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, 2018



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, a smaller reporting company, or an emerging growth company. See definition of "large accelerated filer," "accelerated filer", "smaller reporting company", and "emerging growth company" in Rule 12b-2 of the Exchange Act.



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 25, 2018, was 39,052,237.



	Page

PART I – FINANCIAL INFORMATION	2

Item 1. Financial Statements	2
Consolidated and Condensed Balance Sheets as of June 30, 2018 (unaudited) and December 31, 2017 (audited)	2
Consolidated and Condensed Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017 (unaudited)	3
Consolidated and Condensed Statements of Capital for the Six Months Ended June 30, 2018 and 2017 (unaudited)	5
Consolidated and Condensed Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017 (unaudited)	6
Notes to Consolidated and Condensed Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

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, 2018			December 31, 2017
	(Unaudited)			(Audited)
Assets
Cash	$	610		$	27
Accounts and other receivables, less allowance for doubtful accounts of $405 and $314, respectively	60,884			107,242
Product exchange receivables	174			29
Inventories (Note 6)	113,100			97,252
Due from affiliates	21,031			23,668
Other current assets	5,368			4,866
Assets held for sale (Note 4)	8,158			9,579
Total current assets	209,325			242,663

Property, plant and equipment, at cost	1,273,392			1,253,065
Accumulated depreciation	(450,564		)	(421,137		)
Property, plant and equipment, net	822,828			831,928

Goodwill	17,296			17,296
Investment in WTLPG (Note 7)	141,114			128,810
Other assets, net (Note 9)	28,202			32,801
Total assets	$	1,218,765		$	1,253,498

Liabilities and Partners’ Capital
Trade and other accounts payable	$	72,945		$	92,567
Product exchange payables	13,015			11,751
Due to affiliates	1,271			3,168
Income taxes payable	400			510
Fair value of derivatives (Note 10)	572			72
Other accrued liabilities (Note 9)	23,093			26,340
Total current liabilities	111,296			134,408

Long-term debt, net (Note 8)	831,928			812,632
Other long-term obligations	10,842			8,217
Total liabilities	954,066			955,257

Commitments and contingencies (Note 15)
Partners’ capital (Note 11)	264,699			298,241
Total partners’ capital	264,699			298,241
Total liabilities and partners' capital	$	1,218,765		$	1,253,498

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,
	2018			2017			2018			2017
Revenues:
Terminalling and storage *	$	24,090		$	24,695		$	48,154		$	49,353
Marine transportation *	12,739			12,433			24,193			25,254
Natural gas services*	13,804			14,838			29,160			29,503
Sulfur services	2,787			2,850			5,574			5,700
Product sales: *
Natural gas services	90,643			73,666			249,806			200,323
Sulfur services	35,684			32,027			70,584			71,554
Terminalling and storage	36,824			33,413			73,304			65,560
	163,151			139,106			393,694			337,437
Total revenues	216,571			193,922			500,775			447,247

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	87,642			70,198			230,599			178,377
Sulfur services *	28,739			21,207			52,635			45,690
Terminalling and storage *	33,206			29,897			66,166			58,026
	149,587			121,302			349,400			282,093
Expenses:
Operating expenses *	31,510			32,552			62,964			65,926
Selling, general and administrative *	8,572			8,909			18,240			18,830
Depreciation and amortization	20,891			20,326			40,101			45,662
Total costs and expenses	210,560			183,089			470,705			412,511

Other operating income (loss)	(490		)	15			(492		)	(140		)
Operating income	5,521			10,848			29,578			34,596

Other income (expense):
Equity in earnings of WTLPG	1,131			853			2,726			1,758
Interest expense, net	(13,766		)	(11,219		)	(26,451		)	(22,139		)
Other, net	—			520			—			550
Total other expense	(12,635		)	(9,846		)	(23,725		)	(19,831		)

Net income (loss) before taxes	(7,114		)	1,002			5,853			14,765
Income tax expense	(132		)	(13		)	(281		)	(193		)
Net income (loss)	(7,246		)	989			5,572			14,572
Less general partner's interest in net (income) loss	145			(19		)	(111		)	(291		)
Less (income) loss allocable to unvested restricted units	6			(3		)	(2		)	(38		)
Limited partners' interest in net income (loss)	$	(7,095	)	$	967		$	5,459		$	14,243

Net income (loss) per unit attributable to limited partners - basic	$	(0.18	)	$	0.03		$	0.14		$	0.38
Net income (loss) per unit attributable to limited partners - diluted	$	(0.18	)	$	0.03		$	0.14		$	0.38
Weighted average limited partner units - basic	38,722			38,357			38,829			37,842
Weighted average limited partner units - diluted	38,722			38,414			38,834			37,895

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,
	2018		2017		2018		2017
Revenues:*
Terminalling and storage	$	20,507	$	20,331	$	40,532	$	40,035
Marine transportation	4,105		4,187		7,718		8,512
Natural gas services	—		6		—		118
Product Sales	426		724		1,068		2,154
Costs and expenses:*
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	3,099		2,909		7,417		11,803
Sulfur services	4,345		3,767		8,871		7,442
Terminalling and storage	8,009		4,119		14,567		9,186
Expenses:
Operating expenses	14,339		16,452		27,723		32,828
Selling, general and administrative	6,498		6,500		14,219		14,068

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, 2017	35,452,062		$	304,594		$	7,412		$	312,006
Net income	—		14,281			291			14,572
Issuance of common units, net	2,990,000		51,071			—			51,071
Issuance of restricted units	12,000		—			—			—
Forfeiture of restricted units	(1,750	)	—			—			—
General partner contribution	—		—			1,098			1,098
Cash distributions	—		(36,952		)	(754		)	(37,706		)
Unit-based compensation	—		405			—			405
Purchase of treasury units	(200	)	(4		)	—			(4		)
Excess purchase price over carrying value of acquired assets	—		(7,887		)	—			(7,887		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		1,125			—			1,125
Balances - June 30, 2017	38,452,112		$	326,633		$	8,047		$	334,680

Balances - January 1, 2018	38,444,612		$	290,927		$	7,314		$	298,241
Net income	—		5,461			111			5,572
Issuance of common units, net of issuance related costs	—		(118		)	—			(118		)
Issuance of restricted units	633,425		—			—			—
Forfeiture of restricted units	(7,000	)	—			—			—
Cash distributions	—		(38,433		)	(784		)	(39,217		)
Unit-based compensation	—		520			—			520
Excess purchase price over carrying value of acquired assets	—		(26		)	—			(26		)
Purchase of treasury units	(18,800	)	(273		)	—			(273		)
Balances - June 30, 2018	39,052,237		$	258,058		$	6,641		$	264,699

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,
	2018			2017
Cash flows from operating activities:
Net income	$	5,572		$	14,572
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	40,101			45,662
Amortization of deferred debt issuance costs	1,689			1,445
Amortization of premium on notes payable	(153		)	(153		)
Loss on sale of property, plant and equipment	492			140
Equity in earnings of WTLPG	(2,726		)	(1,758		)
Derivative (income) loss	(2,069		)	2,392
Net cash received (paid) for commodity derivatives	2,569			(6,429		)
Unit-based compensation	520			405
Cash distributions from WTLPG	3,000			2,500
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	46,592			29,522
Product exchange receivables	(145		)	(13		)
Inventories	(15,900		)	(19,065		)
Due from affiliates	2,632			(9,726		)
Other current assets	(699		)	(1,372		)
Trade and other accounts payable	(17,333		)	(4,067		)
Product exchange payables	1,264			246
Due to affiliates	(1,897		)	(5,774		)
Income taxes payable	(110		)	(468		)
Other accrued liabilities	(5,480		)	(2,761		)
Change in other non-current assets and liabilities	584			490
Net cash provided by operating activities	58,503			45,788

Cash flows from investing activities:
Payments for property, plant and equipment	(23,566		)	(19,756		)
Acquisitions	—			(19,533		)
Payments for plant turnaround costs	—			(1,591		)
Proceeds from sale of property, plant and equipment	98			1,597
Proceeds from repayment of Note receivable - affiliate	—			15,000
Contributions to WTLPG	(12,578		)	(145		)
Net cash used in investing activities	(36,046		)	(24,428		)

Cash flows from financing activities:
Payments of long-term debt	(199,000		)	(184,000		)
Proceeds from long-term debt	218,000			155,000
Proceeds from issuance of common units, net of issuance related costs	(118		)	51,071
General partner contribution	—			1,098
Purchase of treasury units	(273		)	(4		)
Payment of debt issuance costs	(1,240		)	(40		)
Excess purchase price over carrying value of acquired assets	(26		)	(7,887		)
Reimbursement of excess purchase price over carrying value of acquired assets	—			1,125
Cash distributions paid	(39,217		)	(37,706		)
Net cash used in financing activities	(21,874		)	(21,343		)

Net increase in cash	583			17
Cash at beginning of period	27			15
Cash at end of period	$	610		$	32
Non-cash additions to property, plant and equipment	$	1,811		$	3,666

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, 2018

(Unaudited)

NOTE 1. NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 U.S. 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, 2017, filed with the Securities and Exchange Commission (the "SEC") on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2017 filed on March 29, 2018.

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.

Correction of Immaterial Error. The second quarter and year to date amounts for 2017 have been revised to reflect a reclassification in the presentation of certain expenses associated with the manufacturing and shipping of product related to a location in the Partnership's Terminalling and Storage operating segment. The reclassification resulted in a decrease in operating expenses from $34,435 to $32,552 and an increase in cost of products sold from $119,419 to $121,302 for the three months ended June 30, 2017, and a decrease in operating expenses from $69,492 to $65,926 and an increase in cost of products sold from $278,527 to $282,093 for the six months ended June 30, 2017.

NOTE 2. NEW ACCOUNTING PRONOUNCEMENTS

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 replaced most existing revenue recognition guidance in U.S. GAAP. The 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 adopted the new standard utilizing the cumulative effect method which will result in the cumulative effect of the adoption being recorded as of January 1, 2018. The Partnership adopted ASU 2014-09 on January 1, 2018 and did not identify any significant changes in the timing of revenue recognition when considering the amended accounting guidance. Additional disclosures related to revenue recognition appear in "Note 5. Revenue."

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

NOTE 3. ACQUISITIONS

Acquisition of Terminalling Assets. On February 22, 2017, the Partnership acquired 100% of the membership interests of MEH South Texas Terminals LLC ("MEH"), a subsidiary of Martin Resource Management, for a purchase price of $27,420 (the "Hondo Acquisition"), which was funded with borrowings under the Partnership's revolving credit facility. At the date of acquisition, MEH was in the process of constructing an asphalt terminal facility in Hondo, Texas (the "Hondo Terminal"), to serve the asphalt market in San Antonio, Texas and surrounding areas. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The excess of the purchase price over the carrying value of the assets of $7,887 was recorded as an adjustment to "Partners' capital" during the six months ended June 30, 2017. During 2018, the Partnership paid an additional $26 related to a purchase price true-up, which was recorded as a further adjustment to "Partners' capital" for the six months ended June 30, 2018.



Original purchase price	$	27,420
Purchase price true-up	26
Historical carrying value of assets allocated to "Property, plant and equipment"	19,533
Excess purchase price over carrying value of acquired assets	$	7,913

As no individual line item of the historical financial statements of the acquired assets was in excess of 3% of the Partnership's relative consolidated financial statement captions, the Partnership elected not to retrospectively recast the historical financial information to include these assets.

NOTE 4. DIVESTITURES, ASSET IMPAIRMENTS, AND DISCONTINUED OPERATIONS

Long-Lived Assets Held for Sale

At June 30, 2018 and December 31, 2017, certain terminalling and storage and marine transportation assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the lower of the assets' carrying amount or fair value less cost to sell by segment in current assets as follows:



	June 30, 2018		December 31, 2017

Terminalling and storage	$	4,358	$	4,152
Marine transportation	3,800		5,427
Assets held for sale	$	8,158	$	9,579

These assets are considered non-core assets to the Partnership's operations and did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

NOTE 5. REVENUE

The following table disaggregates our revenue by major source:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Terminalling and storage segment
Lubricant product sales	$	36,824	$	33,413	$	73,304	$	65,560
Throughput and storage	24,090		24,695		48,154		49,353
	$	60,914	$	58,108	$	121,458	$	114,913
Natural gas services segment
Natural gas liquids product sales	$	90,643	$	73,666	$	249,806	$	200,323
Natural gas storage	13,804		14,838		29,160		29,503
	$	104,447	$	88,504	$	278,966	$	229,826
Sulfur service segment
Sulfur product sales	$	10,479	$	11,193	$	22,316	$	24,273
Fertilizer product sales	25,205		20,834		48,268		47,281
Sulfur services	2,787		2,850		5,574		5,700
	$	38,471	$	34,877	$	76,158	$	77,254
Marine transportation segment
Inland transportation	$	11,206	$	11,022	$	20,898	$	22,313
Offshore transportation	1,533		1,411		3,295		2,941
	$	12,739	$	12,433	$	24,193	$	25,254

Revenue is measured based on a consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties where the Partnership is acting as an agent. The Partnership recognizes revenue when the Partnership satisfies a performance obligation, which typically occurs when the Partnership transfers control over a product to a customer or as the Partnership delivers a service.

The following is a description of the principal activities - separated by reportable segments - from which the Partnership generates revenue.

Terminalling and Storage Segment

Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate. For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck or rail, revenue is recognized when title is transfered, which is either upon delivering product to the customer or when the product leaves the Partnership's facility, depending on the specific terms of the contract. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

Natural Gas Services Segment

Natural Gas Liquids ("NGL") distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Natural gas storage revenue is recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

Sulfur Services Segment

Revenue from sulfur product sales is recognized when the customer takes title to the product. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Revenue from sulfur services is recognized as services are performed during each monthly period. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

Marine Transportation Segment

Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

The table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied at the end of the reporting period. The Partnership applies the practical expedient in ASC 606-10-50-14(a) and does not disclose information about remaining performance obligations that have original expected durations of one year or less.



	2018		2019		2020		2021		2022		Thereafter		Total
Terminalling and storage
Storage and throughput	$	25,119	$	50,629	$	49,330	$	46,022	$	41,505	$	393,700	$	606,305
Natural gas services
Natural gas storage	$	19,141	$	32,703	$	26,935	$	25,134	$	24,615	$	10,107	$	138,635
Sulfur services
Sulfur product sales	$	8,398	$	16,796	$	4,898	$	1,181	$	295	$	—	$	31,568
Marine transportation
Offshore transportation	$	3,128	$	6,205	$	6,069	$	—	$	—	$	—	$	15,402
Total	$	55,786	$	106,333	$	87,232	$	72,337	$	66,415	$	403,807	$	791,910

NOTE 6. INVENTORIES

Components of inventories at June 30, 2018 and December 31, 2017 were as follows:



	June 30, 2018		December 31, 2017
Natural gas liquids	$	60,176	$	47,462
Sulfur	14,542		8,436
Sulfur based products	12,108		18,674
Lubricants	23,488		20,086
Other	2,786		2,594
	$	113,100	$	97,252

NOTE 7. INVESTMENT IN WEST TEXAS LPG PIPELINE L.P.

The Partnership owns a 19.8% limited partnership and 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). A wholly-owned subsidiary of ONEOK, Inc. is the operator of the assets. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that primarily 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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

Selected financial information for WTLPG is as follows:



	As of June 30,						Three Months Ended June 30,				Six Months Ended June 30,
	Total Assets		Long-Term Debt		Members' Equity		Revenues		Net Income		Revenues		Net Income
2018
WTLPG	$	917,441	$	—	$	868,112	$	23,390	$	5,653	$	46,431	$	13,359
	As of December 31,
2017
WTLPG	$	837,163	$	—	$	787,426	$	21,420	$	4,264	$	41,139	$	8,789

NOTE 8. LONG-TERM DEBT

At June 30, 2018 and December 31, 2017, long-term debt consisted of the following:



	June 30, 2018		December 31, 2017
$664,444 Revolving credit facility at variable interest rate (5.09%¹ weighted average at June 30, 2018), 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 $4,879 and $4,986, respectively^2,3	$	459,121	$	440,014
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $1,796 and $2,138, respectively, including unamortized premium of $803 and $956, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured^3,4	372,807		372,618
Total long-term debt, net	$	831,928	$	812,632

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, 2018 and December 31, 2017 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, 2018 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.

²On February 21, 2018, the Partnership amended its revolving credit facility to, among other things, (i) create an inventory financing sublimit tranche, which is a part of and not in addition to the already existing commitments under the revolving credit facility, under which availability is subject to a borrowing base calculated by reference to eligible petroleum products inventory, (ii) exclude the amount of loans under the inventory financing sublimit tranche from total outstanding indebtedness for purposes of determining leverage ratio covenants under the revolving credit facility, (iii) increase the maximum permitted leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 5.25 to 1.00, with a temporary springing provision to 5.50 to 1.00 under certain scenarios, to 5.75 to 1.00 for the first and second quarters of 2018, 5.50 to 1.00 for the next three quarters and 5.25 to 1.00, with the temporary springing provision to 5.50 to 1.00 going back into effect, thereafter and (iv) decrease the maximum permitted senior leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 3.50 to 1.00 to 3.25 to 1.00. The maximum amount of the inventory financing sublimit tranche is $10,000 during the period between March 1 and June 30 of each year, and $75,000 at all

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

other times during each year.

³ The Partnership is in compliance with all debt covenants as of June 30, 2018 and December 31, 2017, respectively.

⁴The 2021 indenture restricts the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets.

The Partnership paid cash interest, net of capitalized interest, in the amount of $6,077 and $4,328 for the three months ended June 30, 2018 and 2017, respectively. The Partnership paid cash interest, net of capitalized interest, in the amount of $24,955 and $22,509 for the six months ended June 30, 2018 and 2017, respectively. Capitalized interest was $167 and $222 for the three months ended June 30, 2018 and 2017, respectively. Capitalized interest was $328 and $445 for the six months ended June 30, 2018 and 2017, respectively.

NOTE 9. SUPPLEMENTAL BALANCE SHEET INFORMATION

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



	June 30, 2018		December 31, 2017
Customer contracts and relationships, net	$	21,730	$	25,252
Other intangible assets	1,506		1,752
Other	4,966		5,797
	$	28,202	$	32,801

Accumulated amortization of intangible assets was $44,425 and $39,462 at June 30, 2018 and December 31, 2017, respectively.

Components of "Other accrued liabilities" were as follows:



	June 30, 2018		December 31, 2017
Accrued interest	$	11,985	$	11,726
Asset retirement obligations	3,374		5,429
Property and other taxes payable	5,310		5,638
Accrued payroll	2,419		3,385
Other	5		162
	$	23,093	$	26,340

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

The schedule below summarizes the changes in our asset retirement obligations:



	June 30, 2018


Beginning asset retirement obligations	$	13,512
Revisions to existing liabilities¹	4,756
Accretion expense	261
Liabilities settled	(4,670		)
Ending asset retirement obligations	13,859
Current portion of asset retirement obligations²	(3,374		)
Long-term portion of asset retirement obligations³	$	10,485

¹Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets.

²The current portion of asset retirement obligations is included in "Other current liabilities" on the Partnership's Consolidated and Condensed Balance Sheets.

³The non-current portion of asset retirement obligations is included in "Other long-term obligations" on the Partnership's Consolidated and Condensed Balance Sheets.

NOTE 10. 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 derivatives and hedging instruments are non-hedge derivatives and are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized as gains and losses in 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, 2018 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 gross notional quantity of 360 barrels settling during the period from October 1, 2018 through December 31, 2018. At December 31, 2017, the Partnership had instruments totaling a gross notional quantity of 145 barrels settling during the period from January 31, 2018 through February 28, 2018. These instruments settle against the applicable pricing source for each grade and location.

(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. From time to time, the Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

facility and its fixed rate senior unsecured notes. At June 30, 2018 and 2017, the Partnership did not have any outstanding interest rate derivative instruments.

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 and Condensed Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	June 30, 2018		December 31, 2017		Balance Sheet Location	June 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	572	$	72
Total derivatives not designated as hedging instruments		$	—	$	—		$	572	$	72

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

For the Three Months Ended June 30, 2018 and 2017



	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2018			2017
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	(401	)	$	103
Total effect of derivatives not designated as hedging instruments		$	(401	)	$	103

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

For the Six Months Ended June 30, 2018 and 2017



	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2018		2017
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	2,069	$	(2,392	)
Total effect of derivatives not designated as hedging instruments		$	2,069	$	(2,392	)

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

NOTE 11. PARTNERS' CAPITAL

As of June 30, 2018, Partners’ capital consisted of 39,052,237 common limited partner units, representing a 98% partnership interest, and a 2% general partner interest. Martin Resource Management, through subsidiaries, owns 6,114,532 of the Partnership's common limited partner units representing approximately 15.7% 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.

Issuance of Common Units

On February 22, 2017, the Partnership completed a public offering of 2,990,000 common units at a price of $18.00 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,990,000 common units, net of underwriters' discounts, commissions and offering expenses, were $51,071. Additionally, the Partnership's general partner contributed $1,098 in cash to the Partnership in conjunction with the issuance in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.

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 no incentive distributions during the three or six months ended June 30, 2018 and 2017.

The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions from the minimum of $0.50 per unit up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit.

Distributions of Available Cash

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

Net Income per Unit

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Net income (loss)	$	(7,246	)	$	989		$	5,572		$	14,572
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—			—			—			—
Distributions payable on behalf of general partner interest	392			393			784			785
General partner interest in undistributed loss	(537		)	(374		)	(673		)	(494		)
Less income (loss) allocable to unvested restricted units	(6		)	3			2			38
Limited partners’ interest in net income (loss)	$	(7,095	)	$	967		$	5,459		$	14,243

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,
	2018	2017	2018	2017
Basic weighted average limited partner units outstanding	38,722,037	38,357,293	38,828,845	37,842,140
Dilutive effect of restricted units issued	—	56,618	5,576	52,476
Total weighted average limited partner diluted units outstanding	38,722,037	38,413,911	38,834,421	37,894,616

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, 2018 because the limited partners were allocated a net loss in this period.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

NOTE 12. 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,
	2018		2017		2018		2017
Employees	$	345	$	182	$	441	$	341
Non-employee directors	43		37		79		64
Total unit-based compensation expense	$	388	$	219	$	520	$	405

All of the Partnership's outstanding awards at June 30, 2018 met the criteria to be treated under equity classification.

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.

On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the "2017 LTIP"). The plan currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The plan is administered by the compensation committee of the general partner’s board of directors (the "Compensation Committee").

A restricted unit is a unit that is granted to grantees with certain vesting restrictions, which may be time-based and/or performance-based. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. The Compensation Committee may determine to make grants under the plan containing such terms as the Compensation Committee shall determine under the plan. With respect to time-based restricted units ("TBRU's"), the Compensation Committee will determine the time period over which restricted units granted to employees and directors will vest. The Compensation Committee may also award a percentage of restricted units with vesting requirements based upon the achievement of specified pre-established performance targets ("Performance Based Restricted Units" or "PBRU's"). The performance targets may include, but are not limited to, the following: revenue and income measures, cash flow measures, net income before interest expense and income tax expense ("EBIT"), net income before interest expense, income tax expense, and depreciation and amortization ("EBITDA"), distribution coverage metrics, expense measures, liquidity measures, market measures, corporate sustainability metrics, and other measures related to acquisitions, dispositions, operational objectives and succession planning objectives. PBRU's are earned only upon our achievement of an objective performance measure for the performance period. PBRU's which vest are payable in common units. Unvested units granted under the 2017 LTIP may or may not participate in cash distributions depending on the terms of each individual award agreement.

The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally vest in equal annual installments over three years of service.

On February 20, 2018, the Partnership issued 4,650 TBRU's to each of the Partnership's three independent directors under the 2017 LTIP. These restricted common units vest in equal installments of 1,162.5 units on January 24, 2019, 2020, 2021, and 2022.

On March 1, 2018, the Partnership issued 301,550 TBRU's and 317,925 PBRU's to certain employees of Martin Resource Management. The TBRU's vest in equal installments over a three-year service period. The PBRU's will vest at the conclusion of a three-performance period based on certain performance targets. In addition, the PBRU's awarded on March 1, 2018 that are achieved will only vest if the grantee is employed by Martin Resource Management on March 31, 2021. As of June 30, 2018, the Partnership is unable to ascertain if the performance conditions will be achieved and, as such, has not

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

recognized compensation expense for the vesting of the units. The Partnership will record compensation expense for the vested portion of the units once the achievement of the performance condition is deemed probable.

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, 2018 is provided below:



	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	98,750			$	24.80
Granted (TBRU)	315,500			$	13.89
Granted (PBRU)	317,925			$	13.89
Vested	(80,550		)	$	27.71
Forfeited	(7,000		)	$	13.90
Non-Vested, end of period	644,625			$	13.91

Aggregate intrinsic value, end of period	$	8,896

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, 2018 and 2017 is provided below:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Aggregate intrinsic value of units vested	$	—	$	10	$	1,188	$	135
Fair value of units vested	—		20		2,232		190

As of June 30, 2018, there was $4,052 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.84 years.

NOTE 13. RELATED PARTY TRANSACTIONS

As of June 30, 2018, Martin Resource Management owns 6,114,532 of the Partnership’s common units representing approximately 15.7% 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, 2018, of approximately 15.7% 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:

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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

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, marine fuel and other liquids;


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


◦	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; and


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


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

•

any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 or more if the Partnership has been offered the opportunity to purchase the business for fair market value and the Partnership declines to do so with the concurrence of the conflicts committee of the board of directors of the general partner of the Partnership (the "Conflicts Committee"); and

•

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

Services. Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

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, 2018, through December 31, 2018, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $16,416. The Partnership reimbursed Martin Resource Management for $4,104 and $4,104 of indirect expenses for the three months ended June 30, 2018 and 2017, respectively. The Partnership reimbursed Martin Resource Management for $8,208 and $8,208 of indirect expenses for the six months ended June 30, 2018 and 2017, 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.

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.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

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 second amended and restated terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution. At such time, the per gallon throughput fee the Partnership charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index. This agreement was further amended on January 1, 2017 and October 1, 2017 to modify its minimum throughput requirements and throughput fees. This agreement, as amended, continues until September 30, 2018 and thereafter on a month to month basis until terminated by either party by giving 60 days’ written notice.

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

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

Sulfuric Acid Sales Agency Agreement. The Partnership was previously a party to a third amended and restated sulfuric acid sales agency agreement dated August 2, 2017 but effective October 1, 2017, under which a successor in interest to the agreement from Martin Resource Management, Saconix LLC ("Saconix"), a limited liability company in which Martin Resource Management held a minority equity interest, purchased and marketed the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that was not consumed by the Partnership’s internal operations. This

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

agreement, as amended, was to remain in place until September 30, 2020 and automatically renew year to year thereafter until either party provided 90 days’ written notice of termination prior to the expiration of the then existing term. Under this agreement, the Partnership sold all of its excess sulfuric acid to Saconix, who then marketed and sold such acid to third-parties. The Partnership shared in the profit of such sales. Effective May 31, 2018, Martin Resource Management no longer holds an equity interest in Saconix. These transactions are reported below as related party transactions during the period the equity interest was held. Transactions subsequent to Martin Resource Managements disposition of the equity interest will be reported as third party transactions.

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,
	2018		2017		2018		2017
Revenues:
Terminalling and storage	$	20,507	$	20,331	$	40,532	$	40,035
Marine transportation	4,105		4,187		7,718		8,512
Natural gas services	—		6		—		118
Product sales:
Natural gas services	18		—		19		942
Sulfur services	226		587		612		1,018
Terminalling and storage	182		137		437		194
	426		724		1,068		2,154
	$	25,038	$	25,248	$	49,318	$	50,819

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,
	2018		2017		2018		2017
Cost of products sold:
Natural gas services	$	3,099	$	2,909	$	7,417	$	11,803
Sulfur services	4,345		3,767		8,871		7,442
Terminalling and storage	8,009		4,119		14,567		9,186
	$	15,453	$	10,795	$	30,855	$	28,431

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(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,
	2018		2017		2018		2017
Operating expenses:
Marine transportation	$	6,000	$	6,067	$	11,321	$	12,063
Natural gas services	2,232		2,233		4,431		4,468
Sulfur services	1,492		1,534		2,831		2,980
Terminalling and storage	4,615		6,618		9,140		13,317
	$	14,339	$	16,452	$	27,723	$	32,828

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,
	2018		2017		2018		2017
Selling, general and administrative:
Marine transportation	$	7	$	7	$	15	$	15
Natural gas services	1,025		1,202		3,279		3,479
Sulfur services	660		621		1,319		1,257
Terminalling and storage	690		566		1,371		1,109
Indirect, including overhead allocation	4,116		4,104		8,235		8,208
	$	6,498	$	6,500	$	14,219	$	14,068

Other Related Party Transactions

The Partnership had a $15,000 note receivable from an affiliate of Martin Resource Management which previously bore an annual interest rate of 15% and had a maturity date of August 31, 2026, the balance of which could be prepaid on or after September 1, 2016. On February 14, 2017, the Partnership notified Martin Resource Management that it would be requesting voluntary repayment of the long-term Note Receivable plus accrued interest. During second quarter of 2017, the Note Receivable was fully repaid. The note has historically been recorded in "Note receivable - affiliates" on the Partnership's Consolidated and Condensed Balance Sheets. Interest income for the three months ended June 30, 2018 and 2017 was $0 and $388, 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, 2018 and 2017 was $0 and $943, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.

NOTE 14. BUSINESS SEGMENTS

The Partnership has four reportable segments: natural gas services, terminalling and storage, 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, 2017, filed with the SEC on February 16, 2018, as amended, by Amendment No. 1 on Form 10-K/A filed on March 29, 2018. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)



Three Months Ended June 30, 2018	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	$	62,314	$	(1,400	)	$	60,914	$	11,690	$	1,739		$	2,471
Natural gas services	104,447		—			104,447		5,304		3,727			2,043
Sulfur services	38,471		—			38,471		2,086		3,048			966
Marine transportation	13,168		(429		)	12,739		1,811		1,353			2,827
Indirect selling, general and administrative	—		—			—		—		(4,346		)	—
Total	$	218,400	$	(1,829	)	$	216,571	$	20,891	$	5,521		$	8,307



Three Months Ended June 30, 2017	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	$	59,561	$	(1,453	)	$	58,108	$	10,327	$	3,252		$	8,634
Natural gas services	88,504		—			88,504		6,205		4,424			4,383
Sulfur services	34,877		—			34,877		2,030		6,295			862
Marine transportation	13,144		(711		)	12,433		1,764		1,149			1
Indirect selling, general and administrative	—		—			—		—		(4,272		)	—
Total	$	196,086	$	(2,164	)	$	193,922	$	20,326	$	10,848		$	13,880



Six Months Ended June 30, 2018	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	$	124,297	$	(2,839	)	$	121,458	$	21,849	$	4,461		$	4,592
Natural gas services	278,966		—			278,966		10,605		21,138			3,052
Sulfur services	76,158		—			76,158		4,150		10,040			2,514
Marine transportation	25,196		(1,003		)	24,193		3,497		2,516			11,118
Indirect selling, general and administrative	—		—			—		—		(8,577		)	—
Total	$	504,617	$	(3,842	)	$	500,775	$	40,101	$	29,578		$	21,276



Six Months Ended June 30, 2017	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	$	118,139	$	(3,226	)	$	114,913	$	25,804	$	1,151		$	16,097
Natural gas services	229,826		—			229,826		12,366		22,697			5,235
Sulfur services	77,254		—			77,254		4,063		17,062			1,167
Marine transportation	26,558		(1,304		)	25,254		3,429		2,378			695
Indirect selling, general and administrative	—		—			—		—		(8,692		)	—
Total	$	451,777	$	(4,530	)	$	447,247	$	45,662	$	34,596		$	23,194

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

The Partnership's assets by reportable segment as of June 30, 2018 and December 31, 2017, are as follows:



	June 30, 2018		December 31, 2017
Total assets:
Terminalling and storage	$	319,619	$	326,920
Natural gas services	669,531		704,524
Sulfur services	121,452		120,790
Marine transportation	108,163		101,264
Total assets	$	1,218,765	$	1,253,498

NOTE 15. COMMITTMENTS AND CONTINGENCIES

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 has reimbursed the Partnership $750 per quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests. These payments were the result of Cardinal Gas Storage Partners LLC ("Cardinal") not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement. These payments were considered to be 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 were recorded as an adjustment to "Partners' capital" in each quarter in which the payments were made. The agreement further provided for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions were not met. For the six months ended June 30, 2017, the Partnership received $1,125, related to the Purchase Price Reimbursement Agreement. The amount received in the first quarter of 2017 represented the final payment under the Purchase Price Reimbursement Agreement.

Certain shippers filed complaints with the Railroad Commission of Texas ("RRC") challenging the increased rates WTLPG implemented effective July 1, 2015. The complainants requested 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." A hearing on the merits was held in front of a hearings examiner during the week of March 27, 2017. The hearings examiner issued a Proposal for Decision on September 29, 2017. On December 5, 2017, this matter was brought before the RRC. After brief discussion, the RRC determined that more time was needed to review the proposal for decision and placed the matter on the agenda for the RRC’s January 23, 2018 meeting. At that meeting, the RRC voted to remand the case to the hearings examiner for the limited purpose of admitting and considering additional relevant evidence on competition. The remand hearing is currently scheduled for the week of October 29th of 2018.

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 alleged that the Partnership breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement. The plaintiff originally sought to evict the Partnership from the leased property and to recover damages. Prior to trial, this matter was settled for a confidential amount in September of 2017. The Partnership's financial statements reflect the terms of the settlement and all amounts have been accrued as asset retirement obligations.

On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with lawsuits filed against it in various 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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

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. The lawsuits against the customer have been transferred to the United States District Court for the Western District of Missouri for consolidated pretrial proceedings. On March 1, 2017, at the request of the parties, the Chancery Court of Davidson County, Tennessee administratively closed the Partnership's lawsuit pending rulings in the United States District Court for the Western District of Missouri. In the event that either party moves the Chancery Court of Davidson County, Tennessee to reopen the case, we expect the Court would grant such motion and reopen the case. If the case is reopened, we are currently unable to determine the exposure we may have in this matter, if any.

Commitments

The Partnership has non-cancelable revenue arrangements that are not under the scope of ASC 606 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues the Partnership expects to receive under these non-cancelable arrangements as of June 30, 2018, are as follows: 2018 - $11,691; 2019 - $19,315; 2020 - $17,577; 2021 - $15,681; 2022 - $15,681; subsequent years - $73,299.

NOTE 16. 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, 2018			December 31, 2017
Commodity derivative contracts, net	$	(572	)	$	(72	)

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:

•

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: 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 considered Level 1, as the fair value is based on quoted market prices in active markets.



	June 30, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
2021 Senior unsecured notes	$	372,807	$	370,245	$	372,618	$	381,657

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2018

(Unaudited)

NOTE 17. CONDENSED CONSOLIDATED 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.

NOTE 18. SUBSEQUENT EVENTS

Quarterly Distribution. On July 19, 2018, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the second quarter of 2018, or $2.00 per common unit on an annualized basis, which will be paid on August 14, 2018 to unitholders of record as of August 7, 2018.

Divestiture of WTLPG Partnership Interest. The Partnership has entered into a definitive agreement with ONEOK, Inc. to sell its 20 percent non-operating partnership interest in WTLPG for $195,000. The Partnership expects to receive net proceeds of approximately $193,650 after transaction fees and expenses. The proceeds from the sale will be used to reduce outstanding borrowings under the Partnership’s revolving credit facility. In conjunction with the proposed sale of West Texas LPG Pipeline, subject to completion of the sale, the Partnership has amended its revolving credit facility which will include, among other things, a revision to the Partnership's existing leverage covenants under its revolving credit facility. Total Indebtedness to EBITDA and Senior Secured Indebtedness to EBITDA (each as defined in the credit agreement) will be amended to 5.25 times and 3.50 times, respectively. No changes to the Consolidated Interest Coverage Ratio (as defined in the credit agreement) of 2.50 times are contemplated.



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, 2017, filed with the Securities and Exchange Commission (the "SEC") on February 16, 2018, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2017 filed on March 29, 2018, 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:


•	Natural gas 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 and the blending and packaging of finished lubricants;


•	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, 2018, Martin Resource Management owned 15.7% 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.

Significant Recent Developments

Credit Facility Amendment. On February 21, 2018, we amended our revolving credit facility in order to achieve two primary objectives, the first of which was to accommodate growth capital expenditures necessary for the previously announced WTLPG expansion project which is discussed in further detail below. Starting in the first quarter of 2018, the amendment will provide short-term (5 quarters) covenant relief by increasing the total leverage ratio to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginning in the second quarter of 2019. Additionally, the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part of and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90% of the value of forward sold/hedged inventory.

West Texas LPG Pipeline Limited Partnership Expansion. On October 23, 2017, we announced that the West Texas LPG Pipeline Limited Partnership ("WTLPG") joint venture (of which we own a 20% interest with ONEOK, Inc. owning and operating the other 80% interest) plans to invest approximately $200.0 million to expand its Natural Gas Liquids ("NGL") system into the prolific Delaware Basin, part of the larger Permian Basin and is expected to be in service by the third quarter of 2018. This project is supported by dedicated NGL production from two third-party planned natural gas processing plants in northern Reeves County, one of the most active areas in the Delaware Basin. The expansion will be supported by long-term volume dedications estimated to be up to 40,000 barrels per day. The Delaware Basin extension includes the construction of an approximately 120-mile, 16-inch pipeline lateral that will have an initial capacity of 110,000 bpd and the construction of two new pump stations and pipeline looping along the existing West Texas LPG system that will increase its capacity to handle the dedicated volume.

Subsequent Events

Quarterly Distribution. On July 19, 2018, we declared a quarterly cash distribution of $0.50 per common unit for the second quarter of 2018, or $2.00 per common unit on an annualized basis, which will be paid on August 14, 2018 to unitholders of record as of August 7, 2018.

Divestiture of WTLPG Partnership Interest. We have entered into a definitive agreement with ONEOK, Inc. to sell our 20 percent non-operating partnership interest in the West Texas LPG Pipeline Limited Partnership for $195.0 million. We expect to receive net proceeds of approximately $193.7 million after transaction fees and expenses. The proceeds from the sale will be used to reduce outstanding borrowings under our revolving credit facility. Accordingly our pro-forma leverage is 4.36 times compared to actual leverage of 5.46 times at June 30, 2018. In addition, our forecasted capital expenditures will be reduced by approximately $24.2 million for the remainder of 2018. In conjunction with the proposed sale of the West Texas LPG Pipeline, subject to completion of the sale, we have amended our revolving credit facility which will include, among other things, revising our existing leverage covenants. Total Indebtedness to EBITDA and Senior Secured Indebtedness to EBITDA (each as defined in the credit agreement) will be amended to 5.25 times and 3.50 times, respectively. No changes to the Consolidated Interest Coverage Ratio (as defined in the credit agreement) of 2.50 times are contemplated.

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, 2017. The following table evaluates the potential impact of estimates utilized during the periods ended June 30, 2018 and 2017:



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
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 and six months ended June 30, 2018 or 2017.
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. During the six months ended June 30, 2018, we made upward revisions to our asset retirement obligations in the amount of $4.8 million.

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, marine fuel and other liquids;


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


•	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; and


•	operating, solely for our account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas, Hondo, 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 15.7% 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 $32.2 million of direct costs and expenses for the three months ended June 30, 2018 compared to $29.6 million for the three months ended June 30, 2017. We reimbursed Martin Resource Management for $64.6 million of direct costs and expenses for the six months ended June 30, 2018 compared to $67.1 million for the six months ended June 30, 2017. 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 both the three months ended June 30, 2018 and 2017, the conflicts committee of the board of directors of the general partner of the Partnership (the "Conflicts Committee") approved reimbursement amounts of $4.1 million. For both the six months ended June 30, 2018 and 2017, the Conflicts Committee approved reimbursement amounts of $8.2 million. 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, 2017, filed with the SEC on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018.

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 10% and 9% of our total cost of products sold during the three months ended June 30, 2018 and 2017, respectively. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 9% and 10% of our total cost of products sold during the six months ended June 30, 2018 and 2017, 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 12% and 13% of our total revenues for the three months ended June 30, 2018 and 2017, respectively. Our sales to Martin Resource Management accounted for approximately 10% and 11% of our total revenues for the six months ended June 30, 2018 and 2017, 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, 2017, filed with the SEC on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018.

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, 2018 and 2017.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(in thousands)
Net income (loss)	$	(7,246	)	$	989		$	5,572		$	14,572
Adjustments:
Interest expense, net	13,766			11,219			26,451			22,139
Income tax expense	132			13			281			193
Depreciation and amortization	20,891			20,326			40,101			45,662
EBITDA	27,543			32,547			72,405			82,566
Adjustments:
Equity in earnings of WTLPG	(1,131		)	(853		)	(2,726		)	(1,758		)
(Gain) loss on sale of property, plant and equipment	490			(15		)	492			140
Unrealized mark-to-market on commodity derivatives	654			(200		)	500			(4,037		)
Distributions from WTLPG	1,500			1,300			3,000			2,500
Unit-based compensation	388			219			520			405
Adjusted EBITDA	29,444			32,998			74,191			79,816
Adjustments:
Interest expense, net	(13,766		)	(11,219		)	(26,451		)	(22,139		)
Income tax expense	(132		)	(13		)	(281		)	(193		)
Amortization of debt premium	(76		)	(76		)	(153		)	(153		)
Amortization of deferred debt issuance costs	870			724			1,689			1,445
Payments for plant turnaround costs	—			(197		)	—			(1,591		)
Maintenance capital expenditures	(5,370		)	(2,618		)	(11,372		)	(7,286		)
Distributable Cash Flow	$	10,970		$	19,599		$	37,623		$	49,899

Results of Operations

The results of operations for the three and six months ended June 30, 2018 and 2017 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, 2018 and 2017. 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, 2018 Compared to the Three Months Ended June 30, 2017



	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, 2018	(in thousands)
Terminalling and storage	$	62,314	$	(1,400	)	$	60,914	$	2,749		$	(1,010	)	$	1,739
Natural gas services	104,447		—			104,447		2,975			752			3,727
Sulfur services	38,471		—			38,471		3,597			(549		)	3,048
Marine transportation	13,168		(429		)	12,739		546			807			1,353
Indirect selling, general and administrative	—		—			—		(4,346		)	—			(4,346		)
Total	$	218,400	$	(1,829	)	$	216,571	$	5,521		$	—		$	5,521



	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, 2017
Terminalling and storage	$	59,561	$	(1,453	)	$	58,108	$	4,128		$	(876	)	$	3,252
Natural gas services	88,504		—			88,504		3,619			805			4,424
Sulfur services	34,877		—			34,877		7,126			(831		)	6,295
Marine transportation	13,144		(711		)	12,433		247			902			1,149
Indirect selling, general and administrative	—		—			—		(4,272		)	—			(4,272		)
Total	$	196,086	$	(2,164	)	$	193,922	$	10,848		$	—		$	10,848

Six Months Ended June 30, 2018 Compared to the Six Months Ended June 30, 2017



	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, 2018	(in thousands)
Terminalling and storage	$	124,297	$	(2,839	)	$	121,458	$	6,368		$	(1,907	)	$	4,461
Natural gas services	278,966		—			278,966		19,595			1,543			21,138
Sulfur services	76,158		—			76,158		11,284			(1,244		)	10,040
Marine transportation	25,196		(1,003		)	24,193		908			1,608			2,516
Indirect selling, general and administrative	—		—			—		(8,577		)	—			(8,577		)
Total	$	504,617	$	(3,842	)	$	500,775	$	29,578		$	—		$	29,578



	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, 2017	(in thousands)
Terminalling and storage	$	118,139	$	(3,226	)	$	114,913	$	3,235		$	(2,084	)	$	1,151
Natural gas services	229,826		—			229,826		20,768			1,929			22,697
Sulfur services	77,254		—			77,254		18,606			(1,544		)	17,062
Marine transportation	26,558		(1,304		)	25,254		679			1,699			2,378
Indirect selling, general and administrative	—		—			—		(8,692		)	—			(8,692		)
Total	$	451,777	$	(4,530	)	$	447,247	$	34,596		$	—		$	34,596

Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended June 30, 2018 and 2017



	Three Months Ended June 30,					Variance			Percent Change
	2018			2017		Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	25,491		$	26,148	$	(657	)	(3	)%
Products	36,823			33,413		3,410			10	%
Total revenues	62,314			59,561		2,753			5	%

Cost of products sold	33,596			30,474		3,122			10	%
Operating expenses	12,909			13,198		(289		)	(2	)%
Selling, general and administrative expenses	1,334			1,444		(110		)	(8	)%
Depreciation and amortization	11,690			10,327		1,363			13	%
	2,785			4,118		(1,333		)	(32	)%
Other operating income (loss)	(36		)	10		(46		)	(460	)%
Operating income	$	2,749		$	4,128	$	(1,379	)	(33	)%

Lubricant sales volumes (gallons)	6,408			5,361		1,047			20	%
Shore-based throughput volumes (guaranteed minimum) (gallons)	20,000			41,666		(21,666		)	(52	)%
Smackover refinery throughput volumes (guaranteed minimum BBL per day)	6,500			6,500		—			—	%

Services revenues. Services revenue decreased $0.7 million, of which $2.6 million was primarily a result of decreased throughput fees at our shore-based terminals, offset by a $1.9 million increase primarily as a result of the Hondo asphalt plant being put into service.

Products revenues. A 59% increase in sales volumes offset by a 4% decrease in average sales price at our blending and packaging facilities resulted in an $7.5 million increase to products revenues. Offsetting this increase was a 15% decrease in sales volume combined with an 8% decrease in average sales price at our shore based terminals resulting in a $4.1 million decrease in products revenues.

Cost of products sold. A 59% increase in sales volumes combined with a 6% increase in average price per gallon at our blending and packaging facilities resulted in a $7.3 million increase in cost of products sold. Offsetting this increase was a 15% decrease in sales volume combined with an 8% decrease in average price per gallon at our shore based terminals resulting in a $4.1 million decrease in cost of products sold.

Operating expenses. Operating expenses at our shore-based terminals decreased by $0.6 million, primarily due to lease and other expenses related to facilities closed in 2017. Operating expenses at our specialty terminals increased $0.6 million, primarily as a result of the Hondo asphalt plant being put into service. Operating expenses at our Smackover refinery decreased $0.1 million as a result of decreased compensation expense.

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

Depreciation and amortization. The increase in depreciation and amortization is due to recent capital expenditures, offset by the disposition of assets at several closed shore-based facilities.

Other operating income (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, 2018 and 2017



	Six Months Ended June 30,						Variance			Percent Change
	2018			2017			Variance			Percent Change
	(In thousands, except BBL per day)
Revenues:
Services	$	50,994		$	52,579		$	(1,585	)	(3	)%
Products	73,303			65,560			7,743			12	%
Total revenues	124,297			118,139			6,158			5	%

Cost of products sold	67,098			59,168			7,930			13	%
Operating expenses	26,356			27,160			(804		)	(3	)%
Selling, general and administrative expenses	2,590			2,769			(179		)	(6	)%
Depreciation and amortization	21,849			25,804			(3,955		)	(15	)%
	6,404			3,238			3,166			98	%
Other operating loss	(36		)	(3		)	(33		)	1,100	%
Operating income	$	6,368		$	3,235		$	3,133		97	%

Lubricant sales volumes (gallons)	12,318			10,695			1,623			15	%
Shore-based throughput volumes (guaranteed minimum) (gallons)	20,000			83,332			(63,332		)	(76	)%
Smackover refinery throughput volumes (guaranteed minimum) (BBL per day)	6,500			6,500			—			—	%

Services revenues. Services revenue decreased $1.6 million, of which $5.4 million was primarily a result of decreased throughput fees at our shore-based terminals, offset by a $3.6 million increase primarily as a result of the Hondo asphalt plant being put into service.

Products revenues. A 45% increase in sales volumes offset by a 1% decrease in average sales price at our blending and packaging facilities resulted in an $11.8 million increase to products revenues. Offsetting this increase was a 10% decrease in sales volume at our shore based terminals resulting in a $4.0 million decrease in products revenues.

Cost of products sold. A 45% increase in sales volumes combined with a 10% increase in average price per gallon at our blending and packaging facilities resulted in a $12.1 million increase in cost of products sold. Offsetting this increase was a 10% decrease in sales volume at our shore based terminals resulting in a $4.2 million decrease in cost of products sold.

Operating expenses. Operating expenses at our shore-based terminals decreased by $1.5 million, primarily due to lease and other expenses related to facilities closed in 2017. Operating expenses at our specialty terminals increased $0.7 million, primarily as a result of the Hondo asphalt plant being put into service.

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

Depreciation and amortization. The decrease in depreciation and amortization is due to the disposition of assets at several closed shore-based facilities, offset by recent capital expenditures.

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

Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended June 30, 2018 and 2017



	Three Months Ended June 30,					Variance			Percent Change
	2018			2017		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	13,804		$	14,838	$	(1,034	)	(7	)%
Products	90,643			73,666		16,977			23	%
Total revenues	104,447			88,504		15,943			18	%

Cost of products sold	88,394			71,003		17,391			24	%
Operating expenses	5,895			5,567		328			6	%
Selling, general and administrative expenses	1,759			2,115		(356		)	(17	)%
Depreciation and amortization	5,304			6,205		(901		)	(15	)%
	3,095			3,614		(519		)	(14	)%
Other operating income (loss)	(120		)	5		(125		)	(2,500	)%
Operating income	$	2,975		$	3,619	$	(644	)	(18	)%

Distributions from WTLPG	$	1,500		$	1,300	$	200		15	%

NGL sales volumes (Bbls)	1,743			1,794		(51		)	(3	)%

Services Revenues. The decrease in services revenue is primarily due to lower re-contracting rates at our Arcadia and Perryville gas storage facilities.

Products Revenues. Our average sales price per barrel increased $10.94, or 27%, resulting in an increase to products revenues of $19.6 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes decreased 3%, decreasing products revenues by $2.6 million.

Cost of products sold. Our average cost per barrel increased $11.14, or 28%, increasing cost of products sold by $20.0 million. The increase in average cost per barrel was a result of an increase in market prices. The decrease in sales volume of 3% resulted in a $2.6 million decrease to cost of products sold. Our margins decreased $0.19 per barrel, or 13%, during the period.

Operating expenses. Operating expenses increased $0.3 million at our natural gas storage facilities, primarily due to increased insurance related expenses of $0.2 million, a $0.2 million increase in repairs and maintenance, and $0.1 million in increased utility expense. These increases are offset by a $0.2 million decrease in property tax expense.

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

Depreciation and amortization. Depreciation and amortization decreased $0.9 million primarily due to decreases in amortization related to contracts acquired as part of the purchase of Cardinal Gas Storage Partners LLC ("Cardinal").

Other operating income (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, 2018 and 2017



	Six Months Ended June 30,					Variance			Percent Change
	2018			2017		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	29,160		$	29,503	$	(343	)	(1	)%
Products	249,806			200,323		49,483			25	%
Total revenues	278,966			229,826		49,140			21	%

Cost of products sold	232,142			180,306		51,836			29	%
Operating expenses	11,675			11,225		450			4	%
Selling, general and administrative expenses	4,829			5,166		(337		)	(7	)%
Depreciation and amortization	10,605			12,366		(1,761		)	(14	)%
	19,715			20,763		(1,048		)	(5	)%
Other operating income (loss)	(120		)	5		(125		)	(2,500	)%
Operating income	$	19,595		$	20,768	$	(1,173	)	(6	)%

Distributions from WTLPG	$	3,000		$	2,500	$	500		20	%

NGL sales volumes (Bbls)	5,184			4,604		580			13	%

Services Revenues. The decrease in services revenue is primarily due to $1.4 million in lower firm storage re-contracting rates at our natural gas storage facilities, offset by $0.5 million in fuel revenue, $0.4 million in firm wheeling revenue and $0.3 million in injection fee revenue.

Products Revenues. Our average sales price per barrel increased $4.68, or 11%, resulting in an increase to products revenues of $21.5 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes increased 13%, increasing products revenues by $28.0 million.

Cost of products sold. Our average cost per barrel increased $5.62, or 14%, increasing cost of products sold by $25.8 million. The increase in average cost per barrel was a result of an increase in market prices. The increase in sales volume of 13% resulted in a $26.0 million increase to cost of products sold. Our margins decreased $0.94 per barrel, or 22%, during the period.

Operating expenses. Operating expenses increased $0.5 million at our natural gas storage facilities, primarily as a result of an increase of $0.2 million in insurance related expenses and $0.2 million in increased utility expense.

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

Depreciation and amortization. Depreciation and amortization decreased $1.8 million primarily due to a decrease in amortization related to contracts acquired as part of the purchase of Cardinal Gas Storage.

Other operating income (loss). Other operating income (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, 2018 and 2017



	Three Months Ended June 30,				Variance			Percent Change
	2018		2017		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	2,787	$	2,850	$	(63	)	(2	)%
Products	35,684		32,027		3,657			11	%
Total revenues	38,471		34,877		3,594			10	%

Cost of products sold	28,829		21,297		7,532			35	%
Operating expenses	2,929		3,417		(488		)	(14	)%
Selling, general and administrative expenses	1,046		1,007		39			4	%
Depreciation and amortization	2,086		2,030		56			3	%
	3,581		7,126		(3,545		)	(50	)%
Other operating income	16		—		16
Operating income	$	3,597	$	7,126	$	(3,529	)	(50	)%

Sulfur (long tons)	178		192		(14		)	(7	)%
Fertilizer (long tons)	93		71		22			31	%
Total sulfur services volumes (long tons)	271		263		8			3	%

Services revenues. Services revenues remained relatively consistent.

Products revenues. Products revenues increased $2.6 million as a result of an 8% increase in average sales price. A 3% increase in sales volumes, primarily attributable to a 31% increase in fertilizer volumes, resulted in an additional $1.1 million increase.

Cost of products sold. A 31% increase in average cost of products sold per ton increased cost of products sold by $6.6 million, which included a one-time negative inventory adjustment of $3.9 million as a result of the implementation of three-dimensional (3D) stockpile measurement scanning technology. Margin per ton decreased $15.50, or 38%. A 3% increase in sales volumes caused an additional increase to cost of products sold of $0.9 million.

Operating expenses. Our operating expenses decreased primarily as a result of a $0.3 million reduction in compensation expense, $0.1 million in lower property taxes, and a $0.1 million reduction in repairs and maintenance of marine vessels and railcars. An additional decrease of $0.1 million is due to a reduction in leases and outside towing. An offsetting increase of $0.2 million resulted from an increase in marine fuel and lube.

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

Depreciation and amortization. Depreciation and amortization remained relatively consistent.

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

Comparative Results of Operations for the Six Months Ended June 30, 2018 and 2017



	Six Months Ended June 30,					Variance			Percent Change
	2018		2017			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	5,574	$	5,700		$	(126	)	(2	)%
Products	70,584		71,554			(970		)	(1	)%
Total revenues	76,158		77,254			(1,096		)	(1	)%

Cost of products sold	52,816		45,871			6,945			15	%
Operating expenses	5,841		6,664			(823		)	(12	)%
Selling, general and administrative expenses	2,081		2,028			53			3	%
Depreciation and amortization	4,150		4,063			87			2	%
	11,270		18,628			(7,358		)	(39	)%
Other operating income (loss)	14		(22		)	36			(164	)%
Operating income	$	11,284	$	18,606		$	(7,322	)	(39	)%

Sulfur (long tons)	354		409			(55		)	(13	)%
Fertilizer (long tons)	181		165			16			10	%
Total sulfur services volumes (long tons)	535		574			(39		)	(7	)%

Services revenues. Services revenues remained relatively consistent.

Products revenues. Products revenue decreased $5.2 million as a result of a 7% decline in sales volumes, primarily attributable to a 13% decrease in sulfur volumes. A 6% increase in average sales price resulted in an offsetting increase of $4.2 million.

Cost of products sold. A 24% increase in average cost of products sold per ton increased cost of products sold by $10.8 million., which included a one-time negative inventory adjustment of $2.9 million as a result of the implementation of three-dimensional (3D) stockpile measurement scanning technology. Margin per ton decreased $11.53, or 26%. A 7% decrease in sales volumes caused an offsetting reduction to cost of products sold of $3.9 million.

Operating expenses. Our operating expenses decreased primarily as a result of a $0.7 million reduction in compensation expense and $0.2 million in lower property taxes. An additional decrease of $0.2 million is due to a reduction in leases and utilities. An offsetting increase of $0.2 million resulted from an increase in marine fuel and lube and $0.1 million due to an increase in other marine operating expense.

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

Depreciation and amortization. Depreciation and amortization remained relatively consistent.

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

Marine Transportation Segment

Comparative Results of Operations for the Three Months Ended June 30, 2018 and 2017



	Three Months Ended June 30,					Variance			Percent Change
	2018			2017		Variance			Percent Change
	(In thousands)
Revenues	$	13,168		$	13,144	$	24		—	%
Operating expenses	10,374			11,062		(688		)	(6	)%
Selling, general and administrative expenses	87			71		16			23	%
Depreciation and amortization	1,811			1,764		47			3	%
	896			247		649			263	%
Other operating loss	(350		)	—		(350		)
Operating income	$	546		$	247	$	299		121	%

Inland revenues. A decrease of $0.5 million attributable to decreased utilization of the inland fleet resulting from regulatory downtime. This decrease was offset by an increase in pass-through revenue (primarily fuel) of $0.4 million.

Operating expenses. The decrease in operating expenses is primarily a result of decreased compensation expense of $0.3 million, lease expense of $0.3 million, repairs and maintenance of $0.4 million, and outside towing of $0.1 million. These decreases were offset by an increase in pass through expenses (primarily fuel) of $0.5 million.

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

Depreciation and amortization. Depreciation and amortization remained relatively consistent.

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

Comparative Results of Operations for the Six Months Ended June 30, 2018 and 2017



	Six Months Ended June 30,						Variance			Percent Change
	2018			2017			Variance			Percent Change
	(In thousands)
Revenues	$	25,196		$	26,558		$	(1,362	)	(5	)%
Operating expenses	20,278			22,155			(1,877		)	(8	)%
Selling, general and administrative expenses	163			175			(12		)	(7	)%
Depreciation and amortization	3,497			3,429			68			2	%
	$	1,258		$	799		$	459		57	%
Other operating loss	(350		)	(120		)	(230		)	192	%
Operating income	$	908		$	679		$	229		34	%

Inland revenues. A decrease of $2.4 million is attributable to decreased utilization of the inland fleet resulting from regulatory downtime. This decrease was offset by an increase in pass-through revenue (primarily fuel) of $0.8 million.

Operating expenses. The decrease in operating expenses is primarily a result of decreased compensation expense of $1.0 million, lease expense of $0.6 million, repairs and maintenance of $0.6 million, outside towing of $0.2 million, and insurance related costs of $0.1 million. These decreases were offset by an increase in pass through expenses (primarily fuel) of $0.8 million.

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

Depreciation and amortization. Depreciation and amortization remained relatively consistent.

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

Equity in Earnings in and Distributions from WTLPG

Comparative Results for the Three Months Ended June 30, 2018 and 2017



	Three Months Ended June 30,				Variance		Percent Change
	2018		2017		Variance		Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	1,131	$	853	$	278	33	%



	Three Months Ended June 30,				Variance		Percent Change
	2018		2017		Variance		Percent Change
	(In thousands)
Distributions from WTLPG	$	1,500	$	1,300	$	200	15	%

Equity in earnings from West Texas LPG Pipeline L.P. ("WTLPG") increased as a result of both higher volumes and increased transportation rates as well as a decrease in property taxes. Offsetting this was an increase in pipeline lease expense and repairs and maintenance. Distributions from WTLPG increased $0.2 million.

Comparative Results for the Six Months Ended June 30, 2018 and 2017



	Six Months Ended June 30,				Variance		Percent Change
	2018		2017		Variance		Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	2,726	$	1,758	$	968	55	%



	Six Months Ended June 30,				Variance		Percent Change
	2018		2017		Variance		Percent Change
	(In thousands)
Distributions from WTLPG	$	3,000	$	2,500	$	500	20	%

Equity in earnings from WTLPG increased as a result of both higher volumes and increased transportation rates offset by an increase in pipeline lease expense and fuel and power expense. Distributions from WTLPG increased $0.5 million.

Interest Expense, Net

Comparative Components of Interest Expense, Net for the Three Months Ended June 30, 2018 and 2017



	Three Months Ended June 30,						Variance		Percent Change
	2018			2017			Variance		Percent Change
	(In thousands)
Revolving loan facility	$	5,867		$	3,954		$	1,913	48	%
7.25% Senior notes	6,850			6,850			—		—	%
Amortization of deferred debt issuance costs	870			724			146		20	%
Amortization of debt discount	(76		)	(76		)	—		—	%
Other	422			377			45		12	%
Capitalized interest	(167		)	(222		)	55		(25	)%
Interest income	—			(388		)	388		(100	)%
Total interest expense, net	$	13,766		$	11,219		$	2,547	23	%

Comparative Components of Interest Expense, Net for the Six Months Ended June 30, 2018 and 2017



	Six Months Ended June 30,						Variance		Percent Change
	2018			2017			Variance		Percent Change
	(In thousands)
Revolving loan facility	$	10,977		$	8,099		$	2,878	36	%
7.25% Senior notes	13,324			13,324			—		—	%
Amortization of deferred debt issuance costs	1,689			1,445			244		17	%
Amortization of debt premium	(153		)	(153		)	—		—	%
Other	942			812			130		16	%
Capitalized interest	(328		)	(445		)	117		(26	)%
Interest income	—			(943		)	943		(100	)%
Total interest expense, net	$	26,451		$	22,139		$	4,312	19	%

Indirect Selling, General and Administrative Expenses



	Three Months Ended June 30,				Variance		Percent Change		Six Months Ended June 30,				Variance			Percent Change
	2018		2017		Variance		Percent Change		2018		2017		Variance			Percent Change
	(In thousands)								(In thousands)
Indirect selling, general and administrative expenses	$	4,346	$	4,272	$	74	2	%	$	8,577	$	8,692	$	(115	)	(1	)%

Indirect selling, general and administrative expenses remained consistent for both the three and six months ended June 30, 2018 compared to the three and six months ended June 30, 2017, respectively.

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 six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,				Variance		Percent Change		Six Months Ended June 30,				Variance		Percent Change
	2018		2017		Variance		Percent Change		2018		2017		Variance		Percent Change
	(In thousands)								(In thousands)
Conflicts Committee approved reimbursement amount	$	4,104	$	4,104	$	—	—	%	$	8,208	$	8,208	$	—	—	%

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.

Recent Debt Financing Activity

Credit Facility Amendment. On February 21, 2018, we amended our revolving credit facility in order to achieve two primary objectives, the first of which was to accommodate growth capital expenditures necessary for the aforementioned WTLPG expansion project. Starting in the first quarter of 2018, the amendment will provide short-term (5 quarters) covenant relief by increasing the total leverage ratio to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginning in the second quarter of 2019. Additionally, the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part of and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90% of the value of forward sold/hedged inventory.

We believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements and anticipated maintenance capital expenditures in 2018.

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, 2017, filed with the SEC on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018, for a discussion of such risks.

Cash Flows - Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

The following table details the cash flow changes between the six months ended June 30, 2018 and 2017:



	Six Months Ended June 30,						Variance			Percent Change
	2018			2017			Variance			Percent Change
	(In thousands)
Net cash provided by (used in):
Operating activities	$	58,503		$	45,788		$	12,715		28	%
Investing activities	(36,046		)	(24,428		)	(11,618		)	48	%
Financing activities	(21,874		)	(21,343		)	(531		)	2	%
Net increase in cash and cash equivalents	$	583		$	17		$	566		3,329	%

Net cash provided by operating activities. The increase in net cash provided by operating activities for the six months ended June 30, 2018 includes a $22.4 million favorable variance in working capital and $0.1 million favorable variance in other non-current assets and liabilities. Further increases were due to increases in distributions received from WTLPG of $0.5 million. Offsetting was a decrease in operating results of $9.0 million and a $1.3 million decrease in other non-cash charges.

Net cash used in investing activities. Net cash used in investing activities for the six months ended June 30, 2018 increased primarily as a result of an increase of $12.4 million from contributions to WTLPG and an increase of $2.2 million due to higher payments for capital expenditures and plant turnaround costs in 2018. A $15.0 million decline in proceeds received resulted from repayment of the Note receivable - affiliate in 2017 as compared to none in 2018. Further, a $1.5 million decline in proceeds received resulted from higher sales of property, plant and equipment in 2017. Offsetting, was a decrease in cash used in investing activities as a result of the acquisition of certain asphalt terminalling assets from Martin Resource Management of $19.5 million in 2017 compared to no acquisitions in 2018.

Net cash used in financing activities. Net cash used in financing activities increased for the six months ended June 30, 2018 as a result of a decrease in proceeds received from the issuance of common units (including the related general partner contribution) of $52.3 million. Also contributing was an increase in cash distributions paid of $1.5 million and an additional $1.2 million in costs associated with our credit facility amendment. Offsetting was a decrease in net repayments of long-term borrowings of $48.0 million and a decrease in cash used of $6.7 million related to excess purchase price over the carrying value of acquired assets in common control transactions.

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,
	2018		2017		2018		2017
	(In thousands)
Expansion capital expenditures	$	2,937	$	11,065	$	9,904	$	14,317
Maintenance capital expenditures	5,370		2,618		11,372		7,286
Plant turnaround costs	—		197		—		1,591
Total	$	8,307	$	13,880	$	21,276	$	23,194

Expansion capital expenditures were made primarily in our Marine Transportation and Terminalling and Storage segments during the three and six months ended June 30, 2018 on certain ongoing organic growth projects. Maintenance capital expenditures were made primarily in our Marine Transportation segment for the six months ended June 30, 2018 related to regulatory maintenance.

Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three and six months ended June 30, 2017. Within our Terminalling and Storage segment, expenditures were made primarily on project construction at our newly acquired asphalt terminal in Hondo, Texas, 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 segment to maintain our existing assets and operations during the six months ended June 30, 2017. For the six months ended June 30, 2017, 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, 2018, 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	$	464,000	$	—	$	464,000	$	—	$	—
2021 Senior unsecured notes	373,800		—		373,800		—		—
Throughput commitment	18,428		6,111		12,251		66		—
Operating leases	25,658		7,846		7,507		2,874		7,431
Interest payable on fixed long-term debt obligations	71,139		27,101		44,038		—		—
Total contractual cash obligations	$	953,025	$	41,058	$	901,596	$	2,940	$	7,431

The interest payable under our credit facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time.

Letters of Credit. At June 30, 2018, we had outstanding irrevocable letters of credit in the amount of $23.8 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, 2017, as amended.

Revolving Credit Facility

At June 30, 2018, we maintained a $664.4 million credit facility. This facility was most recently amended on February 21, 2018 when we amended our revolving credit facility in order to achieve two primary objectives, the first of which was to accommodate growth capital expenditures necessary for the aforementioned WTLPG expansion project. Starting in the first quarter of 2018, the amendment will provide short-term (5 quarters) covenant relief by increasing the total leverage ratio to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginning in the second quarter of 2019. Additionally, the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part of and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90% of the value of forward sold/hedged inventory.

As of June 30, 2018, we had $464.0 million outstanding under the revolving credit facility and $23.8 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 $176.7 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, 2018, we have the ability to borrow approximately $20.6 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, 2018, the level of outstanding draws on our credit facility has ranged from a low of $428.0 million to a high of $500.0 million.

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

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

Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee on all letters of credit issued under the credit facility, and we pay a commitment fee per annum on the unused revolving credit availability under the credit facility. The letter of credit fee, the commitment fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows as of June 30, 2018:



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, 2018, 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, 2018 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. Based on the most recent amendment to our revolving credit facility on February 21, 2018, the maximum permitted leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash

charges) was revised from 5.25 to 1.00, with a temporary springing provision to 5.50 to 1.00 under certain scenarios, to 5.75 to 1.00 for the first and second quarters of 2018, 5.50 to 1.00 for the next three quarters and 5.25 to 1.00, with the temporary springing provision to 5.50 to 1.00 going back into effect, thereafter and (iv) decrease the maximum permitted senior leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 3.50 to 1.00 to 3.25 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.

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.

We are in compliance with all debt covenants as of June 30, 2018 and expect 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, 2018 or 2017. 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, 2018 or 2017.



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, 2018 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 gross notional quantity of 360,000 barrels settling during the period from October 1, 2018 through December 31, 2018. These instruments settle against the applicable pricing source for each grade and location. These instruments are recorded on our Consolidated and Condensed Balance Sheets at June 30, 2018 in "Fair value of derivatives" as a current liability of $0.6 million. Based on the current net notional volume hedged as of June 30, 2018, a $0.10 change in the expected settlement price of these contracts would result in a corresponding decrease in net income of approximately $1.5 million.

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 5.09% as of June 30, 2018. Based on the amount of unhedged floating rate debt owed by us on June 30, 2018, 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 $4.6 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 $370.2 million as of June 30, 2018, based on market prices of similar debt at June 30, 2018. 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 an $8.5 million decrease in the fair value of our long-term debt at June 30, 2018.



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.

During 2017 we began implementation of a new enterprise resource planning ("ERP") system. The new ERP system is expected to take several years to fully implement, and has and will continue to require significant capital and human resources to deploy. During the six months ended June 30, 2018, we completed the implementation of certain functional areas of the ERP implementation project that affect the processes that constitute our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) and this initial deployment will require testing for effectiveness throughout 2018. Management has taken steps to ensure that appropriate controls are designed and implemented as each functional area of the new ERP system is enacted.

Beginning January 1, 2018, we implemented ASC 606, Revenue from Contracts with Customers. Although the new revenue standard is expected to have an immaterial impact on our ongoing net income, we did implement changes to our processes related to revenue recognition and the control activities within them. These included the development of new policies based on the five-step model provided in the new revenue standard, new training, ongoing contract review requirements, and gathering of information provided for disclosures.

Other than as described above, there were no changes in our internal control over financial reporting during the six months ended June 30, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control 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 15 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 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018.



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.

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, 2018, 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

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: 7/25/2018	By:	/s/ Robert D. Bondurant
		Robert D. Bondurant
		Executive Vice President, Treasurer, Chief Financial Officer, and Principal Accounting Officer