortization of deferred debt issuance costs	5,415			2,890			2,525			87%
Amortization of debt discount and premium	1,141			230			911			396%
Impact of interest rate derivative activity	(2,864		)	—			(2,864		)
Other	407			231			176			76%
Capitalized interest	(957		)	(744		)	(213		)	29%
Total interest expense	$	34,351		$	31,058		$	3,293		11%

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 Statement of Operations for the nine months ended September 30, 2014.

Indirect Selling, General and Administrative Expenses



	Three Months Ended September 30,				Variance		Percent Change	Nine Months Ended September 30,				Variance		Percent Change
	2014		2013		Variance		Percent Change	2014		2013		Variance		Percent Change
	(In thousands)							(In thousands)
Indirect selling, general and administrative expenses	$	4,479	$	3,779	$	700	19%	$	14,214	$	11,270	$	2,944	26%

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

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

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



	Three Months Ended September 30,				Variance		Percent Change	Nine Months Ended September 30,				Variance		Percent Change
	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%	$	9,401	$	7,966	$	1,435	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 September 29, 2014, we completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $122.6 million. Our general partner contributed $2.6 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.

On August 29, 2014, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45.0 million in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10-day weighted average price of our common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, our general partner contributed $0.9 million in order to maintain its 2% general partner interest in us. The proceeds from the common unit issuances were used to pay down outstanding amounts under our revolving credit facility.

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 $3.5 million and $20.6 million during the three and nine months ended September 30, 2014, respectively. The Partnership paid $0.1 million and $0.3 million in compensation to the Sales Agents for the three and nine months ended September 30, 2014, respectively. Under the the program, we issued 89,252 and 506,408 common units during the three and nine months ended September 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 $0.4 million during the nine months ended September 30, 2014 related to these issuances 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 - Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

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



	Nine Months Ended September 30,						Variance			Percent Change
	2014			2013			Variance			Percent Change
	(In thousands)
Net cash provided by (used in):
Operating activities	$	53,001		$	62,168		$	(9,167	)	(15)%
Investing activities	(296,464		)	(167,119		)	(129,345		)	(77)%
Financing activities	229,927			99,834			130,093			130%
Net decrease in cash and cash equivalents	$	(13,536	)	$	(5,117	)	$	(8,419	)	(165)%

Net cash provided by operating activities for the nine months ended September 30, 2014 decreased compared to the prior year period primarily due to an $18.4 million unfavorable variance in working capital. In addition, 2013 included $8.7 million of cash used in discontinued operating activities. There was no cash used in or provided by operating activities in 2014.

Net cash used in investing activities for the nine months ended September 30, 2014 increased compared to the prior year period due to a $134.4 million equity investment in WTLPG in 2014. In addition, cash paid for acquisitions increased $26.1 million in the 2014 period. Finally, contributions to unconsolidated entities decreased $27.5 million in 2014.

Net cash provided by financing activities for the nine months ended September 30, 2014 increased compared to the prior period due to $331.6 million in net proceeds from the issuance of common units during 2014 offset by a $204.8 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 September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In thousands)				(In thousands)
Expansion capital expenditures	$	12,979	$	36,999	$	45,262	$	61,118
Maintenance capital expenditures	4,306		2,973		13,260		7,473
Plant turnaround costs	90		—		4,000		—
Total	$	17,375	$	39,972	$	62,522	$	68,591

Expansion capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Natural Gas Services segments during the three and nine months ended September 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. Within our Natural Gas Services segment, expenditures were made on ongoing organic growth projects. 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 nine months ended September 30, 2014. For the three and nine months ended September 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 nine months ended September 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 nine months ended September 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 September 30, 2014, we had $910.1 million of outstanding indebtedness, consisting of outstanding borrowings of $402.1 million (including unamortized premium) under our Senior Notes due in 2021 and $508.0 million under our revolving credit facility.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 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	$	508,000	$	—	$	—	$	508,000	$	—
2021 Senior unsecured notes	402,077		—		—		—		402,077
Throughput commitment	40,641		5,069		10,632		11,327		13,613
Operating leases	40,190		11,462		17,924		5,643		5,161
Interest expense: ¹
Revolving credit facility	51,660		14,812		29,624		7,224		—
2021 Senior unsecured notes	186,083		29,000		58,000		58,000		41,083
Total contractual cash obligations	$	1,228,651	$	60,343	$	116,180	$	590,194	$	461,934

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

Letters of Credit. At September 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 September 30, 2014, we had $508.0 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 $381.4 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 September 30, 2014, we have the ability to incur approximately $80.5 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 nine months ended September 30, 2014, the level of outstanding draws on our credit facility has ranged from a low of $220.0 million to a high of $657.0 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 September 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 October 29, 2014, our outstanding indebtedness includes $500.0 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 nine months ended September 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 nine months ended September 30, 2014 or 2013.



Item 3.	Quantitative and Qualitative Disclosures about Market Risk

Commodity Risk. The Partnership from time to time uses derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. We have established a hedging policy and monitor and manage the commodity market risk associated with potential commodity risk exposure. In addition, we focus on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

We are exposed to commodity risk associated with the future purchase of natural gas. We utilize derivatives to manage exposure associated with commodity price risk by entering into call options to place a limit on the commodity price of the future purchase of base gas. All derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings.

As of September 30, 2014, we had a notional quantity of 3,631,740 MMBtu of natural gas call options with a strike price of $4.50 per MMBtu. These options manage the purchase of base gas at Monroe Gas Storage Company, LLC for the portion of base gas that is currently leased with Credit Suisse scheduled to be returned in January and February 2015. The options settle in two increments of 2,345,498 MMBtu and 1,286,242 MMBtu on January 31, 2015 and February 28, 2015, respectively.

Commodity Derivative Contracts in Place

As of September 30, 2014

(Dollars in Thousands)

Date of Option

Counterparty

Settlement Date

Notional Amount (MMBTU)

Settlement

Pricing Terms

Fair Value Asset

Fair Value Liability

June 2012

RBC

January - February 2015

3,631,740

Fixed price of $4.50/MMBTU settled against Henry Hub Natural Gas Index

830

—

3,631,740

830

—

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 2.92% as of September 30, 2014. Based on the amount of unhedged floating rate debt owed by us on September 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 $5.1 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 $420.9 million as of September 30, 2014, based on market prices of similar debt at September 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 $19.4 million decrease in fair value of our long-term debt at September 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 $14.9 million.

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



Interest Rate Swaps
As of September 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%	$	—	$	271
May 2014	SunTrust	February 2021	100,000		3 MO LIBOR plus 4.925%	7.25%	—		271
September 2014	SunTrust	September 2019	50,000		3 MO LIBOR	2.09%	49		—
			$	250,000			$	49	$	542



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: 10/29/2014	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 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 Arcadia Gas Storage, LLC, dated June 26, 2006.
3.12*	Company Agreement of Arcadia Gas Storage, LLC, dated December 27, 2006.
3.13*	Amendment to the Company Agreement of Arcadia Gas Storage, LLC, dated September 5, 2014.
3.14*	Certificate of Formation of Cadeville Gas Storage LLC, dated May 23, 2008.
3.15*	Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated May 23, 2008.
3.16*	First Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated April 16, 2012.
3.17*	Second Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated September 5, 2014.
3.18*	Certificate of Formation of Monroe Gas Storage Company, LLC, dated June 14, 2006.
3.19*	Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated May 31, 2011.
3.20*	First Amendment to the Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated September 5, 2014.
3.21*	Certificate of Formation of Perryville Gas Storage LLC, dated May 23, 2008.
3.22*	Limited Liability Company Agreement of Perryville Gas Storage LLC, dated June 16, 2008.
3.23*	First Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated April 14, 2010.
3.24*	Second Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated September 5, 2014.
3.25*	Certificate of Formation of Cardinal Gas Storage Partners LLC, dated April 2, 2008.



3.26*	Third Amended and Restated Limited Liability Company Agreement of Cardinal Gas Storage Partners LLC (F/K/A Redbird Gas Storage LLC) dated October 27, 2014.
3.27*	Certificate of Merger of Cardinal Gas Storage Partners LLC with and into Redbird Gas Storage LLC, dated October 27, 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 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*	Second Supplemental Indenture, to the Indenture dated February 11, 2013 dated September 30, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee.
4.5*	Third Supplemental Indenture, to the Indenture dated February 11, 2013 dated October 27, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee.
10.1	Third Amendment to Third Amended and Restated Credit Agreement, dated 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).
10.2	Membership Interests Purchase Agreement, dated August 10, 2014, by and among Energy Capital Partners and its affiliated funds and Redbird Gas Storage LLC (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (Sec File No. 000-50056), filed August 12, 2014, and incorporated herein by reference).
10.3	Common Unit Purchase Agreement, dated August 20, 2014, by and between the Partnership and Martin Product Sales LLC (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (Sec File No. 000-50056), filed August 22, 2014, and incorporated herein by reference).
10.4	Amended and Restated Common Unit Purchase Agreement, dated August 29, 2014, by and between the Partnership and Martin Product Sales LLC (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (Sec File No. 000-50056), filed September 2, 2014, and incorporated herein by reference).
10.5*	2014 Amended and Restated Tolling Agreement, dated October 28, 2014, by and between the Operating Partnership and Cross Oil Refining & Marketing, Inc.
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended September, 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

Martin Midstream Partners - 10-Q quarterly report FY2014 Q3

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