Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________________________________

FORM 10-Q



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

For the quarterly period ended June 30, 2016



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

For the transition period from ____________ to ____________

Commission File Number

000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)



Delaware		05-0527861
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

4200 Stone Road

Kilgore, Texas 75662

(Address of principal executive offices, zip code)

Registrant’s telephone number, including area code: (903) 983-6200

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.



Yes x		No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



Yes x		No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



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

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



Yes o		No x

The number of the registrant’s Common Units outstanding at July 27, 2016, was 35,454,712.



	Page

PART I – FINANCIAL INFORMATION	2

Item 1. Financial Statements	2
Consolidated and Condensed Balance Sheets as of June 30, 2016 (unaudited) and December 31, 2015 (audited)	2
Consolidated and Condensed Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015 (unaudited)	3
Consolidated and Condensed Statements of Capital for the Six Months Ended June 30, 2016 and 2015 (unaudited)	6
Consolidated and Condensed Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015 (unaudited)	7
Notes to Consolidated and Condensed Financial Statements	8

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk	51

Item 4. Controls and Procedures	52

PART II. OTHER INFORMATION	53

Item 1. Legal Proceedings	53

Item 1A. Risk Factors	53

Item 6. Exhibits	53

PART I – FINANCIAL INFORMATION



Item 1.	Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)



	June 30, 2016			December 31, 2015
	(Unaudited)			(Audited)
Assets
Cash	$	28		$	31
Accounts and other receivables, less allowance for doubtful accounts of $372 and $430, respectively	50,360			74,355
Product exchange receivables	118			1,050
Inventories	90,636			75,870
Due from affiliates	7,972			10,126
Fair value of derivatives	—			675
Other current assets	5,129			5,718
Total current assets	154,243			167,825

Property, plant and equipment, at cost	1,391,544			1,387,814
Accumulated depreciation	(422,465		)	(404,574		)
Property, plant and equipment, net	969,079			983,240

Goodwill	19,657			23,802
Investment in WTLPG	130,474			132,292
Note receivable - Martin Energy Trading LLC	15,000			15,000
Other assets, net	53,279			58,314
Total assets	$	1,341,732		$	1,380,473

Liabilities and Partners’ Capital
Trade and other accounts payable	$	81,836		$	81,180
Product exchange payables	8,809			12,732
Due to affiliates	3,859			5,738
Income taxes payable	370			985
Fair value of derivatives	862			—
Other accrued liabilities	20,663			18,533
Total current liabilities	116,399			119,168

Long-term debt, net	878,891			865,003
Fair value of derivatives	—			206
Other long-term obligations	2,551			2,217
Total liabilities	997,841			986,594

Commitments and contingencies (Note 16)
Partners’ capital	343,891			393,879
Total partners’ capital	343,891			393,879
Total liabilities and partners' capital	$	1,341,732		$	1,380,473

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars and units in thousands, except per unit amounts)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Revenues:
Terminalling and storage *	$	31,090		$	33,453		$	62,795		$	67,250
Marine transportation *	14,339			20,343			30,685			40,979
Natural gas services*	15,403			16,564			31,500			33,051
Sulfur services	2,700			3,090			5,400			6,180
Product sales: *
Natural gas services	58,899			97,786			149,990			244,089
Sulfur services	39,588			45,284			79,063			95,331
Terminalling and storage	28,329			34,579			56,520			69,572
	126,816			177,649			285,573			408,992
Total revenues	190,348			251,099			415,953			556,452

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	55,579			88,623			134,123			226,330
Sulfur services *	24,700			33,518			52,224			69,541
Terminalling and storage *	22,934			29,658			46,766			59,740
	103,213			151,799			233,113			355,611
Expenses:
Operating expenses *	40,822			47,783			82,054			93,089
Selling, general and administrative *	8,144			9,035			16,315			17,841
Loss on impairment of goodwill	4,145			—			4,145			—
Depreciation and amortization	22,089			22,685			44,137			45,402
Total costs and expenses	178,413			231,302			379,764			511,943

Other operating loss	(1,679		)	(167		)	(1,595		)	(177		)
Operating income	10,256			19,630			34,594			44,332

Other income (expense):
Equity in earnings of WTLPG	805			1,649			2,482			3,389
Interest expense, net	(12,155		)	(9,925		)	(22,267		)	(20,471		)
Other, net	74			(79		)	136			358
Total other expense	(11,276		)	(8,355		)	(19,649		)	(16,724		)

Net income (loss) before taxes	(1,020		)	11,275			14,945			27,608
Income tax expense	(191		)	(314		)	(242		)	(614		)
Income (loss) from continuing operations	(1,211		)	10,961			14,703			26,994
Income from discontinued operations, net of income taxes	—			—			—			1,215
Net income (loss)	(1,211		)	10,961			14,703			28,209
Less general partner's interest in net income	(3,869		)	(4,113		)	(8,080		)	(8,351		)
Less (income) loss allocable to unvested restricted units	4			(44		)	(39		)	(111		)
Limited partners' interest in net income (loss)	$	(5,076	)	$	6,804		$	6,584		$	19,747

See accompanying notes to consolidated and condensed financial statements.

*Related Party Transactions Shown Below

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars and units in thousands, except per unit amounts)

*Related Party Transactions Included Above



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Revenues:*
Terminalling and storage	$	20,590	$	23,061	$	41,548	$	43,535
Marine transportation	6,036		6,622		12,447		13,367
Natural gas services	129		—		442		—
Product Sales	968		1,759		1,668		3,348
Costs and expenses:*
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	4,498		6,810		7,883		13,728
Sulfur services	3,810		3,618		7,622		7,242
Terminalling and storage	4,081		5,632		7,466		11,034
Expenses:
Operating expenses	18,088		18,915		35,445		39,315
Selling, general and administrative	6,911		5,849		12,343		11,843

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars and units in thousands, except per unit amounts)



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016			2015		2016		2015
Allocation of net income (loss) attributable to:
Limited partner interest:
Continuing operations	$	(5,076	)	$	6,804	$	6,584	$	18,896
Discontinued operations	—			—		—		851
	$	(5,076	)	$	6,804	$	6,584	$	19,747
General partner interest:
Continuing operations	$	3,869		$	4,113	$	8,080	$	7,992
Discontinued operations	—			—		—		359
	$	3,869		$	4,113	$	8,080	$	8,351

Net income (loss) per unit attributable to limited partners:
Basic:
Continuing operations	$	(0.14	)	$	0.19	$	0.19	$	0.54
Discontinued operations	—			—		—		0.02
	$	(0.14	)	$	0.19	$	0.19	$	0.56

Weighted average limited partner units - basic	35,346			35,308		35,366		35,316

Diluted:
Continuing operations	$	(0.14	)	$	0.19	$	0.19	$	0.54
Discontinued operations	—			—		—		0.02
	$	(0.14	)	$	0.19	$	0.19	$	0.56

Weighted average limited partner units - diluted	35,346			35,376		35,380		35,372

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)



	Partners’ Capital
	Common Limited					General Partner Amount
	Units		Amount			General Partner Amount			Total
Balances - January 1, 2015	35,365,912		$	470,943		$	14,728		$	485,671
Net income	—		19,858			8,351			28,209
Issuance of common units, net	—		(269		)	—			(269		)
Issuance of restricted units	91,950		—			—			—
Forfeiture of restricted units	(1,000	)	—			—			—
General partner contribution	—		—			55			55
Cash distributions	—		(57,612		)	(8,965		)	(66,577		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		750			—			750
Unit-based compensation	—		750			—			750
Balances - June 30, 2015	35,456,862		$	434,420		$	14,169		$	448,589

Balances - January 1, 2016	35,456,612		$	380,845		$	13,034		$	393,879
Net income	—		6,623			8,080			14,703
Issuance of restricted units	13,800		—			—			—
Forfeiture of restricted units	(250	)	—			—			—
Cash distributions	—		(57,603		)	(9,119		)	(66,722		)
Unit-based compensation	—		486			—			486
Reimbursement of excess purchase price over carrying value of acquired assets	—		1,875			—			1,875
Purchase of treasury units	(15,200	)	(330		)	—			(330		)
Balances - June 30, 2016	35,454,962		$	331,896		$	11,995		$	343,891

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)



	Six Months Ended
	June 30,
	2016			2015
Cash flows from operating activities:
Net income	$	14,703		$	28,209
Less: Income from discontinued operations, net of income taxes	—			(1,215		)
Net income from continuing operations	14,703			26,994
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	44,137			45,402
Amortization of deferred debt issuance costs	2,247			1,742
Amortization of premium on notes payable	(153		)	(164		)
Loss (gain) on sale of property, plant and equipment	1,595			165
Loss on impairment of goodwill	4,145			—
Equity in earnings of unconsolidated entities	(2,482		)	(3,389		)
Derivative income	(1,125		)	(1,745		)
Net cash received for commodity derivatives	1,666			—
Net cash received for interest rate derivatives	160			—
Net premiums received on derivatives that settled during the year on interest rate swaption contracts	630			1,745
Unit-based compensation	486			750
Cash distributions from WTLPG	4,300			4,400
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	23,995			58,689
Product exchange receivables	932			2,752
Inventories	(14,766		)	12,204
Due from affiliates	2,154			3,800
Other current assets	509			(711		)
Trade and other accounts payable	(3,429		)	(46,283		)
Product exchange payables	(3,923		)	2,308
Due to affiliates	(1,879		)	(118		)
Income taxes payable	(615		)	(438		)
Other accrued liabilities	2,130			(959		)
Change in other non-current assets and liabilities	(614		)	(1,709		)
Net cash provided by continuing operating activities	74,803			105,435
Net cash used in discontinued operating activities	—			(1,351		)
Net cash provided by operating activities	74,803			104,084
Cash flows from investing activities:
Payments for property, plant and equipment	(27,844		)	(28,027		)
Acquisition of intangible assets	(2,150		)	—
Payments for plant turnaround costs	(1,184		)	(1,754		)
Proceeds from sale of property, plant and equipment	655			776
Proceeds from involuntary conversion of property, plant and equipment	9,100			—
Net cash used in continuing investing activities	(21,423		)	(29,005		)
Net cash provided by discontinued investing activities	—			41,250
Net cash provided by (used in) investing activities	(21,423		)	12,245
Cash flows from financing activities:
Payments of long-term debt	(163,700		)	(151,000		)
Proceeds from long-term debt	180,700			101,000
Proceeds from issuance of common units, net of issuance related costs	—			(269		)
General partner contribution	—			55
Purchase of treasury units	(330		)	—
Payment of debt issuance costs	(5,206		)	(306		)
Reimbursement of excess purchase price over carrying value of acquired assets	1,875			750
Cash distributions paid	(66,722		)	(66,577		)
Net cash used in financing activities	(53,383		)	(116,347		)
Net decrease in cash	(3		)	(18		)
Cash at beginning of period	31			42
Cash at end of period	$	28		$	24
Non-cash additions to property, plant and equipment	$	989		$	3,767

See accompanying notes to consolidated and condensed financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(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: natural gas services, including liquids transportation and distribution services and natural gas storage; terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil, blending and packaging of finished lubricants; 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, 2015, filed with the Securities and Exchange Commission (the "SEC") on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2015 filed on March 30, 2016.

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.

During the 2nd quarter of 2016, the Partnership agreed to commence a relocation of one of its docks at the Partnership's Corpus Christi crude terminal location due to the construction of a new bridge near the facility. During the three months ended June 30, 2016, the Partnership received proceeds in the amount of $9,100 related to the relocation. The Partnership expects to record a gain from this involuntary conversion that will be recorded when the relocation is completed, which is expected to be no later than the 3rd quarter of 2017.


(2)	New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, Leases. This standard amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is evaluating the effect that ASU 2016-02 will have on its consolidated and condensed financial statements and related disclosures.

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which applies only to inventory for which cost is determined by methods other than last-in, first-out and the retail inventory method. This includes inventory that is measured using first-in, first-out or average cost. Inventory within the scope of this standard is required to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard will be effective on January 1, 2017. The Partnership is evaluating the effect that ASU 2015-11 will have on its consolidated and condensed financial statements and related disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is evaluating the effect that ASU 2014-09 will have on its consolidated and condensed financial statements and related disclosures. The Partnership has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.


(3)	Discontinued operations and divestitures

Floating Storage Assets. On February 12, 2015, the Partnership sold all six of its 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision to dispose of the Floating Storage Assets. As a result, the Partnership classified the Floating Storage Assets as held for sale at December 31, 2014 and has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the three and six months ended June 30, 2016 and 2015. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the operations and cash flows of the Floating Storage Assets as discontinued operations. The Floating Storage Assets were presented as discontinued operations under the guidance prior to the Partnership's adoption of ASU 2014-08 related to discontinued operations. The adoption of the amended guidance was effective for the Partnership January 1, 2015.

The Floating Storage Assets’ operating results, which are included in income from discontinued operations, were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Total revenues from third parties¹	$	—	$	—	$	—	$	791
Total costs and expenses and other, net, excluding depreciation and amortization	—		—		—		1,038
Depreciation and amortization	—		—		—		—
Other operating income²	—		—		—		1,462
Income from discontinued operations before income taxes	—		—		—		1,215
Income tax expense	—		—		—		—
Income from discontinued operations, net of income taxes	$	—	$	—	$	—	$	1,215

¹ All revenues for the six months ended June 30, 2015 were from third parties.

² Other operating income represents the gain on the disposition of the Floating Storage Assets.


(4)	Inventories

Components of inventories at June 30, 2016 and December 31, 2015 were as follows:



	June 30, 2016		December 31, 2015
Natural gas liquids	$	45,027	$	20,959
Sulfur	8,385		13,812
Sulfur based products	16,092		19,400
Lubricants	18,349		18,675
Other	2,783		3,024
	$	90,636	$	75,870

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)


(5)	Investment in West Texas LPG Pipeline L.P.

The Partnership owns a 19.8% general partnership and 0.2% limited partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). ONEOK Partners, L.P. is the operator of the assets. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The Partnership recognizes its 20% interest in WTLPG as "Investment in WTLPG" on its Consolidated and Condensed Balance Sheets. The Partnership accounts for its ownership interest in WTLPG under the equity method of accounting.

Selected financial information for WTLPG is as follows:



	As of June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	Total Assets		Members' Equity		Revenues		Net Income		Revenues		Net Income
2016
WTLPG	$	815,035	$	795,247	$	20,166	$	4,027	$	45,021	$	12,725
	As of December 31,
2015
WTLPG	$	819,342	$	804,023	$	21,762	$	8,242	$	43,916	$	16,945

As of June 30, 2016 and December 31, 2015, the Partnership’s interest in cash of WTLPG was $700 and $1,060, respectively.


(6)	Derivative Instruments and Hedging Activities

The Partnership’s revenues and cost of products sold are materially impacted by changes in NGL prices. Additionally, the Partnership's results of operations are materially impacted by changes in 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. All of the Partnership's derivatives are non-hedge derivatives and therefore all changes in fair values are recognized as gains and losses in the earnings of the periods in which they occur.

(a) Commodity Derivative Instruments

The Partnership from time to time has used derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure. In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership has entered into hedging transactions as of June 30, 2016 to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. The Partnership has instruments totaling a net notional quantity of 383,000 barrels settling during the period from October 31, 2016 through March 31, 2017. These instruments settle against OPIS Mont Belvieu (non-TET) monthly average price. Martin Energy Trading LLC ("MET") serves as the counterparty for all positions outstanding at June 30, 2016.

(b) Interest Rate Derivative Instruments

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

During the six months ended June 30, 2016 and 2015, the Partnership entered into contracts which provided the counterparty the option to enter into swap contracts to hedge the Partnership's exposure to changes in the fair value of its senior unsecured notes ("interest rate swaptions") through June 30, 2016 and 2015, respectively. In connection with the interest rate swaption contracts, the Partnership received premiums of $0 and $630, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated and Condensed Balance Sheets, during the three and six months ended June 30, 2016, respectively. In connection with the interest rate swaption contracts, the Partnership received premiums of $1,120 and $1,745, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated and Condensed Balance Sheets, during the three and six months ended June 30, 2015, respectively. Each of the interest rate swaptions was fully amortized as of June 30, 2016 and 2015. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the three and six months ended June 30, 2016, the Partnership recognized $0 and $630, respectively, of premiums in "Interest expense, net" on the Partnership's Consolidated and Condensed Statements of Operations related to the interest rate swaption contracts. For the three and six months ended June 30, 2015, the Partnership recognized $1,120 and $1,745, respectively, of premiums in "Interest expense, net" on the Partnership's Consolidated and Condensed Statements of Operations related to the interest rate swaption contracts.

As of December 31, 2015, the Partnership had a fixed-to-variable interest rate swap agreement with a notional principal amount of $50,000 of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with a portion of the Partnership's 2021 senior unsecured notes from fixed rate to variable rate based on the LIBOR interest rate. The Partnership's swap agreement had a termination date that corresponded to the maturity date of the 2021 senior unsecured notes. This instrument was recorded on the Partnership's Consolidated and Condensed Balance Sheets at December 31, 2015 in "Fair value of derivatives" as a non current liability of $206. This position terminated on January 7, 2016, resulting in a benefit of $160.

For information regarding gains and losses on interest rate derivative instruments, see "Tabular Presentation of Gains and Losses on Derivative Instruments" below.

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



	Fair Values of Derivative Instruments in the Consolidated Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	June 30, 2016		December 31, 2015		Balance Sheet Location	June 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	675	Fair value of derivatives	$	862	$	—
Derivatives not designated as hedging instruments:	Non Current:					Non Current:
Interest rate contracts	Fair value of derivatives	—		—		Fair value of derivatives	—		206
Total derivatives not designated as hedging instruments		$	—	$	675		$	862	$	206

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

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

For the Three Months Ended June 30, 2016 and 2015



	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016			2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	—		$	1,120
Commodity contracts	Cost of products sold	(876		)	—
Total derivatives not designated as hedging instruments		$	(876	)	$	1,120

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

For the Six Months Ended June 30, 2016 and 2015



	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016		2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	630	$	1,745
Interest rate contracts	Interest expense	366		—
Commodity contracts	Cost of products sold	129		—
Total derivatives not designated as hedging instruments		$	1,125	$	1,745


(7)	Fair Value Measurements

The Partnership uses a valuation framework based upon inputs that market participants use in pricing certain assets and liabilities. These inputs are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources. Unobservable inputs represent the Partnership's own market assumptions. Unobservable inputs are used only if observable inputs are unavailable or not reasonably available without undue cost and effort. The two types of inputs are further prioritized into the following hierarchy:

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 reflect the entity's own assumptions and are not corroborated by market data.

Assets and liabilities measured at fair value on a recurring basis are summarized below:



	Level 2
	June 30, 2016			December 31, 2015
Commodity derivative contracts	$	(862	)	$	675
Interest rate derivative contracts	—			(206		)

The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

•

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 below. There is negligible credit risk associated with these instruments.


•	Note receivable and 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 Partnership has not had any indicators which represent a change in the market spread associated with its variable interest rate debt.


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



	June 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - MET	$	15,000	$	15,814	$	15,000	$	15,830
2021 Senior unsecured notes	372,050		345,054		371,861		318,000


(8)	Supplemental Balance Sheet Information

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



	June 30, 2016		December 31, 2015
Customer contracts and relationships, net	$	44,243	$	50,452
Other intangible assets	2,556		1,818
Other	6,480		6,044
	$	53,279	$	58,314

Accumulated amortization of intangible assets was $42,156 and $32,842 at June 30, 2016 and December 31, 2015, respectively.

Components of "Other accrued liabilities" were as follows:



	June 30, 2016		December 31, 2015
Accrued interest	$	10,431	$	10,365
Property and other taxes payable	6,566		6,668
Accrued payroll	3,602		1,389
Other	64		111
	$	20,663	$	18,533

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)


(9)	Long-Term Debt

At June 30, 2016 and December 31, 2015, long-term debt consisted of the following:



	June 30, 2016		December 31, 2015
$664,444³ Revolving credit facility at variable interest rate (3.46%¹ weighted average at June 30, 2016), due March 2020 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, net of unamortized debt issuance costs of $8,159 and $4,858, respectively²	$	506,841	$	493,142
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $3,165 and $3,507, respectively, including unamortized premium of $1,415 and $1,568, respectively, issued $250,000 February 2013 and $150,000 April 2014, due February 2021, unsecured²	372,050		371,861
Total long-term debt, net	$	878,891	$	865,003

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. All amounts outstanding at June 30, 2016 and December 31, 2015 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing LIBOR borrowings at June 30, 2016 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 The Partnership is in compliance with all debt covenants as of June 30, 2016.

³ On April 27, 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.

The Partnership paid cash interest, net of proceeds received from interest rate swaptions and capitalized interest, in the amount of $4,757 and $22,116 for the three and six months ended June 30, 2016, respectively. The Partnership paid cash interest, net of proceeds received from interest rate swaptions and capitalized interest, in the amount of $3,015 and $21,104 for the three and six months ended June 30, 2015, respectively. Capitalized interest was $358 and $682 for the three and six months ended June 30, 2016, respectively. Capitalized interest was $570 and $1,095 for the three and six months ended June 30, 2015, respectively.


(10)	Partners' Capital

As of June 30, 2016, Partners’ capital consisted of 35,454,962 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owns 6,264,532 of the Partnership's common limited partner units representing approximately 17.7% of the Partnership's outstanding common limited partner units. Martin Midstream GP LLC ("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 MMGP Holdings, LLC ("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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

Incentive Distribution Rights

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. The general partner was allocated $3,893 and $7,786 in incentive distributions during the three and six months ended June 30, 2016, respectively. The general partner was allocated $3,893 and $7,631 in incentive distributions during the three and six months ended June 30, 2015, respectively.

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

Distributions of Available Cash

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

Net Income per Unit

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
Continuing operations:	2016			2015			2016			2015
Income (loss) from continuing operations	$	(1,211	)	$	10,961		$	14,703		$	26,994
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	3,893			3,893			7,786			7,452
Distributions payable on behalf of general partner interest	668			667			1,335			1,277
General partner interest in undistributed earnings	(692		)	(447		)	(1,041		)	(737		)
Less (income) loss allocable to unvested restricted units	(4		)	44			39			106
Limited partners’ interest in income (loss) from continuing operations	$	(5,076	)	$	6,804		$	6,584		$	18,896



	Three Months Ended June 30,				Six Months Ended June 30,
Discontinued operations:	2016		2015		2016		2015
Income from discontinued operations	$	—	$	—	$	—	$	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		—		—		335
Distributions payable on behalf of general partner interest	—		—		—		58
General partner interest in undistributed earnings	—		—		—		(34		)
Less income allocable to unvested restricted units	—		—		—		5
Limited partners’ interest in income from discontinued operations	$	—	$	—	$	—	$	851

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented:



	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Basic weighted average limited partner units outstanding	35,346,412	35,307,638	35,366,038	35,315,989
Dilutive effect of restricted units issued	—	68,499	13,880	56,115
Total weighted average limited partner diluted units outstanding	35,346,412	35,376,137	35,379,918	35,372,104

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented. All common unit equivalents were antidilutive for the three months ended June 30, 2016 because the limited partners were allocated a net loss in this period.


(11)	Related Party Transactions

As of June 30, 2016, Martin Resource Management owns 6,264,532 of the Partnership’s common units representing approximately 17.7% of the Partnership’s outstanding limited partner 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% general partner interest in the Partnership and the Partnership’s IDRs. The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of June 30, 2016, of approximately 17.7% of the Partnership’s outstanding limited partner units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

Omnibus Agreement

Omnibus Agreement. The Partnership and its general partner are parties to the Omnibus Agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain Martin Resource Management trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

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


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

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

•distributing NGLs; and

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

This restriction does not apply to:


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


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


◦	providing land transportation of various liquids;


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


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


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


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


◦	providing crude oil marketing and transportation from the well head to the end market;


◦	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; and


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


•	any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000;

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

•

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, 2016, through December 31, 2016, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $13,033. The Partnership reimbursed Martin Resource Management for $3,257 and $6,516 of indirect expenses for the three and six months ended June 30, 2016, respectively. The Partnership reimbursed Martin Resource Management for $3,419 and $6,839 of indirect expenses for the three and six months ended June 30, 2015, 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 the 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(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 NGLs as well as other liquid products.

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

Indemnification. Martin Transport, Inc. has indemnified the Partnership against all claims arising out of the negligence or willful misconduct of Martin Transport, Inc. and its officers, employees, agents, representatives and subcontractors. The Partnership has indemnified Martin Transport, Inc. against all claims arising out of the negligence or willful misconduct of the Partnership and its officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport, Inc. and the Partnership, 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, as amended, 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. Effective January 1, 2016, the Partnership entered into a new terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution. This agreement replaced the prior agreement that was in place concerning the same services, which was dated January 1, 2015. The minimum throughput requirements were reduced under the new agreement. The per gallon throughput fee the Partnership charges under this agreement was increased and 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. Most of these agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.

Other Agreements

Cross Tolling Agreement. The Partnership is a party to an amended and restated tolling agreement with Cross Oil Refining and Marketing, Inc. ("Cross") dated October 28, 2014, as amended, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement expires November 25, 2031. Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

day of crude oil at the facility at a fixed price per barrel. Any additional barrels are processed at a modified price per barrel. In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, on the third, sixth and ninth anniversaries of the agreement, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

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

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

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Revenues:
Terminalling and storage	$	20,590	$	23,061	$	41,548	$	43,535
Marine transportation	6,036		6,622		12,447		13,367
Natural gas services	129		—		442		—
Product sales:
Natural gas services	—		286		—		300
Sulfur services	667		970		1,049		2,044
Terminalling and storage	301		503		619		1,004
	968		1,759		1,668		3,348
	$	27,723	$	31,442	$	56,105	$	60,250

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Cost of products sold:
Natural gas services	$	4,498	$	6,810	$	7,883	$	13,728
Sulfur services	3,810		3,618		7,622		7,242
Terminalling and storage	4,081		5,632		7,466		11,034
	$	12,389	$	16,060	$	22,971	$	32,004

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Operating expenses:
Marine transportation	$	7,232	$	8,038	$	14,647	$	16,598
Natural gas services	2,380		1,992		4,626		4,155
Sulfur services	1,583		2,036		2,805		3,699
Terminalling and storage	6,893		6,849		13,367		14,863
	$	18,088	$	18,915	$	35,445	$	39,315

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Selling, general and administrative:
Marine transportation	$	5	$	8	$	13	$	16
Natural gas services	2,159		1,238		3,092		2,401
Sulfur services	824		642		1,411		1,438
Terminalling and storage	666		542		1,307		1,149
Indirect, including overhead allocation	3,257		3,419		6,520		6,839
	$	6,911	$	5,849	$	12,343	$	11,843

Other Related Party Transactions

The Partnership has a $15,000 note receivable from MET which bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. The note is recorded in "Note receivable - Martin Energy Trading LLC" on the Partnership's Consolidated and Condensed Balance Sheets. Interest income for the three months ended June 30, 2016 and 2015 was $561 and $561, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations. Interest income for the six months ended June 30, 2016 and 2015 was $1,122 and $1,116, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.

As discussed in Note 6, the Partnership has certain derivative financial instruments through March 31, 2017 to protect a portion of its commodity price risk exposure related to NGLs. MET serves as counterparty to the outstanding positions at June 30, 2016.


(12)	Income Taxes

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

The Partnership is subject to the Texas margin tax which is included in income tax expense on the Consolidated and Condensed Statements of Operations. The Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new "taxable margin" component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

immaterial. State income taxes attributable to the Texas margin tax of $191 and $314 were recorded in income tax expense for the three months ended June 30, 2016 and 2015, respectively. State income taxes attributable to the Texas margin tax of $242 and $614 were recorded in income tax expense for the six months ended June 30, 2016 and 2015, respectively.


(13)	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, 2015, filed with the SEC on February 29, 2016, as amended, by Amendment No. 1 on Form 10-K/A filed on March 30, 2016. 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 June 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	60,721	$	(1,302	)	$	59,419	$	10,078	$	7,675		$	2,955
Natural gas services	74,302		—			74,302		6,983		3,698			1,640
Sulfur services	42,288		—			42,288		2,011		10,286			2,477
Marine transportation	15,032		(693		)	14,339		3,017		(7,161		)	1,363
Indirect selling, general and administrative	—		—			—		—		(4,242		)	—
Total	$	192,343	$	(1,995	)	$	190,348	$	22,089	$	10,256		$	8,435



Three Months Ended June 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	69,287	$	(1,255	)	$	68,032	$	9,617	$	5,298		$	8,207
Natural gas services	114,350		—			114,350		8,373		9,260			5,395
Sulfur services	48,374		—			48,374		2,105		7,144			147
Marine transportation	20,886		(543		)	20,343		2,590		2,428			502
Indirect selling, general and administrative	—		—			—		—		(4,500		)	—
Total	$	252,897	$	(1,798	)	$	251,099	$	22,685	$	19,630		$	14,251

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)



Six Months Ended June 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	122,071	$	(2,756	)	$	119,315	$	20,076	$	14,025		$	15,130
Natural gas services	181,490		—			181,490		13,957		17,545			3,153
Sulfur services	84,463		—			84,463		3,981		18,471			3,793
Marine transportation	31,934		(1,249		)	30,685		6,123		(6,977		)	1,937
Indirect selling, general and administrative	—		—			—		—		(8,470		)	—
Total	$	419,958	$	(4,005	)	$	415,953	$	44,137	$	34,594		$	24,013



Six Months Ended June 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	139,321	$	(2,499	)	$	136,822	$	19,406	$	12,985		$	17,882
Natural gas services	277,140		—			277,140		16,775		18,147			14,109
Sulfur services	101,511		—			101,511		4,231		15,266			361
Marine transportation	42,832		(1,853		)	40,979		4,990		7,244			1,196
Indirect selling, general and administrative	—		—			—		—		(9,310		)	—
Total	$	560,804	$	(4,352	)	$	556,452	$	45,402	$	44,332		$	33,548

The Partnership's assets by reportable segment as of June 30, 2016 and December 31, 2015, are as follows:



	June 30, 2016		December 31, 2015
Total assets:
Terminalling and storage	$	414,988	$	417,202
Natural gas services	674,392		694,333
Sulfur services	129,399		134,108
Marine transportation	122,953		134,830
Total assets	$	1,341,732	$	1,380,473


(14)	Unit Based Awards

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Employees	$	209	$	341	$	410	$	652
Non-employee directors	55		10		76		98
Total unit-based compensation expense	$	264	$	351	$	486	$	750

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

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 six months ended June 30, 2016 is provided below:



	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	150,474			$	29.15
Granted	13,800			$	15.13
Vested	(55,474		)	$	30.68
Forfeited	(250		)	$	28.50
Non-Vested, end of period	108,550			$	27.60

Aggregate intrinsic value, end of period	$	2,508

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 six months ended June 30, 2016 and 2015 is provided below:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	—	$	—	$	1,183	$	110
Fair value of units vested	$	—	$	—	$	1,685	$	113

As of June 30, 2016, there was $1,668 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.93 years.

In conjunction with restricted unit issuances during the six months ended June 30, 2015, the Partnership received $55 in capital contributions from its general partner to maintain its 2% general partnership interest in the Partnership.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)

Unit Options. The plan currently permits the grant of options covering common units. As of June 30, 2016, 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.


(15)	Condensed Consolidating Financial Information

The Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating Partnership L.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership. The guarantees that have been issued are full, irrevocable and unconditional and joint and several. 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. Substantially all of the Partnership's operating subsidiaries are subsidiary guarantors of its outstanding senior unsecured notes and any subsidiaries other than the subsidiary guarantors are minor.


(16)	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.

Pursuant to a Purchase Price Reimbursement Agreement between the Partnership and Martin Resource Management related to the Partnership’s acquisition of the Redbird Gas Storage LLC ("Redbird") Class A interests on October 2, 2012, beginning in the second quarter of 2015, Martin Resource Management will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests. These payments are a result of Cardinal not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement. These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred to the Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. The agreement further provides for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions are not met. Currently, the Partnership expects to be fully reimbursed for the 2016 amount of $4,500. For the three and six months ended June 30, 2016, the Partnership received $1,125 and $1,875, respectively, related to the Purchase Price Reimbursement Agreement. For the each of the three and six months ended June 30, 2015, the Partnership received $750 related to the Purchase Price Reimbursement Agreement.

In 2015, the Partnership was named as a defendant in the cause J. A. Davis Properties, LLC v. Martin Operating Partnership L.P., in the 38th Judicial District Court, Cameron Parish, Louisiana. The plaintiff alleges that the Partnership has breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement. The plaintiff is seeking to evict the Partnership from the leased property and to recover damages. The Partnership intends to vigorously defend this matter and has asserted appropriate counterclaims against the plaintiff. At this time, the Partnership is unable to ascertain the damages, if any, that could ultimately be awarded against it.

On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with at least five lawsuits filed against it in the United States District Courts, which generally allege that the customer engaged in unlawful and deceptive business practices in connection with its marketing and advertising of its private label motor oil. The Partnership disputes that it has any obligation to defend or indemnify the customer for its conduct. Accordingly, on January 7, 2016, the Partnership filed a Complaint for Declaratory Judgment in the Chancery Court of Davidson County, Tennessee requesting a judicial determination that the Partnership does not owe the customer the demanded defense and indemnity obligations. Currently, we are unable to determine the exposure we may have in this matter, if any.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2016

(Unaudited)


(17)	Impairments and other charges

Marine Transportation Goodwill Impairment

The Partnership performed its annual assessment of the recoverability of goodwill during the third quarter of 2015. The Partnership updated its internal business outlook of the Marine Transportation reporting unit to consider the current economic environment that affects its operations. As part of the first step of goodwill impairment testing, the Partnership updated its assessment of its future cash flows, applying expected long-term growth rates, discount rates, and terminal values that the Partnership considers reasonable. Fair value was determined based on weighted average of the discounted cash flow method, the guideline public company method and the guideline transaction method. As a result of the analysis, the Partnership determined that there was no impairment of goodwill as of its annual assessment date. At the annual assessment date, the percentage of the fair value of the Partnership's Marine Transportation reporting unit over its carrying value was 41%.

Over the last year, global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to recent historical levels. This decrease in commodity prices has had, and is expected to continue to have, a negative impact on drilling and crude oil production in the areas served by the Partnership's marine transportation assets. Therefore, as of June 30, 2016, the Partnership determined that the state of market conditions, including the demand for utilization, day rates and the current oversupply of inland tank barges, indicated that an impairment of goodwill may exist. As a result, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, the Partnership prepared a quantitative analysis of the fair value of the goodwill as of June 30, 2016, based on the weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were driven by our actual results during the six months ended June 30, 2016 and the pricing and market conditions existing as of June 30, 2016, which were below our forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the analysis, a $4,145 impairment of all goodwill in the Marine Transportation reporting unit was incurred during the three months ended June 30, 2016. The Partnership did not recognize any impairment losses for goodwill during the six months ended June 30, 2015.

Divestiture of Non-Core Marine Equipment

During the three months ended June 30, 2016, the Partnership disposed of 8 inland tank barges and 2 inland push boats, which were deemed non-core assets to the Partnership's Marine Transportation business. The Partnership recognized a loss related to the disposition of these assets in the amount of $1,567, which is included in "Other operating loss" on the Partnership's Consolidated and Condensed Statements of Operations.


(18)	Subsequent Events

Quarterly Distribution. On July 21, 2016, the Partnership declared a quarterly cash distribution of $0.8125 per common unit for the second quarter of 2016, or $3.25 per common unit on an annualized basis, which will be paid on August 12, 2016 to unitholders of record as of August 5, 2016. Additionally, the Partnership expects to pay a distribution to its general partner in the amount of $4,561. Of this amount, $668 is related to the base general partner distribution and $3,893 represents incentive distribution rights paid to the general partner.



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" refer 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, 2015, filed with the Securities and Exchange Commission (the "SEC") on February 29, 2016, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2015 filed on March 30, 2016, 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 of naphthenic crude oil and the blending and packaging of finished lubricants;


•	Natural gas liquids transportation and distribution services and natural gas storage;


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


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

The petroleum products and by-products we collect, transport, store and market are produced primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the U.S. Gulf Coast region. This region is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry.

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of June 30, 2016, Martin Resource Management owned 17.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management

controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations 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.

Martin Resource Management has operated our business since 2002. Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.

Recent Developments

Commodity prices have declined substantially and experienced significant volatility. If commodity prices remain weak for a sustained period, our pipeline, terminalling throughput and NGL volumes may be negatively impacted, particularly as producers are curtailing or redirecting drilling. A sustained decline in commodity prices could result in a decrease in activity in the areas served by certain of our terminalling and storage and marine transportation assets resulting in reduced utilization of these assets. Drilling activity levels vary by geographic area, but in general, we have observed widespread decreases in drilling activity, particularly in the Gulf of Mexico, with lower commodity prices. The abundance of supply of inland marine tank barges in our predominantly Gulf Coast market has had a direct impact on our utilization as well a decreased transportation rates.

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, which includes force reductions and asset rationalization strategies. Given the current environment, we have altered and reduced our planned growth capital expenditures. We believe that controlling our spending in an effort to preserve liquidity is prudent and reduces our need for near-term access to the somewhat uncertain capital markets.

The following information highlights selected developments since January 1, 2016.

West Texas LPG Pipeline L.P. ("WTLPG") 2015 Rate Complaints. Certain shippers filed complaints with the Railroad Commission of Texas (“RRC”) challenging the increased rates WTLPG implemented effective July 1, 2015. The complaints request that the rate increase be suspended until the RRC has determined appropriate new rates. On March 8, 2016, the RRC issued an order directing that WTLPG’s rates “in effect prior to July 1, 2015, are the lawful rates for the duration of this docket unless changed by Commission order.” The RRC indicated that WTLPG’s rates should be reviewed on a market basis, without consideration of cost of service, if market information is available. A hearing on the merits of this complaint will be held on October 19, 2016 according to the initial procedural schedule set by the Administrative Law Judge overseeing this proceeding.

Credit Facility Amendment. On April 27, 2016, we made certain strategic amendments to our revolving credit facility which, among other things, decreased our borrowing capacity from $700.0 million to $664.4 million and extended the maturity date of the facility from March 28, 2018 to March 28, 2020.

Subsequent Events

Quarterly Distribution. On July 21, 2016, we declared a quarterly cash distribution of $0.8125 per common unit for the second quarter of 2016, or $3.25 per common unit on an annualized basis, which will be paid on August 12, 2016 to unitholders of record as of August 5, 2016. Additionally, we will pay a distribution to our general partner in the amount of $4.6 million. Of this amount, $0.7 million is related to the base general partner distribution and $3.9 million represents incentive distribution rights paid to our general partner.

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 requires 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 base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from these estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations or cash flows. You should also read Note 2, "Significant Accounting Policies" in Notes to Consolidated Financial Statements included within our Annual Report on Form 10-K for the year ended December 31, 2015. The following table evaluates the potential impact of estimates utilized during the periods ended June 30, 2016 and 2015:



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 an increase in uncollectible receivables. A 10% increase in our allowance for doubtful accounts would not significantly impact net income.
Depreciation
Depreciation expense is computed using the straight-line method over the useful life of the assets.	Determination of depreciation expense requires judgment regarding estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, estimates are reviewed to determine if any changes in the underlying assumptions are needed.	The lives of our fixed assets range from 3 - 50 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $7.7 million, resulting in a corresponding reduction in net income.
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.	Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.	No impairment of long-lived assets was recorded during the three or six months ended June 30, 2016 or 2015.
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, 2015 and determined that there was no impairment. During the three months ended June 30, 2016, we determined that based on a continued decrease in the demand for utilization and transportation day rates forecasted in our Marine Transportation reporting unit, an impairment of goodwill may exist. Based on the results of our impairment analysis, we determined that a $4.1 million impairment loss of all goodwill in the Marine Transportation reporting unit was incurred during the three months ended June 30, 2016. See note 17 for more information.
Purchase Price Allocations
We allocate the purchase price of an acquired business to its identifiable assets (including identifiable intangible assets) and liabilities based on their fair values at the date of acquisition. Any excess of purchase price in excess of amounts allocated to identifiable assets and liabilities is recorded as goodwill. As additional information becomes available, we may adjust the preliminary allocation for a period of up to one year.	The determination of fair values of acquired assets and liabilities requires a significant level of management judgment. Fair values are estimated using various methods as deemed appropriate. For significant transactions, third party assessments may be engaged to assist in the valuation process.	If subsequent factors indicate that estimates and assumptions used to allocate costs to acquired assets and liabilities differ from actual results, the allocation between goodwill, other intangible assets and fixed assets could significantly differ. Any such differences could impact future earnings through depreciation and amortization expense. Additionally, if estimated results supporting the valuation of goodwill or other intangible assets are not achieved, impairments could result.
Asset Retirement Obligations
Asset retirement obligations ("AROs") associated with a contractual or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and depreciated over the life of the related asset or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled.	Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate.	If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.
Environmental Liabilities
We estimate environmental liabilities using both internal and external resources. Activities include feasibility studies and other evaluations management considers appropriate. Environmental liabilities are recorded in the period in which the obligation can be reasonably estimated.	Estimating environmental liabilities requires significant management judgment as well as possible use of third party specialists knowledgeable in such matters.	Environmental liabilities have not adversely affected our results of operations or financial condition in the past, and we do not anticipate that they will in the future.

Our Relationship with Martin Resource Management

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


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


•	distributing fuel oil, ammonia, 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;


•	providing crude oil marketing and transportation from the well head to the end market;


•	operating an environmental consulting company;


•	operating an engineering services company;


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


•	operating a natural gas optimization business;


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


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

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

Ownership

Martin Resource Management owns approximately 17.7% of the outstanding limited partner units. In addition, Martin Resource Management controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2% 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 $34.1 million of direct costs and expenses for the three months ended June 30, 2016 compared to $37.4 million for the three months ended June 30, 2015. We reimbursed Martin Resource Management for $64.2 million of direct costs and expenses for the six months ended June 30, 2016 compared to $76.3 million for the six months ended June 30, 2015. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the three months ended June 30, 2016 and 2015, the Conflicts Committee approved reimbursement amounts of $3.3 million and $3.4 million, respectively. For the six months ended June 30, 2016 and 2015, the Conflicts Committee approved reimbursement amounts of $6.5 million and $6.8 million, respectively. The Conflicts Committee 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.

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, and Director Independence" set forth in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016.

Commercial

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

In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 12% and 11% of our total cost of products sold during the three months ended June 30, 2016 and 2015, respectively. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 10% and 9% of our total cost of products sold during the six months ended June 30, 2016 and 2015, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. Our sales to Martin Resource Management accounted for approximately 15% and 13% of our total revenues for the three months ended June 30, 2016 and 2015, respectively. Our sales to Martin Resource Management accounted for approximately 13% and 11% of our total revenues for the six months ended June 30, 2016 and 2015, 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, and Director Independence" set forth in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016.

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

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

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

Non-GAAP Financial Measures

The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the three and six months ended June 30, 2016 and 2015.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(in thousands)
Net income (loss)	$	(1,211	)	$	10,961		$	14,703		$	28,209
Less: Income from discontinued operations, net of income taxes	—			—			—			(1,215		)
Income (loss) from continuing operations	(1,211		)	10,961			14,703			26,994
Adjustments:
Interest expense	12,155			9,925			22,267			20,471
Income tax expense	191			314			242			614
Depreciation and amortization	22,089			22,685			44,137			45,402
EBITDA	33,224			43,885			81,349			93,481
Adjustments:
Equity in earnings of unconsolidated entities	(805		)	(1,649		)	(2,482		)	(3,389		)
(Gain) loss on sale of property, plant and equipment	1,679			153			1,595			165
Loss on impairment of goodwill	4,145			—			4,145			—
Unrealized mark-to-market on commodity derivatives	1,327			—			1,537			—
Distributions from unconsolidated entities	1,800			2,300			4,300			4,400
Unit-based compensation	264			351			486			750
Adjusted EBITDA	41,634			45,040			90,930			95,407
Adjustments:
Interest expense	(12,155		)	(9,925		)	(22,267		)	(20,471		)
Income tax expense	(191		)	(314		)	(242		)	(614		)
Amortization of debt premium	(76		)	(82		)	(153		)	(164		)
Amortization of deferred debt issuance costs	1,532			874			2,247			1,742
Non-cash mark-to-market on interest rate derivatives	—			—			(206		)	—
Payments for plant turnaround costs	(193		)	(286		)	(1,184		)	(1,754		)
Maintenance capital expenditures	(5,165		)	(3,424		)	(11,209		)	(5,183		)
Distributable Cash Flow	$	25,386		$	31,883		$	57,916		$	68,963

Results of Operations

The results of operations for the three and six months ended June 30, 2016 and 2015 have been derived from our consolidated and condensed financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating revenues and operating income by segment for the three and six months ended June 30, 2016 and 2015. The results of operations for these interim periods are not necessarily indicative of the results of operations which might be expected for the entire year.

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

Three Months Ended June 30, 2016 Compared to the Three Months Ended June 30, 2015



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income (Loss) Intersegment Eliminations			Operating Income (Loss) after Eliminations
Three Months Ended June 30, 2016	(in thousands)
Terminalling and storage	$	60,721	$	(1,302	)	$	59,419	$	8,440		$	(765	)	$	7,675
Natural gas services	74,302		—			74,302		3,045			653			3,698
Sulfur services	42,288		—			42,288		11,099			(813		)	10,286
Marine transportation	15,032		(693		)	14,339		(8,086		)	925			(7,161		)
Indirect selling, general and administrative	—		—			—		(4,242		)	—			(4,242		)
Total	$	192,343	$	(1,995	)	$	190,348	$	10,256		$	—		$	10,256



Three Months Ended June 30, 2015
Terminalling and storage	$	69,287	$	(1,255	)	$	68,032	$	6,061		$	(763	)	$	5,298
Natural gas services	114,350		—			114,350		8,809			451			9,260
Sulfur services	48,374		—			48,374		7,806			(662		)	7,144
Marine transportation	20,886		(543		)	20,343		1,454			974			2,428
Indirect selling, general and administrative	—		—			—		(4,500		)	—			(4,500		)
Total	$	252,897	$	(1,798	)	$	251,099	$	19,630		$	—		$	19,630

Six Months Ended June 30, 2016 Compared to the Six Months Ended June 30, 2015



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income (Loss) Intersegment Eliminations			Operating Income (Loss) after Eliminations
Six Months Ended June 30, 2016	(in thousands)
Terminalling and storage	$	122,071	$	(2,756	)	$	119,315	$	15,726		$	(1,701	)	$	14,025
Natural gas services	181,490		—			181,490		16,088			1,457			17,545
Sulfur services	84,463		—			84,463		19,958			(1,487		)	18,471
Marine transportation	31,934		(1,249		)	30,685		(8,708		)	1,731			(6,977		)
Indirect selling, general and administrative	—		—			—		(8,470		)	—			(8,470		)
Total	$	419,958	$	(4,005	)	$	415,953	$	34,594		$	—		$	34,594



	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Operating Income (Loss)			Operating Income (Loss) Intersegment Eliminations			Operating Income (Loss) after Eliminations
Six Months Ended June 30, 2015	(in thousands)
Terminalling and storage	$	139,321	$	(2,499	)	$	136,822	$	13,913		$	(928	)	$	12,985
Natural gas services	277,140		—			277,140		17,236			911			18,147
Sulfur services	101,511		—			101,511		17,359			(2,093		)	15,266
Marine transportation	42,832		(1,853		)	40,979		5,134			2,110			7,244
Indirect selling, general and administrative	—		—			—		(9,310		)	—			(9,310		)
Total	$	560,804	$	(4,352	)	$	556,452	$	44,332		$	—		$	44,332

Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended June 30, 2016 and 2015



	Three Months Ended June 30,					Variance			Percent Change
	2016		2015			Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	32,392	$	34,708		$	(2,316	)	(7	)%
Products	28,329		34,579			(6,250		)	(18	)%
Total revenues	60,721		69,287			(8,566		)	(12	)%

Cost of products sold	23,471		30,150			(6,679		)	(22	)%
Operating expenses	17,725		22,326			(4,601		)	(21	)%
Selling, general and administrative expenses	1,007		938			69			7	%
Depreciation and amortization	10,078		9,617			461			5	%
	8,440		6,256			2,184			35	%
Other operating loss	—		(195		)	195			(100	)%
Operating income	$	8,440	$	6,061		$	2,379		39	%

Lubricant sales volumes (gallons)	5,194		5,984			(790		)	(13	)%
Shore-based throughput volumes (gallons)	26,187		43,836			(17,649		)	(40	)%
Smackover refinery throughput volumes (BBL per day)	6,567		6,524			43			1	%
Corpus Christi crude terminal (BBL per day)	74,565		169,787			(95,222		)	(56	)%

Services revenues. Services revenue decreased $2.3 million, primarily as a result of decreased throughput volumes at our Corpus Christi crude terminal.

Products revenues. A 23% decrease in sales volumes at our blending and packaging facilities resulted in a $4.4 million decrease to products revenues. The decline in volumes resulted primarily from increased price competition. Product revenues at our shore-based terminals decreased $1.7 million resulting from a 4% decrease in sales volume as well as an 8% decrease in average sales price.

Cost of products sold. A 23% decrease in sales volumes at our blending and packaging facilities resulted in an $3.3 million decrease in cost of products sold. The average price per gallon decreased 12%, resulting in a $2.0 million decrease in cost of products sold. Cost of products sold at our shore-based terminals decreased $1.4 million resulting from a 4% decrease in sales volume as well as an 8% decrease in average cost per gallon.

Operating expenses. Operating expenses at our specialty terminals decreased $2.7 million, primarily due to decreases in repairs and maintenance of $1.3 million and decreased pass-through expenses at our Corpus Christi crude terminal of $1.0 million. Operating expenses at our Smackover refinery decreased $1.7 million, primarily due to decreases in repairs and maintenance of $1.0 million, outside services of $0.3 million, and utilities of $0.3 million.

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

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

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

Volumetric data. Actual volumes at our our Corpus Christi crude terminal for the quarter ended June 30, 2016 averaged 74,565 BBL per day, 10,435 BBL per day less than the contracted minimum throughput.

Comparative Results of Operations for the Six Months Ended June 30, 2016 and 2015



	Six Months Ended June 30,					Variance			Percent Change
	2016		2015			Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	65,549	$	69,749		$	(4,200	)	(6	)%
Products	56,522		69,572			(13,050		)	(19	)%
Total revenues	122,071		139,321			(17,250		)	(12	)%

Cost of products sold	47,821		61,311			(13,490		)	(22	)%
Operating expenses	36,441		42,679			(6,238		)	(15	)%
Selling, general and administrative expenses	2,107		1,811			296			16	%
Depreciation and amortization	20,076		19,406			670			3	%
	15,626		14,114			1,512			11	%
Other operating income (loss)	100		(201		)	301			(150	)%
Operating income	$	15,726	$	13,913		$	1,813		13	%

Lubricant sales volumes (gallons)	10,340		12,033			(1,693		)	(14	)%
Shore-based throughput volumes (gallons)	51,746		86,360			(34,614		)	(40	)%
Smackover refinery throughput volumes (BBL per day)	5,503		6,033			(530		)	(9	)%
Corpus Christi crude terminal (BBL per day)	83,600		175,151			(91,551		)	(52	)%

Services revenues. Services revenue decreased $4.2 million, primarily as a result of decreased throughput volumes at our Corpus Christi crude terminal.

Products revenues. A 25% decrease in sales volumes at our blending and packaging facilities resulted in a $9.6 million decrease to products revenues. The decline in volumes resulted primarily from the downturn in the energy industry, as well as increased price competition. Product revenues at our shore-based terminals decreased $3.8 million resulting from an 11% decrease in average sales price.

Cost of products sold. A 25% decrease in sales volumes at our blending and packaging facilities resulted in a $7.4 million decrease in cost of products sold. Average price per gallon decreased 7%, resulting in a $2.4 million decrease in cost of products sold. Cost of products sold at our shore-based terminals decreased $3.7 million resulting from a 12% decrease in average cost per gallon.

Operating expenses. Operating expenses at our specialty terminals decreased $4.0 million, primarily as a result of $1.8 million in decreased pass-through expenses, $1.2 million in decreased repairs and maintenance, a $0.3 million decrease related to

compensation expense, and a $0.5 million decrease in property taxes. Operating expenses at our Smackover refinery decreased $1.7 million, primarily as a result of $1.0 million in decreased repairs and maintenance, $0.5 million in decreased compensation expense, $0.6 million in decreased utilities expense, and decreased outside services of $0.3 million. These decreases were offset by an increase in property damage claims of $0.5 million.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.3 million primarily as a result of increased compensation expense in our blending and packaging operations.

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

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

Volumetric data. Actual volumes at our our Corpus Christi crude terminal for the six months ended June 30, 2016 averaged 83,600 BBL per day, 1,400 BBL per day less than the contracted minimum throughput.

Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended June 30, 2016 and 2015



	Three Months Ended June 30,						Variance			Percent Change
	2016			2015			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	15,403		$	16,564		$	(1,161	)	(7	)%
Products	58,899			97,786			(38,887		)	(40	)%
Total revenues	74,302			114,350			(40,048		)	(35	)%

Cost of products sold	56,233			89,074			(32,841		)	(37	)%
Operating expenses	6,138			5,727			411			7	%
Selling, general and administrative expenses	1,807			2,364			(557		)	(24	)%
Depreciation and amortization	6,983			8,373			(1,390		)	(17	)%
	3,141			8,812			(5,671		)	(64	)%
Other operating loss	(96		)	(3		)	(93		)	3,100	%
Operating income	$	3,045		$	8,809		$	(5,764	)	(65	)%

Distributions from unconsolidated entities	$	1,800		$	2,300		$	(500	)	(22	)%

NGL sales volumes (Bbls)	1,726			3,220			(1,494		)	(46	)%

Services Revenues. The decrease in services revenue is primarily a result of decreased storage rates at our Arcadia and Monroe gas storage facilities.

Products Revenues. Our NGL average sales price per barrel increased $3.76, or 12%, resulting in an increase to products revenues of $12.1 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes decreased 46%, decreasing products revenues $51.0 million.

Cost of products sold. Our average cost per barrel excluding the effects of non-cash mark-to-market adjustments on derivative instruments increased $4.15, or 15%, increasing cost of products sold by $13.4 million. The increase in average cost per barrel was a result of an increase in market prices. The decrease in sales volume of 46% resulted in a $47.5 million decrease to cost of products sold. Our margins decreased $0.39 per barrel, or 15% during the period.

Operating expenses. Operating expenses increased $0.4 million as a result of a $0.2 million increase in pipeline maintenance related to our East Texas NGL pipeline and a $0.2 million increase from our Arcadia rail facility put into service in June 2015.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased primarily due to decreased compensation expense.

Depreciation and amortization. Depreciation and amortization decreased $1.4 million primarily due to a $1.7 million decrease in amortization related to contracts acquired during the purchase of Cardinal, offset by a $0.3 million increase in depreciation expense related to recent capital expenditures.

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

Comparative Results of Operations for the Six Months Ended June 30, 2016 and 2015



	Six Months Ended June 30,						Variance			Percent Change
	2016			2015			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	31,500		$	33,051		$	(1,551	)	(5	)%
Products	149,990			244,089			(94,099		)	(39	)%
Total revenues	181,490			277,140			(95,650		)	(35	)%

Cost of products sold	135,581			227,241			(91,660		)	(40	)%
Operating expenses	11,657			11,416			241			2	%
Selling, general and administrative expenses	4,111			4,465			(354		)	(8	)%
Depreciation and amortization	13,957			16,775			(2,818		)	(17	)%
	16,184			17,243			(1,059		)	(6	)%
Other operating loss	(96		)	(7		)	(89		)	1,271	%
Operating income	$	16,088		$	17,236		$	(1,148	)	(7	)%

Distributions from unconsolidated entities	$	4,300		$	4,400		$	(100	)	(2	)%

NGL sales volumes (Bbls)	4,928			7,089			(2,161		)	(30	)%

Services Revenues. The decrease in services revenue is primarily a result of decreased storage rates at our Arcadia and Monroe gas storage facilities.

Products Revenues. Our NGL average sales price per barrel decreased $4.00, or 12%, resulting in a decrease to products revenues of $28.3 million. The decrease in average sales price per barrel was a result of a decline in market prices. Product sales volumes decreased 31%, decreasing products revenues $65.8 million.

Cost of products sold. Our average cost per barrel excluding the effects of non-cash mark-to-market adjustments on derivative instruments decreased $4.86, or 15%, decreasing cost of products sold by $34.4 million. The decrease in average cost per barrel was a result of a decline in market prices. The decrease in sales volume of 31% resulted in a $58.8 million decrease to cost of products sold. Our margins increased $0.86 per barrel, or 36% during the period.

Operating expenses. Operating expenses increased $0.2 million primarily due to a $0.8 million increase from our Arcadia rail facility put into service in June 2015, offset by lower fuel expense at our Cardinal Gas Storage facilities and a $0.1 million decreased pipeline maintenance related to our East Texas NGL pipeline.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased primarily due to decreased consulting fees.

Depreciation and amortization. Depreciation and amortization decreased $2.8 million primarily due to a $3.4 million decrease in amortization related to contracts acquired during the purchase of Cardinal, offset by a $0.6 million increase in depreciation expense related to recent capital expenditures.

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

Sulfur Services Segment

Comparative Results of Operations for the Three Months Ended June 30, 2016 and 2015



	Three Months Ended June 30,					Variance			Percent Change
	2016			2015		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	2,700		$	3,090	$	(390	)	(13	)%
Products	39,588			45,284		(5,696		)	(13	)%
Total revenues	42,288			48,374		(6,086		)	(13	)%

Cost of products sold	24,790			33,613		(8,823		)	(26	)%
Operating expenses	3,442			3,987		(545		)	(14	)%
Selling, general and administrative expenses	930			863		67			8	%
Depreciation and amortization	2,011			2,105		(94		)	(4	)%
	11,115			7,806		3,309			42	%
Other operating loss	(16		)	—		(16		)
Operating income	$	11,099		$	7,806	$	3,293		42	%

Sulfur (long tons)	181			222		(41		)	(18	)%
Fertilizer (long tons)	87			82		5			6	%
Total sulfur services volumes (long tons)	268			304		(36		)	(12	)%

Revenues. Products revenue decreased $5.3 million as a result of a 12% decrease in sales volumes, attributable primarily to an 18% decrease in sulfur volumes. A 1% decline in average sales price decreased products revenue an additional $0.4 million.

Cost of products sold. A 16% decrease in prices reduced cost of products sold by $5.5 million, resulting from a decline in commodity prices. A 12% decrease in volumes resulted in an additional decrease in cost of products sold of $3.3 million. Margin per ton increased $16.82, or 44%.

Operating expenses. Our operating expenses decreased primarily as a result of reduced fuel expense of $0.4 million.

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

Depreciation and amortization. The decrease in depreciation and amortization is due to asset dispositions in the fourth quarter of 2015.

Comparative Results of Operations for the Six Months Ended June 30, 2016 and 2015



	Six Months Ended June 30,					Variance			Percent Change
	2016			2015		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	5,400		$	6,180	$	(780	)	(13	)%
Products	79,063			95,331		(16,268		)	(17	)%
Total revenues	84,463			101,511		(17,048		)	(17	)%

Cost of products sold	52,405			69,726		(17,321		)	(25	)%
Operating expenses	6,199			8,270		(2,071		)	(25	)%
Selling, general and administrative expenses	1,888			1,925		(37		)	(2	)%
Depreciation and amortization	3,981			4,231		(250		)	(6	)%
	19,990			17,359		2,631			15	%
Other operating loss	(32		)	—		(32		)
Operating income	$	19,958		$	17,359	$	2,599		15	%

Sulfur (long tons)	338			438		(100		)	(23	)%
Fertilizer (long tons)	170			178		(8		)	(4	)%
Total sulfur services volumes (long tons)	508			616		(108		)	(18	)%

Revenues. Products revenue decreased $17.0 million as a result of an 18% decrease in sales volumes, attributable primarily to a 23% decrease in sulfur volumes. A 1% increase in average sales price caused an offsetting increase to products revenue of $0.7 million.

Cost of products sold. An 18% decrease in sales volumes decreased cost of products sold by $11.3 million. A 9% decrease in prices reduced our cost of products sold by $6.0 million. Margin per ton increased $11.01, or 26%.

Operating expenses. Our operating expenses decreased primarily as a result of $0.9 million in lower fuel expense, property taxes of $0.3 million, terminal and thruput fees of $0.2 million, and compensation expense of $0.2 million. Also contributing to the reduction in operating expense was a decrease in utilities, outside towing expenses, and other marine operating expenses of $0.1 million each.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased slightly due to decreased bad debt expense, compensation expense, and communications expense.

Depreciation and amortization. The decrease in depreciation and amortization is due to asset dispositions in the fourth quarter of 2015.

Marine Transportation Segment

Comparative Results of Operations for the Three Months Ended June 30, 2016 and 2015



	Three Months Ended June 30,					Variance			Percent Change
	2016			2015		Variance			Percent Change
	(In thousands)
Revenues	$	15,032		$	20,886	$	(5,854	)	(28)%
Operating expenses	14,231			16,523		(2,292		)	(14)%
Selling, general and administrative expenses	158			350		(192		)	(55)%
Loss on impairment of goodwill	4,145			—		4,145
Depreciation and amortization	3,017			2,590		427			16%
	(6,519		)	1,423		(7,942		)	(558)%
Other operating income (loss)	(1,567		)	31		(1,598		)	(5,155)%
Operating income (loss)	$	(8,086	)	$	1,454	$	(9,540	)	(656)%

Inland revenues. A $2.7 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet resulting from an abundance of supply of marine equipment in our predominantly Gulf Coast market.

Offshore revenues. A $2.0 million decrease in offshore revenue is the result of decreased utilization of the offshore fleet.

Pass-through revenues. A $1.3 million decrease in pass-through revenues was primarily related to fuel.

Operating expenses. The decrease in operating expenses is a result of decreased pass-through expenses (primarily fuel) of $1.3 million, compensation expense of $0.5 million, and lower repairs and maintenance of $1.3 million. Offsetting these decreases were increases in claims expense of $0.6 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.2 million due to decreased legal fees of $0.1 million and consulting fees of $0.1 million

Loss on impairment of goodwill. This represents the loss on impairment of goodwill in the Marine Transportation reporting unit during the second quarter of 2016.

Depreciation and amortization. Depreciation and amortization increased as a result of recent capital expenditures offset by the disposal of property, plant and equipment.

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

Comparative Results of Operations for the Six Months Ended June 30, 2016 and 2015



	Six Months Ended June 30,					Variance			Percent Change
	2016			2015		Variance			Percent Change
	(In thousands)
Revenues	$	31,934		$	42,832	$	(10,898	)	(25)%
Operating expenses	29,068			32,429		(3,361		)	(10)%
Selling, general and administrative expenses	(261		)	310		(571		)	(184)%
Loss on impairment of goodwill	4,145			—		4,145
Depreciation and amortization	6,123			4,990		1,133			23%
Operating income	$	(7,141	)	$	5,103	$	(12,244	)	(240)%
Other operating income (loss)	(1,567		)	31		(1,598		)	(5,155)%
Operating income (loss)	$	(8,708	)	$	5,134	$	(13,842	)	(270)%

Inland revenues. A $5.1 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet resulting from an abundance of supply of marine equipment in our predominantly Gulf Coast market.

Offshore revenues. A $3.7 million decrease in offshore revenue is the result of decreased utilization of the offshore fleet, partially offset by the recognition of previously deferred revenues of $1.5 million.

Pass-through revenues. A $2.3 million decrease in pass-through revenues was primarily related to fuel.

Operating expenses. The decrease in operating expenses is a result of decreased pass-through expenses (primarily fuel) of $2.3 million, compensation expense of $0.9 million, and lower repairs and maintenance of $1.7 million. Offsetting these decreases were increases in claims expense of $0.5 million, property and liability premiums of $0.5 million, outside towing of $0.4 million, and property taxes of $0.3 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased due to the 2016 period including the collection of a previously deemed uncollectible receivable.

Loss on impairment of goodwill. This represents the loss on impairment of goodwill in the Marine Transportation reporting unit during the second quarter of 2016.

Depreciation and amortization. Depreciation and amortization increased as a result of recent capital expenditures offset by the disposal of property, plant and equipment.

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

Equity in Earnings of and Distributions from Unconsolidated Entities for the Three Months Ended June 30, 2016 and 2015



	Three Months Ended June 30,				Variance			Percent Change
	2016		2015		Variance			Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	805	$	1,649	$	(844	)	(51)%



	Three Months Ended June 30,				Variance			Percent Change
	2016		2015		Variance			Percent Change
	(In thousands)
Distributions from WTLPG	$	1,800	$	2,300	$	(500	)	(22)%

Equity in earnings from West Texas LPG Pipeline L.P. ("WTLPG") decreased primarily due to an increase in repairs and maintenance on the asset. Distributions from WTLPG decreased $0.5 million.

Equity in Earnings in and Distributions from Unconsolidated Entities for the Six Months Ended June 30, 2016 and 2015



	Six Months Ended June 30,				Variance			Percent Change
	2016		2015		Variance			Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	2,482	$	3,389	$	(907	)	(27	)%



	Six Months Ended June 30,				Variance			Percent Change
	2016		2015		Variance			Percent Change
	(In thousands)
Distributions from WTLPG	$	4,300	$	4,400	$	(100	)	(2	)%

Equity in earnings from WTLPG decreased primarily due to an increase in repairs and maintenance on the asset. Distributions from WTLPG slightly decreased $0.1 million.

Interest Expense, Net

Comparative Components of Interest Expense, Net for the Three Months Ended June 30, 2016 and 2015



	Three Months Ended June 30,						Variance			Percent Change
	2016			2015			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	4,550		$	4,009		$	541		13%
7.25% Senior notes	6,851			7,250			(399		)	(6)%
Amortization of deferred debt issuance costs	1,532			874			658			75%
Amortization of debt discount	(76		)	(82		)	6			(7)%
Impact of interest rate derivative activity, including cash settlements	—			(1,120		)	1,120			(100)%
Other	217			125			92			74%
Capitalized interest	(358		)	(570		)	212			(37)%
Interest income	(561		)	(561		)	—			—%
Total interest expense, net	$	12,155		$	9,925		$	2,230		22%

Comparative Components of Interest Expense, Net for the Six Months Ended June 30, 2016 and 2015



	Six Months Ended June 30,						Variance			Percent Change
	2016			2015			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	8,726		$	8,130		$	596		7%
7.25% Senior notes	13,626			14,500			(874		)	(6)%
Amortization of deferred debt issuance costs	2,247			1,742			505			29%
Amortization of debt premium	(153		)	(164		)	11			(7)%
Impact of interest rate derivative activity, including cash settlements	(995		)	(1,745		)	750			(43)%
Other	620			219			401			183%
Capitalized interest	(682		)	(1,095		)	413			(38)%
Interest income	(1,122		)	(1,116		)	(6		)	1%
Total interest expense, net	$	22,267		$	20,471		$	1,796		9%

Indirect Selling, General and Administrative Expenses



	Three Months Ended June 30,				Variance			Percent Change	Six Months Ended June 30,				Variance			Percent Change
	2016		2015		Variance			Percent Change	2016		2015		Variance			Percent Change
	(In thousands)								(In thousands)
Indirect selling, general and administrative expenses	$	4,242	$	4,500	$	(258	)	(6)%	$	8,470	$	9,310	$	(840	)	(9)%

Indirect selling, general and administrative expenses decreased for the three months ended June 30, 2016 due primarily to a $0.2 million reduction in overhead expense allocated from Martin Resource Management.

For the six months ended June 30, 2016, the decrease in indirect selling, general and administrative expenses is attributable to a $0.3 million reduction in overhead expense allocated from Martin Resource Management, $0.3 million in lower unit grant compensation expense, and reduced audit and legal fees of $0.1 million each.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, legal, 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 during the three months and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,				Variance			Percent Change	Six Months Ended June 30,				Variance			Percent Change
	2016		2015		Variance			Percent Change	2016		2015		Variance			Percent Change
	(In thousands)								(In thousands)
Conflicts Committee approved reimbursement amount	$	3,257	$	3,419	$	(162	)	(5)%	$	6,516	$	6,839	$	(323	)	(5)%

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 have historically been cash flows generated by our operations and access to debt and equity markets, both public and private. 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 revolving credit facility. Given the current environment, we have altered and reduced our planned growth capital expenditures. We believe that controlling our spending in an effort to preserve liquidity is prudent and reduces our need for near-term access to the somewhat uncertain capital markets.

Recent Debt Financing Activity

In 2015, we repurchased on the open market an aggregate $26.2 million of our outstanding 7.25% senior unsecured notes. These transactions resulted in a gain on retirement of debt of $1.2 million.

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 2016.

Finally, 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, 2015, filed with the SEC on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016, for a discussion of such risks.

Cash Flows - Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

The following table details the cash flow changes between the six months ended June 30, 2016 and 2015:



	Six Months Ended June 30,						Variance			Percent Change
	2016			2015			Variance			Percent Change
	(In thousands)
Net cash provided by (used in):
Operating activities	$	74,803		$	104,084		$	(29,281	)	(28)%
Investing activities	(21,423		)	12,245			(33,668		)	(275)%
Financing activities	(53,383		)	(116,347		)	62,964			(54)%
Net increase (decrease) in cash and cash equivalents	$	(3	)	$	(18	)	$	15		(83)%

The change in net cash provided by operating activities for the six months ended June 30, 2016 includes a decrease in operating results plus other non-cash items of $5.5 million, and a $25.0 million unfavorable variance in working capital. Net cash used in discontinued operating activities decreased $1.4 million in 2016.

Net cash provided by (used in) investing activities for the six months ended June 30, 2016 decreased primarily as a result of the 2015 period including $41.3 million in cash proceeds from the disposition of certain floating storage assets classified as discontinued operations. Offsetting these proceeds was an acquisition of intangible assets of $2.2 million in 2016 compared to no acquisitions in 2015. Additionally, $9.1 million represents proceeds from involuntary conversion of property, plant and equipment.

The change in net cash used in financing activities for the six months ended June 30, 2016 is due to a decrease in net repayments of long-term borrowings of $67.0 million. In 2016, we paid an additional $4.9 million in costs associated with our credit facility amendment compared to the previous period.

Capital Expenditures and Plant Turnaround Costs

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:

•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;

•maintenance capital expenditures made to maintain existing assets and operations; and

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

The following table summarizes our capital expenditure activity, excluding amounts paid for acquisitions, for the periods presented:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In thousands)
Expansion capital expenditures	$	3,078	$	10,541	$	11,620	$	26,611
Maintenance capital expenditures	5,164		3,424		11,209		5,183
Plant turnaround costs	193		286		1,184		1,754
Total	$	8,435	$	14,251	$	24,013	$	33,548

Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three and six months ended June 30, 2016. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery and on certain organic growth projects ongoing in our specialty terminalling operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage, Sulfur Services, and Marine Transportation

segments to maintain our existing assets and operations during the three and six months ended June 30, 2016. The increase is primarily related to tank repairs in our specialty terminalling business and a three-year regulatory coast guard inspection on our two marine vessels that operate in our sulfur business. For the three and six months ended June 30, 2016 and 2015, plant turnaround costs relate to our Smackover refinery.

Expansion capital expenditures were made primarily in our Terminalling and Storage and Natural Gas Services segments during the three and six months ended June 30, 2015. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery and on certain organic growth projects ongoing in our specialty terminalling operations. Within our Natural Gas Services segment, expenditures were made on ongoing organic growth projects. Maintenance capital expenditures were made primarily in our Terminalling and Storage segment to maintain our existing assets and operations during the three and six months ended June 30, 2015. For the three and six months ended June 30, 2015, plant turnaround costs relate to our Smackover refinery.

Capital Resources

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

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of June 30, 2016, 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	$	515,000	$	—	$	—	$	515,000	$	—
2021 Senior unsecured notes	373,800		—		—		373,800		—
Throughput commitment	31,606		6,257		12,793		12,472		84
Exclusive right of use commitment	10,000		10,000		—		—		—
Operating leases	52,097		13,727		17,461		12,030		8,879
Interest expense: ¹
Revolving credit facility	66,578		17,803		35,606		13,169		—
2021 Senior unsecured notes	125,340		27,101		54,201		44,038		—
Total contractual cash obligations	$	1,174,421	$	74,888	$	120,061	$	970,509	$	8,963

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

Letters of Credit. At June 30, 2016, we had outstanding irrevocable letters of credit in the amount of $0.1 million, which were issued under our revolving credit facility.

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

Description of Our Long-Term Debt

2021 Senior Notes

For a description of our 7.25% senior unsecured notes due 2021, 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, 2015, as amended.

Revolving Credit Facility

At June 30, 2016, we maintained a $664.4 million credit facility. This facility was most recently amended on April 27, 2016, when we made certain strategic amendments to our revolving credit facility which, among other things, decreased our borrowing capacity from $700.0 million to $664.4 million and extended the maturity date of the facility from March 28, 2018 to March 28, 2020.

As of June 30, 2016, we had $515.0 million outstanding under the revolving credit facility and $0.1 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 $149.3 million. Subject to the financial covenants contained in our credit facility and based on our existing EBITDA (as defined in our credit facility) calculations, as of June 30, 2016, we have the ability to borrow approximately $90.7 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 six months ended June 30, 2016, the level of outstanding draws on our credit facility has ranged from a low of $498.0 million to a high of $556.5 million.

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

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

Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee on all letters of credit issued under the credit facility, and we pay a commitment fee per annum on the unused revolving credit availability under the credit facility. The letter of credit fee, the commitment fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows as of June 30, 2016:



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	%

At June 30, 2016, 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 June 30, 2016 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 with a temporary springing provision to 5.50 to 1.00 under certain scenarios. The maximum permitted senior leverage ratio (as defined in the credit facility but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00. The minimum interest coverage ratio (as defined in the credit facility but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.50 to 1.00.

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

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

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under the credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us.

If an event of default relating to bankruptcy or other insolvency events occurs with respect to us or any of our subsidiaries, all indebtedness under our credit facility will immediately become due and payable. If any other event of default exists under our credit facility, the lenders may terminate their commitments to lend us money, accelerate the maturity of the indebtedness outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral.

As of July 27, 2016, our outstanding indebtedness includes $540.0 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.

The Partnership is in compliance with all debt covenants as of June 30, 2016 and expects to be in compliance for the next twelve months.

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 WTLPG and natural gas storage divisions of the Natural Gas Services segment each provide stable cash flows and are not generally subject to seasonal demand factors. Additionally, our Terminalling and Storage and Marine Transportation segments and the molten sulfur business are typically not impacted by seasonal fluctuations and a significant portion of our net income is derived from our terminalling and storage, sulfur and marine transportation businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our Terminalling and Storage and Marine Transportation segments.

Impact of Inflation

Inflation did not have a material impact on our results of operations for the six months ended June 30, 2016 or 2015. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the six months ended June 30, 2016 or 2015.



Item 3.	Quantitative and Qualitative Disclosures about Market Risk

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

We have entered into hedging transactions as of June 30, 2016 to protect a portion of our commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. We have instruments totaling a net notional quantity of 383,000 barrels settling during the period from October 31, 2016 through March 31, 2017. These instruments settle against OPIS Mont Belvieu (non-TET) monthly average price. These instruments are recorded on our Consolidated and Condensed Balance Sheets at June 30, 2016 in "Fair value of derivatives" as a current liability of $0.8 million. Based on the current net notional volume hedged as of June 30, 2016, a $0.10 change in the expected settlement price of these contracts would result in an impact of $1.6 million to the Partnership's net income.

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 3.46% as of June 30, 2016. Based on the amount of unhedged floating rate debt owed by us on June 30, 2016, the impact of a 100 basis point increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $5.2 million annually.

We are not exposed to changes in interest rates with respect to our senior unsecured notes as these obligations are fixed rate. The estimated fair value of the senior unsecured notes was approximately $345.1 million as of June 30, 2016, based on market prices of similar debt at June 30, 2016. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of a 100 basis point increase in interest rates. Such an increase in interest rates would result in approximately a $12.9 million decrease in fair value of our long-term debt at June 30, 2016.



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 SEC’s rules and forms.

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

PART II - OTHER INFORMATION



Item 1.	Legal Proceedings

From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. Information regarding legal proceedings is set forth in Note 16 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 February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016.



Item 6.	Exhibits

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

SIGNATURES

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



	Martin Midstream Partners L.P.

	By:	Martin Midstream GP LLC
		Its General Partner

Date: 7/27/2016	By:	/s/ Robert D. Bondurant
		Robert D. Bondurant
		Executive Vice President, Treasurer, Chief Financial Officer, and Principal Accounting Officer

INDEX TO EXHIBITS



Exhibit Number		Exhibit Name

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 June 30, 2016, 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; and (5) the Notes to Consolidated and Condensed Financial Statements.

* Filed or furnished herewith