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 March 31, 2014

OR

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 May 2, 2014, was 27,039,432.

		Page
PART I – FINANCIAL INFORMATION		2
Item 1. Financial Statements		2
	Consolidated and Condensed Balance Sheets as of March 31, 2014 (unaudited) and December 31, 2013 (audited)	2
	Consolidated and Condensed Statements of Operations for the Three Months Ended March 31, 2014 and 2013 (unaudited)	3
	Consolidated and Condensed Statements of Capital for the Three Months Ended March 31, 2014 and 2013 (unaudited)	5
	Consolidated and Condensed Statements of Cash Flows for the Three Months Ended March 31, 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		24
Item 3. Quantitative and Qualitative Disclosures about Market Risk		42
Item 4. Controls and Procedures		43
PART II. OTHER INFORMATION		44
Item 1. Legal Proceedings		44
Item 1A. Risk Factors		44
Item 6. Exhibits		44

1

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	March 31, 2014			December 31, 2013
	(Unaudited)			(Audited)
Assets
Cash	$	4,371		$	16,542
Accounts and other receivables, less allowance for doubtful accounts of $2,129 and $2,492, respectively	133,579			163,855
Product exchange receivables	901			2,727
Inventories	94,771			94,902
Due from affiliates	16,448			12,099
Other current assets	7,734			7,353
Total current assets	257,804			297,478
Property, plant and equipment, at cost	946,784			929,183
Accumulated depreciation	(314,352		)	(304,808		)
Property, plant and equipment, net	632,432			624,375
Goodwill	23,802			23,802
Investment in unconsolidated entities	129,336			128,662
Debt issuance costs, net	15,190			15,659
Other assets, net	9,048			7,943
	$	1,067,612		$	1,097,919
Liabilities and Partners’ Capital
Trade and other accounts payable	$	128,149		$	142,951
Product exchange payables	17,504			9,595
Due to affiliates	3,044			2,596
Income taxes payable	1,504			1,204
Other accrued liabilities	15,565			20,242
Total current liabilities	165,766			176,588
Long-term debt and capital lease obligations, less current installments	643,772			658,695
Other long-term obligations	1,981			2,219
Total liabilities	811,519			837,502
Commitments and contingencies
Partners’ capital	256,093			260,417
	$	1,067,612		$	1,097,919

See accompanying notes to consolidated and condensed financial statements.

2

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended
	March 31,
	2014			2013
Revenues:
Terminalling and storage  *	$	31,801		$	28,891
Marine transportation  *	23,410			24,980
Sulfur services	3,037			3,001
Product sales: *
Natural gas services	333,337			259,109
Sulfur services	51,170			67,384
Terminalling and storage	54,273			50,321
	438,780			376,814
Total revenues	497,028			433,686
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	320,698			248,778
Sulfur services *	37,853			52,797
Terminalling and storage *	48,029			43,815
	406,580			345,390
Expenses:
Operating expenses  *	43,896			43,360
Selling, general and administrative  *	8,606			7,030
Depreciation and amortization	13,992			11,893
Total costs and expenses	473,074			407,673
Other operating (expense) income	(45		)	372
Operating income	23,909			26,385
Other income (expense):
Equity in loss of unconsolidated entities	(296		)	(374		)
Interest expense	(11,451		)	(9,058		)
Other, net	(67		)	(9		)
Total other expense	(11,814		)	(9,441		)
Net income before taxes	12,095			16,944
Income tax expense	(300		)	(307		)
Net income	11,795			16,637
Less general partner's interest in net income	(236		)	(333		)
Less income allocable to unvested restricted units	(32		)	(43		)
Limited partners' interest in net income	$	11,527		$	16,261
Net income per unit attributable to limited partners - basic	$	0.43		$	0.61
Weighted average limited partner units - basic	26,572			26,561
Net income per unit attributable to limited partners - diluted	$	0.43		$	0.61
Weighted average limited partner units - diluted	26,605			26,569

See accompanying notes to consolidated and condensed financial statements.

*Related Party Transactions Shown Below

3

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
	March 31,
	2014		2013
Revenues:
Terminalling and storage	$	18,010	$	17,328
Marine transportation	5,849		6,843
Product Sales	1,892		1,209
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	8,453		8,556
Sulfur services	4,865		4,534
Terminalling and storage	9,844		11,961
Expenses:
Operating expenses	18,239		17,974
Selling, general and administrative	5,384		4,418

See accompanying notes to consolidated and condensed financial statements.

4

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)

	Partners’ Capital
	Common Limited					General Partner Amount
	Units		Amount						Total
Balances - January 1, 2013	26,566,776		$	349,490		$	8,472		$	357,962
Net income	—		16,304			333			16,637
Issuance of restricted units	57,750		—			—			—
General partner contribution	—		—			37			37
Cash distributions	—		(20,501		)	(456		)	(20,957		)
Unit-based compensation	—		256			—			256
Balances - March 31, 2013	26,624,526		$	345,549		$	8,386		$	353,935
Balances - January 1, 2014	26,625,026		$	254,028		$	6,389		$	260,417
Net income	—		11,559			236			11,795
Issuance of common units	132,580		5,235			—			5,235
Issuance of restricted units	6,400		—			—			—
Forfeiture of restricted units	(2,750	)	—			—			—
General partner contribution	—		—			114			114
Cash distributions	—		(20,898		)	(472		)	(21,370		)
Unit-based compensation	—		179			—			179
Purchase of treasury units	(6,400	)	(277		)	—			(277		)
Balances - March 31, 2014	26,754,856		$	249,826		$	6,267		$	256,093

See accompanying notes to consolidated and condensed financial statements.

5

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Three Months Ended
	March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	11,795		$	16,637
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	13,992			11,893
Amortization of deferred debt issuance costs	810			1,269
Amortization of debt discount	77			76
Loss (gain) on sale of property, plant and equipment	45			(372		)
Equity in loss of unconsolidated entities	296			374
Unit-based compensation	179			256
Other	—			6
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	27,801			56,639
Product exchange receivables	1,826			(2,625		)
Inventories	131			25,494
Due from affiliates	(4,349		)	(25,635		)
Other current assets	(381		)	(1,046		)
Trade and other accounts payable	(19,635		)	(24,429		)
Product exchange payables	7,909			8,445
Due to affiliates	448			2,394
Income taxes payable	300			484
Other accrued liabilities	(4,677		)	4,185
Change in other non-current assets and liabilities	(43		)	26
Net cash provided by continuing operating activities	36,524			74,071
Net cash used in discontinued operating activities	—			(8,678		)
Net cash provided by operating activities	36,524			65,393
Cash flows from investing activities:
Payments for property, plant and equipment	(16,642		)	(14,715		)
Acquisitions	—			(50,801		)
Payments for plant turnaround costs	(2,164		)	—
Proceeds from sale of property, plant and equipment	245			3,610
Proceeds from involuntary conversion of property, plant and equipment	2,475			—
Investment in unconsolidated subsidiaries	—			(15,000		)
Return of investments from unconsolidated entities	225			525
Contributions to unconsolidated entities	(1,195		)	(9,365		)
Net cash used in investing activities	(17,056		)	(85,746		)
Cash flows from financing activities:
Payments of long-term debt	(91,000		)	(373,000		)
Payments of notes payable and capital lease obligations	—			(81		)
Proceeds from long-term debt	76,000			418,000
Net proceeds from issuance of common units	5,235			—
General partner contribution	114			37
Purchase of treasury units	(277		)	—
Payment of debt issuance costs	(341		)	(8,761		)
Cash distributions paid	(21,370		)	(20,957		)
Net cash (used in) provided by financing activities	(31,639		)	15,238
Net decrease in cash	(12,171		)	(5,115		)
Cash at beginning of period	16,542			5,162
Cash at end of period	$	4,371		$	47
Non-cash additions to property, plant and equipment	$	4,833		$	—

See accompanying notes to consolidated and condensed financial statements.

6

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 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”), a newly-formed sole member of Martin Midstream GP LLC (“MMGP”), the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners (“Alinda”). Upon closing the transaction, Alinda appointed two representatives to serve as directors of the general partner.

(2) New Accounting Pronouncements

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

(3) Acquisitions

Marine Transportation Equipment Purchase

On September 30, 2013, the Partnership acquired two 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

7

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 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 $667 and net income of $191 for the three months ended March 31, 2014 related to the Cactus acquisition.

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 included revenues of $3,652 and net income of $162 for the three months ended March 31, 2014 related to the NLG acquisition.

NGL Marine Equipment Purchase

On February 28, 2013, the Partnership purchased from affiliates of Florida Marine Transporters, Inc. six liquefied petroleum gas pressure barges and two commercial push boats for approximately $50,801, of which the commercial push boats totaling $8,201 were allocated to property, plant and equipment in the Partnership's Marine Transportation segment and the six

8

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

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 three months ended March 31, 2013.

(5) Inventories

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

	March 31, 2014		December 31, 2013
Natural gas liquids	$	21,602	$	31,859
Sulfur	18,515		8,912
Sulfur based products	16,626		17,584
Lubricants	35,173		33,847
Other	2,855		2,700
	$	94,771	$	94,902

(6) Investments in Unconsolidated Entities and Joint Ventures

At March 31, 2014, the Partnership owned an unconsolidated 42.21% interest in Cardinal Gas Storage Partners LLC (“Cardinal”).  

During the fourth quarter of 2013, the Partnership sold its unconsolidated 50% interest in Caliber Gathering, LLC (“Caliber”).

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

These investments are accounted for by the equity method.

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

	March 31, 2014		December 31, 2013
Redbird	$	113,781	$	113,662
MET	15,555		15,000
Total investment in unconsolidated entities	$	129,336	$	128,662

9

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

	Three Months Ended March 31,
	2014			2013
Equity in loss of Redbird	$	(851	)	$	(216	)
Equity in earnings of MET	555			—
Equity in loss of Caliber	—			(158		)
Equity in loss of unconsolidated entities	$	(296	)	$	(374	)

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

	As of March 31,				Three Months Ended March 31,
	Total Assets		Members' Equity		Revenues		Net Income (Loss)
2014
Cardinal	$	646,963	$	346,860	$	18,429	$	(2,017	)
	As of December 31,
2013
Cardinal	$	661,816	$	346,584	$	8,087	$	451

As of March 31, 2014 and December 31, 2013, the Partnership’s interest in cash of the unconsolidated equity-method investees was $6,287 and $3,703, respectively.

(7) Derivative Instruments and Hedging Activities

The Partnership’s results of operations are materially impacted by changes in crude oil, natural gas and NGL prices and interest rates. In an effort to manage its exposure to these risks, the Partnership periodically enters into various derivative instruments, including commodity and interest rate hedges.

(a)    Commodity Derivative Instruments

The Partnership has from time to time used derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure.  These hedging arrangements have been in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership did not have any commodity derivative instruments outstanding during the three months ended March 31, 2014 or 2013.

(b)    Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. From time to time, the Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit facility and senior unsecured notes. The Partnership did not have any interest rate derivative instruments outstanding during the three months ended March 31, 2014 or 2013.

(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.

10

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

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 March 31, 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	March 31, 2014		(Level 1)		(Level 2)		(Level 3)
Liabilities
2018 Senior unsecured notes	$	182,767	$	—	$	182,767	$	—
2021 Senior unsecured notes	263,786		—		263,786		—
Total liabilities	$	446,553	$	—	$	446,553	$	—

	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.

11

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

(9) Other Accrued Liabilities

Components of other accrued liabilities were as follows:

	March 31, 2014		December 31, 2013
Accrued interest	$	10,301	$	11,038
Property and other taxes payable	3,620		6,785
Accrued payroll	1,308		2,186
Other	336		233
	$	15,565	$	20,242

(10) Long-Term Debt and Capital Leases

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

	March 31, 2014		December 31, 2013
$637,5003 Revolving credit facility at variable interest rate (3.16%1 weighted average at March 31, 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	$	220,000	$	235,000
$200,0002 Senior notes, 8.875% interest, net of unamortized discount of $1,228 and $1,305, respectively, issued March 2010 and due April 2018, unsecured	173,772		173,695
$250,000 Senior notes, 7.250% interest, issued February 2013 and due February 2021, unsecured	250,000		250,000
Total long-term debt	643,772		658,695
Less current installments	—		—
Long-term debt, net of current installments	$	643,772	$	658,695

¹ Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%.  The applicable margin for existing LIBOR borrowings at March 31, 2014 is 3.00%. 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 has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings.  On April 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 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.

³ Effective February 18, 2014, the Partnership increased the maximum amount of borrowings and letters of credit available under the Partnership's revolving credit facility from $600,000 to $637,500 and extended the maturity date of the facility from April 2016 to March 2018.

12

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

The Partnership paid cash interest in the amount of $11,689 and $2,217 for the three months ended March 31, 2014 and 2013, respectively.  Capitalized interest was $388 and $180 for the three months ended March 31, 2014 and 2013, respectively.

(11) Partners' Capital

As of March 31, 2014, partners’ capital consisted of 26,754,856 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owned 5,093,267 of the Partnership's common limited partnership units representing approximately 19.0% 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

In March 2014, the Partnership entered into an equity distribution agreement with multiple underwriters (the “Sales Agents”) for the ongoing distribution of the Partnership's common units. Pursuant to this program, the Partnership offered and sold common unit equity through the Sales Agents for aggregate proceeds of $5,654 during the three months ended March 31, 2014. Sales were at market prices prevailing at the time of the sale. The Partnership also received capital contributions from the general partner of $114 during the three months ended March 31, 2014, 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. No incentive distributions were allocated to the general partner from July 1, 2012 through March 31, 2014. As of March 31, 2014, the amount of incentive distributions the general partner has foregone is $11,867, resulting in an amount remaining of $6,133.

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

For the three months ended March 31, 2014 and 2013, the general partner received no incentive distributions.

Distributions of Available Cash

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

13

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

Net Income per Unit

The Partnership follows the provisions of the FASB ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.

For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method. The following is a reconciliation of net income allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended March 31,
	2014			2013
Net income attributable to Martin Midstream Partners L.P.	$	11,795		$	16,637
Less general partner’s interest in net income:
Distributions payable on behalf of general partner interest	472			456
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	(236		)	(123		)
Less income allocable to unvested restricted units	32			43
Limited partners’ interest in net income	$	11,527		$	16,261

The weighted average units outstanding for basic net income per unit were 26,571,666 and 26,560,654 for the three months ended March 31, 2014 and 2013, respectively.  For diluted net income per unit, the weighted average units outstanding were increased by 33,101 and 8,756 for the three months ended March 31, 2014 and 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 March 31, 2014, Martin Resource Management owned 5,093,267 of the Partnership’s common units representing approximately 19.0% 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 March 31, 2014, of approximately 19.0% 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.

14

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

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 of Martin Resource Management’s trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

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

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

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

•distributing NGLs; and

•manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.

This restriction does not apply to:

• the ownership and/or operation on the Partnership’s behalf of any asset or group of assets owned by it or its affiliates;

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

◦ providing land transportation of various liquids;

◦ distributing fuel oil, sulfuric acid, marine fuel and other liquids;

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

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

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

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

◦ operating an environmental consulting company;

◦ operating an engineering services company;

◦ 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

15

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

◦ 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 $3,190 and $2,657 of indirect expenses for the three months ended March 31, 2014 and 2013, respectively.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

These indirect expenses are intended to cover the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the general partner of the Partnership.

Related  Party Transactions. The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read “Services” above.

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

Amendment and Termination. The Omnibus Agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management.  The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.  Such amendments were approved by the Conflicts Committee.  The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.

16

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

Motor Carrier Agreement

Motor Carrier Agreement.  The Partnership is a party to a motor carrier agreement effective January 1, 2006 as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGL's as well as other liquid products.

Term and Pricing. The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term.  The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice. These rates are subject to any adjustments which are mutually agreed upon or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list.

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

Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates.  Effective each January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.

Marine Fuel.  The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil.  Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.

Terminal Services Agreements

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

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

Talen's Agreements. In connection with the Talen's 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.

17

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

Other Agreements

 Cross Tolling Agreement. The Partnership is a party to an agreement with Cross, originally dated November 25, 2009, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The tolling agreement, which has subsequently been amended, has a 22 year term which expires November 25, 2031.  Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel.  Any additional barrels are processed at a modified price per barrel.  In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement.  All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period.  In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. The Partnership is party to a second amended and restated sulfuric acid sales agency agreement dated August 5, 2013, under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations.  This agreement, as amended, will remain in place until the Partnership terminates it by providing 180 days’ written notice.  Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

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

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

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

	Three Months Ended March 31,
	2014		2013
Revenues:
Terminalling and storage	$	18,010	$	17,328
Marine transportation	5,849		6,843
Product sales:
Natural gas services	829		9
Sulfur services	955		1,133
Terminalling and storage	108		67
	1,892		1,209
	$	25,751	$	25,380

18

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

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

Cost of products sold:
Natural gas services	$	8,453	$	8,556
Sulfur services	4,865		4,534
Terminalling and storage	9,844		11,961
	$	23,162	$	25,051

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

Operating Expenses:
Marine transportation	$	9,664	$	10,058
Natural gas services	606		485
Sulfur services	1,486		2,355
Terminalling and storage	6,483		5,076
	$	18,239	$	17,974

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
Natural gas services	958		579
Sulfur services	843		806
Terminalling and storage	385		361
Indirect overhead allocation, net of reimbursement	3,190		2,657
	$	5,384	$	4,418

(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 became 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 $307 were recorded in income tax expense for the three months ended March 31, 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

19

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

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.    

Three Months Ended March 31, 2014	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Terminalling and storage	$	87,297	$	(1,223	)	$	86,074	$	8,975	$	8,311		$	15,600
Natural gas services	333,633		—			333,633		504		9,465			500
Sulfur services	54,207		—			54,207		1,983		8,068			1,447
Marine transportation	24,114		(1,000		)	23,114		2,530		2,962			3,928
Indirect selling, general and administrative	—		—			—		—		(4,897		)	—
Total	$	499,251	$	(2,223	)	$	497,028	$	13,992	$	23,909		$	21,475
Three Months Ended March 31, 2013	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Terminalling and storage	$	80,353	$	(1,141	)	$	79,212	$	7,096	$	9,983		$	14,049
Natural gas services	259,439		—			259,439		292		8,462			115
Sulfur services	70,385		—			70,385		1,966		9,344			201
Marine transportation	25,232		(582		)	24,650		2,539		2,539			350
Indirect selling, general and administrative	—		—			—		—		(3,943		)	—
Total	$	435,409	$	(1,723	)	$	433,686	$	11,893	$	26,385		$	14,715

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

	March 31, 2014		December 31, 2013
Total assets:
Terminalling and storage	$	468,527	$	461,160
Natural gas services	274,584		320,631
Sulfur services	161,160		151,982
Marine transportation	163,341		164,146
Total assets	$	1,067,612	$	1,097,919

20

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

(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 March 31,
	2014		2013
Employees	$	122	$	195
Non-employee directors	57		61
Total unit-based compensation expense	$	179	$	256

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 three months ended March 31, 2014 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	72,998			$	33.26
Granted	6,400			$	43.05
Vested	(5,750		)	$	40.34
Forfeited	(2,750		)	$	31.06
Non-Vested, end of period	70,898			$	33.65
Aggregate intrinsic value, end of period	$	3,052

21

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the three and nine months ended March 31, 2014 and 2013 are provided below:

	Three Months Ended March 31,
	2014		2013
Aggregate intrinsic value of units vested	$	249	$	153
Fair value of units vested	$	247	$	168

As of March 31, 2014, there was $1,643 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.19 years.

Unit Options.  The plan currently permits the grant of options covering common units. As of May 2, 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.

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

(17) Commitments and Contingencies

From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business.  In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.

(18) Subsequent Events

Interest Rate Swaps. The Partnership entered into two interest rate swap agreements effective April 1, 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.  Under these swap agreements, the Partnership will pay a floating rate of interest and receive a fixed rate based on a three-month U.S. Dollar LIBOR rate to match the fixed rate of the senior unsecured notes.

Issuance of 7.250% Senior Unsecured Notes Due 2021. On April 1, 2014, the Partnership completed a private placement add-on of $150,000 of the 7.250% senior unsecured notes.  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 Partnership expects the exchange offer to be completed during the second quarter of 2014.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2014

(Unaudited)

Redemption of 8.875% Senior Unsecured Notes Due 2018. On April 1, 2014, the Partnership redeemed all $175,000 of the 8.875% senior unsecured notes due in 2018 from their holders. In conjunction with the redemption, the Partnership incurred a debt prepayment premium of $7,767. Additionally, the Partnership expects to record a non-cash charge of $3,871 for the write-off of unamortized debt issuance costs and unamortized debt discount related to the redemption of the senior unsecured notes. 

Quarterly Distribution. On April 23, 2014, the Partnership declared a quarterly cash distribution of $0.7875 per common unit for the first quarter of 2014, or $3.15 per common unit on an annualized basis, which will be paid on May 15, 2014 to unitholders of record as of May 5, 2014.

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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 March 31, 2014, Martin Resource Management owned 19.0% of our total outstanding common limited partner units. Furthermore, Martin Resource Management

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controls Martin Midstream GP LLC (“MMGP”), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC (“Holdings”), a sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operation through its ownership interests in and control of our general partner.

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 primarily in our Terminalling and Storage and Natural Gas Services segments.

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

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

Amendment to Revolving Credit Facility.  On February 18, 2014, we increased the maximum amount of borrowings under our revolving credit facility from $600.0 million to $637.5 million by utilizing the accordion feature of our revolving credit facility.

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

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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 March 31, 2014 and 2013:

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Allowance for Doubtful Accounts
We evaluate our allowance for doubtful accounts on an ongoing basis and record adjustments when, in management's judgment, circumstances warrant. Reserves are recorded to reduce receivables to the amount ultimately expected to be collected.	We evaluate the collectability of our accounts receivable based on factors such as the customer's ability to pay, the age of the receivable and our historical collection experience. A deterioration in any of these factors could result in an increase in the allowance for doubtful accounts balance.	If actual collection results are not consistent with our judgments, we may experience increase in uncollectible receivables. A 10% increase in our allowance for doubtful accounts would result in a decrease in net income of approximately $0.2 million.
Depreciation
Depreciation expense is computed using the straight-line method over the useful life of the assets.	Determination of depreciation expense requires judgment regarding estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, estimates are reviewed to determine if any changes in the underlying assumptions are needed.	The lives of our fixed assets range from 3 - 25 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $5.8 million, resulting in a corresponding reduction in net income.
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.	Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.	Applying this impairment review methodology, we have recorded no impairment charges during the periods ended March 31, 2014 and 2013. If actual events are not consistent with our estimates and assumptions or our estimates and assumptions change due to new information, we may incur an impairment charge.
Impairment of Goodwill
Goodwill is subject to a fair-value based impairment test on an annual basis, or more frequently if events or changes in circumstances indicate that the fair value of any of our reporting units is less than its carrying amount.	We determine fair value using accepted valuation techniques, including discounted cash flow, the guideline public company method and the guideline transaction method. These analyses require management to make assumptions and estimates regarding industry and economic factors, future operating results and discount rates. We conduct impairment testing using present economic conditions, as well as future expectations.	We completed the most recent annual review of goodwill as of August 31, 2013 and determined there was no impairment. Additionally, management is aware of no change in circumstances which indicate a need for an interim impairment evaluation.
Purchase Price Allocations
We allocate the purchase price of an acquired business to its identifiable assets (including identifiable intangible assets) and liabilities based on their fair values at the date of acquisition. Any excess of purchase price in excess of amounts allocated to identifiable assets and liabilities is recorded as goodwill. As additional information becomes available, we may adjust the preliminary allocation for a period of up to one year.	The determination of fair values of acquired assets and liabilities requires a significant level of management judgment. Fair values are estimated using various methods as deemed appropriate. For significant transactions, third party assessments may be engaged to assist in the valuation process.	If subsequent factors indicate that estimates and assumptions used to allocate costs to acquired assets and liabilities differ from actual results, the allocation between goodwill, other intangible assets and fixed assets could significantly differ. Any such differences could impact future earnings through depreciation and amortization expense. Additionally, if estimated results supporting the valuation of goodwill or other intangible assets are not achieved, impairments could result.

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Asset Retirement Obligations
Asset retirement obligations (“AROs”) associated with a contractual or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and depreciated over the life of the related asset or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled.	Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate.	If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.
Environmental Liabilities
We estimate environmental liabilities using both internal and external resources. Activities include feasibility studies and other evaluations management considers appropriate. Environmental liabilities are recorded in the period in which the obligation can be reasonably estimated.	Estimating environmental liabilities requires significant management judgment as well as possible use of third party specialists knowledgeable in such matters.	Environmental liabilities have not adversely affected our results of operations or financial condition in the past, and we do not anticipate that they will in the future.

Our Relationship with Martin Resource Management

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

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

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

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

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

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

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

• operating an environmental consulting company;

• operating an engineering services company;

• 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.

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Ownership

Martin Resource Management owns an approximate 19.0% limited partnership interest in us. In addition, Martin Resource Management controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, a sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights.

Management

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

Related Party Agreements

The Omnibus Agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business.  We reimbursed Martin Resource Management for $43.6 million of direct costs and expenses for the three months ended March 31, 2014 compared to $44.8 million for the three months ended March 31, 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 March 31, 2014 and 2013, the conflicts committee of our general partner (“Conflicts Committee”) approved reimbursement amounts of $3.2 million and $2.7 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee of our general partner's board of directors will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.  These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management’s retained businesses.  The Omnibus Agreement also contains significant non-compete provisions and indemnity obligations.  Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

The agreements include, but are not limited to, motor carrier agreements, marine transportation agreements, terminal services agreements, a tolling agreement, a sulfuric acid agreement, and various other miscellaneous agreements. Pursuant to the terms of the Omnibus Agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee of our general partner’s board of directors.

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

We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.2 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 6% of our total cost of products sold during the three months ended March 31, 2014. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 7% of our total cost of products sold during

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the three months ended March 31, 2013. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates.  Our sales to Martin Resource Management accounted for approximately 5% and 6% of our total revenues for the three months ended March 31, 2014 and 2013, respectively.  We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, Martin Energy Services LLC ("MES"), and MES provides terminal services to us to handle lubricants, greases and drilling fluids.  Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

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

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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 months ended March 31,2014 and 2013, which represents EBITDA, Adjusted EBITDA and Distributable Cash Flow from continuing operations.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow

	Three Months Ended
	March 31,
	2014			2013
Net income	$	11,795		$	16,637
Adjustments:
Interest expense	11,451			9,058
Income tax expense	300			307
Depreciation and amortization	13,992			11,893
EBITDA	37,538			37,895
Adjustments:
Equity in loss of unconsolidated entities	296			374
Loss (gain) on sale of property, plant and equipment	45			(372		)
Distributions from unconsolidated entities	780			525
Unit-based compensation	179			256
Adjusted EBITDA	38,838			38,678
Adjustments:
Interest expense	(11,451		)	(9,058		)
Income tax expense	(300		)	(307		)
Amortization of debt discount	77			76
Amortization of deferred debt issuance costs	810			1,269
Payments of installment notes payable and capital lease obligations	—			(81		)
Payments for plant turnaround costs	(2,164		)	—
Maintenance capital expenditures	(4,338		)	(1,678		)
Distributable Cash Flow	$	21,472		$	28,899

Results of Operations

The results of operations for the three months ended March 31, 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 months ended March 31, 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.

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

Three Months Ended March 31, 2014 Compared to the Three Months Ended March 31, 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 March 31, 2014
Terminalling and storage	$	87,297	$	(1,223	)	$	86,074	$	9,033		$	(722	)	$	8,311
Natural gas services	333,633		—			333,633		8,638			827			9,465
Sulfur services	54,207		—			54,207		9,189			(1,121		)	8,068
Marine transportation	24,114		(1,000		)	23,114		1,946			1,016			2,962
Indirect selling, general and administrative	—		—			—		(4,897		)	—			(4,897		)
Total	$	499,251	$	(2,223	)	$	497,028	$	23,909		$	—		$	23,909

	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues  after Eliminations		Operating Income (Loss)			Operating Income Intersegment Eliminations			Operating Income (Loss)  after Eliminations
Three Months Ended March 31, 2013
Terminalling and storage	$	80,353	$	(1,141	)	$	79,212	$	10,669		$	(686	)	$	9,983
Natural gas services	259,439		—			259,439		8,104			358			8,462
Sulfur services	70,385		—			70,385		10,046			(702		)	9,344
Marine transportation	25,232		(582		)	24,650		1,509			1,030			2,539
Indirect selling, general and administrative	—		—			—		(3,943		)	—			(3,943		)
Total	$	435,409	$	(1,723	)	$	433,686	$	26,385		$	—		$	26,385

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Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended March 31, 2014 and 2013

	Three Months Ended March 31,					Variance			Percent Change
	2014			2013
	(In thousands, except BBL per day)
Revenues:
Services	$	33,024		$	30,032	$	2,992		10%
Products	54,273			50,321		3,952			8%
Total revenues	87,297			80,353		6,944			9%
Cost of products sold	48,525			44,270		4,255			10%
Operating expenses	19,752			17,694		2,058			12%
Selling, general and administrative expenses	967			695		272			39%
Depreciation and amortization	8,975			7,096		1,879			26%
	9,078			10,598		(1,520		)	(14)%
Other operating income	(45		)	71		(116		)	(163)%
Operating income	$	9,033		$	10,669	$	(1,636	)	(15)%
Lubricant sales volumes (gallons)	9,163			8,797		366			4%
Shore-based throughput volumes (gallons)	61,152			74,948		(13,796		)	(18)%
Smackover refinery throughput volumes (BBL per day)	3,140			6,447		(3,307		)	(51)%
Corpus Christi crude terminal (BBL per day)	140,346			109,369		30,977			28%

Services revenues. Services revenue increased $2.1 million related to specialty terminals, including $1.6 million attributable to volume increases at our crude terminal in Corpus Christi, Texas. In addition, revenue at our Smackover refinery increased $1.0 million due to higher minimum tolling fees and pipeline revenue.

Products revenues. Revenues at our blending and packaging facilities increased $2.0 million and $0.7 million due to volume and price increases of 6% and 2%, respectively. Revenues at our shore-based terminals increased $1.2 million principally due to a 7% increase in average sales price.

Cost of products sold.  A 6% increase in volumes at our blending and packaging facilities resulted in a $1.8 million increase in cost of products sold. Average cost per gallon for blending and packaging increased 4%, resulting in increased costs of $1.2 million. Costs at our shore-based facilities increased $1.3 million due to an 8% increase in prices.

Operating expenses. Costs at our Smackover refinery increased $1.4 million, including $0.6 million of repair and maintenance expense and $0.4 million of compensation costs. Additionally, operating expenses at our Corpus Christi crude terminal increased $0.6 million.

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

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

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

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Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended March 31, 2014 and 2013

	Three Months Ended March 31,				Variance			Percent Change
	2014		2013
	(In thousands)
Revenues:
Marine transportation	$	296	$	330	$	(34	)	(10)%
Products	333,337		259,109		74,228			29%
Total revenues	333,633		259,439		74,194			29%
Cost of products sold	321,140		249,136		72,004			29%
Operating expenses	1,915		981		934			95%
Selling, general and administrative expenses	1,436		926		510			55%
Depreciation and amortization	504		292		212			73%
Operating income	$	8,638	$	8,104	$	534		7%
Distributions from unconsolidated entities	$	780	$	525	$	255		49%
NGL sales volumes (Bbls)	4,958		3,705		1,253			34%

Revenues. Natural gas services sales volumes increased 34%, positively impacting revenues $84.2 million.  The increase in volumes was a result of a colder winter season in 2014 compared to 2013. Additionally, we experienced increased volume as a result of being in the second full year of operations in the Louisiana butane market. Our NGL average sales price per barrel decreased $2.70, or 4%, resulting in an offsetting decrease to revenues of $10.0 million.

Cost of products sold.  Our average cost per barrel decreased $2.47, or 4%.  Our margins decreased $0.23 per barrel during the period as a result of decreased market prices.

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

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

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

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Sulfur Services Segment

Comparative Results of Operations for the Three Months Ended March 31, 2014 and 2013

	Three Months Ended March 31,				Variance			Percent Change
	2014		2013
	(In thousands)
Revenues:
Services	$	3,037	$	3,001	$	36		1%
Products	51,170		67,384		(16,214		)	(24)%
Total revenues	54,207		70,385		(16,178		)	(23)%
Cost of products sold	37,943		52,887		(14,944		)	(28)%
Operating expenses	3,977		4,439		(462		)	(10)%
Selling, general and administrative expenses	1,115		1,047		68			6%
Depreciation and amortization	1,983		1,966		17			1%
Operating income	$	9,189	$	10,046	$	(857	)	(9)%
Sulfur (long tons)	190.4		194.0		(3.6		)	(2)%
Fertilizer (long tons)	91.2		103.7		(12.5		)	(12)%
Total sulfur services volumes (long tons)	281.6		297.7		(16.1		)	(5)%

Revenues.  Product revenue declined $13.3 million attributable to a 20% decrease in prices. A 5% reduction in sales volumes resulted in decreased revenue of $2.9 million.

Cost of products sold.  Cost of products sold decreased $12.8 million due to a 24% reduction in prices. A 5% decline in volumes resulted in a $2.2 million decrease in cost of products sold. Our margin per ton decreased $1.73, or 4%, primarily attributable to the decline in market prices in our sulfur business.

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

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

Depreciation and amortization.  Depreciation and amortization remained consistent.

Marine Transportation Segment

Comparative Results of Operations for the Three Months Ended March 31, 2014 and 2013

	Three Months Ended March 31,				Variance			Percent Change
	2014		2013
	(In thousands)
Revenues	$	24,114	$	25,232	$	(1,118	)	(4)%
Operating expenses	19,447		21,066		(1,619		)	(8)%
Selling, general and administrative expenses	191		419		(228		)	(54)%
Depreciation and amortization	2,530		2,539		(9		)	—%
	1,946		1,208		738			61%
Other operating income	—		301		(301		)	(100)%
Operating income	$	1,946	$	1,509	$	437		29%

Inland revenues.  Inland revenues increased $0.4 million as a result of $1.3 million attributable to the Florida Marine assets acquired in February 2013. Inland revenues declined $0.7 million due to decreased utilization of the legacy inland fleet.

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Offshore revenues. A decrease in offshore revenues of $1.6 million is primarily due to decreased utilization of the offshore fleet.

Operating expenses.  Operating expenses decreased primarily as a result of decreases in outside towing of $0.8 million, barge lease rental of $0.6 million, and compensation expense of $0.3 million.

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

Depreciation and amortization.  Depreciation and amortization remained consistent.

Other operating income.  Other operating income for the 2013 period includes the gain on disposition of property, plant and equipment.

Equity in Earnings (Loss) of Unconsolidated Entities for the Three Months Ended March 31, 2014 and 2013

	Three Months Ended March 31,						Variance			Percent Change
	2014			2013
	(In thousands)
Equity in loss of Cardinal	$	(851	)	$	(216	)	$	(635	)	(294)%
Equity in earnings of MET	555			—			555
Equity in loss of Caliber	—			(158		)	158			100%
Equity in loss of unconsolidated entities	$	(296	)	$	(374	)	$	78		21%

Equity in earnings of Cardinal decreased $0.6 million. Equity in earnings decreased $1.4 million due a decline in the performance of Monroe Gas Storage Company, LLC ("Monroe"). This decline was partially offset by $0.8 million attributable to the results of Cadeville Gas Storage, LLC ("Cadeville") and Perryville Gas Storage, LLC ("Perryville"), both of which were completed in the second quarter of 2013. Monroe, Cadeville and Perryville are subsidiaries of Cardinal.

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

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

Interest Expense

Comparative Components of Interest Expense for the Three Months Ended March 31, 2014 and 2013

	Three Months Ended March 31,						Variance			Percent Change
	2014			2013
	(In thousands)
Revolving loan facility	$	2,399		$	1,576		$	823		52%
8.875% Senior notes	3,882			3,883			(1		)	—%
7.250% Senior notes	4,531			2,366			2,165			92%
Amortization of deferred debt issuance costs	810			1,269			(459		)	(36)%
Amortization of debt discount	77			76			1			1%
Other	140			68			72			106%
Capitalized interest	(388		)	(180		)	(208		)	(116)%
Total interest expense	$	11,451		$	9,058		$	2,393		26%

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Indirect Selling, General and Administrative Expenses for the Three Months Ended March 31, 2014 and 2013

	Three Months Ended March 31,				Variance		Percent Change
	2014		2013
	(In thousands)
Indirect selling, general and administrative expenses	$	4,897	$	3,943	$	954	24%

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 March 31,				Variance		Percent Change
	2014		2013
	(In thousands)
Conflicts Committee approved reimbursement amount	$	3,190	$	2,657	$	533	20%

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.  We received $5.2 million in net proceeds from the issuance of common units under our "at the market" equity distribution program. We made certain strategic amendments under our revolving credit facility, including most recently in February 2014 when we increased our maximum borrowing capacity from $600.0 million to $637.5 million utilizing the accordion feature of our revolving credit facility.

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

Our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 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

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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. We expect the exchange offer to be 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 February 18, 2014, we increased the maximum amount of borrowings and letters of credit under our revolving credit facility from $600.0 million to $637.5 million utilizing the accordion feature of our revolving credit facility.

Equity Offerings

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 $5.6 million during the three months ended March 31, 2014. Sales were at market prices prevailing at the time of the sale. We also received capital contributions from our general partner of $0.1 million during the three months ended March 31, 2014, 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 - Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

The following table details the cash flow changes between the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,						Variance			Percent Change
	2014			2013
	(In thousands)
Net cash provided by (used in):
Operating activities	$	36,524		$	65,393		$	(28,869	)	(44)%
Investing activities	(17,056		)	(85,746		)	68,690			80%
Financing activities	(31,639		)	15,238			(46,877		)	(308)%
Net decrease in cash and cash equivalents	$	(12,171	)	$	(5,115	)	$	(7,056	)	(138)%

Net cash provided by operating activities for the three months ended March 31, 2014 decreased compared to the prior year period primarily due to a $34.5 million unfavorable variance in the change in working capital. The primary working negative working capital impact was the change in accounts and other receivables related to the timing of receipts from our customers.

Net cash used in investing activities for the three months ended March 31, 2014 decreased compared to the prior year period mainly due to $50.8 million in cash paid for acquisitions and $15.0 million in cash paid for the preferred interests in MET in the 2013 period.

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Net cash provided by (used in) financing activities for the three months ended March 31, 2014 decreased compared to the prior period mainly due to (i) $60.0 million in decreased borrowings under our revolving credit facility in the current period; (ii) offset by $8.4 million in additional cash paid during the 2013 period related to deferred financing costs.; and (iii) $5.2 million in net proceeds related to the issuance of common units during the first quarter of 2014.

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 March 31,
	2014		2013
	(In thousands)
Expansion capital expenditures	$	17,137	$	13,037
Maintenance capital expenditures	4,338		1,678
Plant turnaround costs	2,164		—
Total	$	23,639	$	14,715

Expansion capital expenditures were made primarily in our Terminalling and Storage and Marine Transportation segments during the three months ended March 31, 2014. Within our Terminalling and Storage segment, expenditures were made primarily at our Corpus Christi crude terminal, Smackover refinery, and certain smaller organic growth projects ongoing in our specialty terminalling operations. Within our Marine Transportation segment, expenditures were made related to the construction of new barges. Maintenance capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Sulfur Services segments to maintain our existing assets and operations during the three months ended March 31, 2014. For the three months ended March 31, 2014, plant turnaround costs relate to our Smackover refinery.

Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three months ended March 31, 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 segment to maintain our existing assets and operations during the three months ended March 31, 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 March 31, 2014, we had $643.8 million of outstanding indebtedness, consisting of outstanding borrowings of $423.8 million (net of unamortized discount) under our Senior Notes due in 2018 and 2021 and $220.0 million under our revolving credit facility.

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Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of March 31, 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	$	220,000	$	—	$	—	$	220,000	$	—
2018 Senior unsecured notes	173,772		—		—		173,772		—
2021 Senior unsecured notes	250,000		—		—		—		250,000
Non-competition agreements	50		50		—		—		—
Throughput commitment	43,118		4,990		10,466		11,149		16,513
Operating leases	46,162		11,873		20,881		7,437		5,971
Interest expense: ¹
Revolving credit facility	27,700		6,944		13,888		6,868		—
2018 Senior unsecured notes	63,419		15,531		31,062		16,826		—
2021 Senior unsecured notes	125,365		18,125		36,250		36,250		34,740
Total contractual cash obligations	$	949,586	$	57,513	$	112,547	$	472,302	$	307,224

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

Letter of Credit.  At March 31, 2014, we had outstanding irrevocable letters of credit in the amount of $8.6 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 notes issued March 26, 2010, see “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Description of Our Long-Term Debt” in our Annual Report on Form 10-K for the year ended December 31, 2013.

2018 Senior Notes

For a description of our 2018, 8.875% senior notes issued March 26, 2010, see “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Description of Our Long-Term Debt” in our Annual Report on Form 10-K for the year ended December 31, 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 February 18, 2014 when we increased our maximum amount of borrowings to $637.5 million utilizing the accordion feature of our revolving credit facility.

As of March 31, 2014, we had $220.0 million outstanding under the revolving credit facility and $8.6 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 $408.9 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 March 31, 2014, we have the ability to incur approximately $86.7 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 three months ended March 31, 2014, the level of outstanding draws on our credit facility has ranged from a low of $220.0 million to a high of $262.0 million.

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

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

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

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

The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at March 31, 2014 is 3.00%.  

The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio is 5.25 to 1.00. The maximum permitted senior leverage ratio (as defined in the credit facility but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00. The minimum interest coverage ratio (as defined in the credit facility but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.50 to 1.00.

In addition, the credit facility contains various covenants, which, among other things, limit our and our subsidiaries’ ability to: (i) grant or assume liens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur or assume indebtedness; (v) sell, transfer, assign or convey assets; (vi) repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us to make quarterly distributions to unitholders so long as no default or event of default exists under the credit facility; (vii) change the nature of our business; (viii) engage in transactions with affiliates; (ix) enter into certain burdensome agreements; (x) make certain amendments to the Omnibus Agreement and our material agreements; (xi) make capital expenditures; and (xii) permit our joint ventures to incur indebtedness or grant certain liens.

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

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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 May 2, 2014, our outstanding indebtedness includes $260.0 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 three months ended March 31, 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 three months ended March 31,2014 or 2013.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 3.16% as of March 31, 2014.  As of May 2, 2014, we had total indebtedness outstanding under our credit facility of $260.0 million, all of which was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on March 31, 2014, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $2.2 million annually.

We are not exposed to changes in interest rates with respect to our senior unsecured notes due in 2018 and 2021 as these obligations are fixed rates.  The estimated fair value of our senior unsecured notes was approximately $446.6 million as of March 31, 2014, based on market prices of similar debt at March 31, 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 $13.3 million decrease in fair value of our long-term debt at March 31, 2014.

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Item 4. Controls and Procedures

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

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

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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

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SIGNATURES

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

	Martin Midstream Partners L.P.
	By:	Martin Midstream GP LLC
		It’s General Partner
Date:  May 2, 2014	By:	/s/ Ruben S. Martin
		Ruben S. Martin
		President and Chief Executive Officer

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INDEX TO EXHIBITS

Exhibit Number	Exhibit Name
3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.2	Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 25, 2009 (filed as Exhibit 10.1 to the Partnership's Amendment to Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein by reference).
3.3	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 1, 2011, and incorporated herein by reference).
3.4	Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
3.5	Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.6	Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
3.7	Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.8	Amended and Restated Limited Liability Company Agreement of the General Partner, dated August 30, 2013 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (Reg. No. 000-50056), filed September 3, 2013, and incorporated herein by reference).
3.9	Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.10	Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
4.1	Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
4.2	Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
4.3	Indenture, dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed March 26, 2010, and incorporated herein by reference).
4.4	First Supplemental Indenture, to the Indenture dated as of March 26, 2010, dated as of February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed March 4, 2013, and incorporated herein by reference).
4.5	Indenture (including form of 7.250% Senior Notes due 2021), dated as of February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).
10.1	Third Amended and Restated Credit Agreement, dated March 28, 2013, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders set forth therein (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed April 3, 2013 and incorporated herein by reference).
10.2*	First Amendment to Third Amended and Restated Credit Agreement, dated as of July 12, 2013, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein.
10.3	Commitment Increase and Joinder Agreement, dated February 18, 2014, among the Operating Partnership, the Guarantors named therein, Deutsche Bank AG New York Branch, and Royal Bank of Canada, as Administrative Agent (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed February 18, 2014, and incorporated herein by reference).

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10.4	Equity Distribution Agreement, dated as of March 7, 2014, among the Partnership, the General Partner, the Operating General Partner, the Operating Partnership, Goldman, Sachs & Co. and MLV & Co. LLC (filed as exhibit 1.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed March 7, 2014, and incorporated herein by reference).
10.5	Registration Rights Agreement, dated as of April 1, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Securities, LLC (filed as exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed April 1, 2014, and incorporated herein by reference).
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.  Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.  Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, formatted in Extensible Business Reporting Language: (1) the Consolidated and Condensed Balance Sheets; (2) the Consolidated and Condensed Statements of Income; (3) the Consolidated and Condensed Statements of Cash Flows; (4) the Consolidated and Condensed Statements of Capital; (5) the Consolidated and Condensed Statements of Other Comprehensive Income; and (6) the Notes to Consolidated and Condensed Financial Statements.

* Filed or furnished herewith

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