10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________________________________ 

FORM 10-Q

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

 For the quarterly period ended September 30, 2012

OR

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

For the transition period from ____________ to ____________

Commission File Number

000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)

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

4200 Stone Road

Kilgore, Texas 75662

(Address of principal executive offices, zip code)

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

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

Yes  x No o

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

Yes x No o

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

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

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

Yes o No x

The number of the registrant’s Common Units outstanding at November 5, 2012, was 23,116,776.

		Page
PART I – FINANCIAL INFORMATION		2
Item 1. Financial Statements		2
	Consolidated and Condensed Balance Sheets as of September 30, 2012 (unaudited) and December 31, 2011 (audited)	2
	Consolidated and Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011 (unaudited)	3
	Consolidated and Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011 (unaudited)	6
	Consolidated and Condensed Statements of Capital for the Nine Months Ended September 30, 2012 and 2011 (unaudited)	7
	Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011 (unaudited)	8
	Notes to Consolidated and Condensed Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		55
Item 3. Quantitative and Qualitative Disclosures about Market Risk		56
Item 4. Controls and Procedures		57
PART II. OTHER INFORMATION		58
Item 1. Legal Proceedings		58
Item 1A. Risk Factors		58
Item 5. Other Information		58
Item 6. Exhibits		60
SIGNATURE
CERTIFICATIONS

1

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	September 30, 2012			December 31, 2011
	(Unaudited)			(Audited)
Assets
Cash	$	27		$	266
Accounts and other receivables, less allowance for doubtful accounts of $3,264 and $3,021, respectively	121,020			126,461
Product exchange receivables	5,455			17,646
Inventories	116,260			77,677
Due from affiliates	21,139			5,968
Fair value of derivatives	—			622
Other current assets	1,511			1,978
Assets held for sale	—			212,787
Total current assets	265,412			443,405
Property, plant and equipment, at cost	695,662			632,728
Accumulated depreciation	(243,780		)	(215,272		)
Property, plant and equipment, net	451,882			417,456
Goodwill	8,337			8,337
Investment in unconsolidated entities	80,799			62,948
Debt issuance costs, net	10,924			13,330
Other assets, net	6,442			3,633
	$	823,796		$	949,109
Liabilities and Partners’ Capital
Current installments of long-term debt and capital lease obligations	$	217		$	1,261
Trade and other accounts payable	104,779			125,970
Product exchange payables	27,908			37,313
Due to affiliates	4,669			18,485
Income taxes payable	7,174			893
Fair value of derivatives	—			362
Other accrued liabilities	11,764			11,022
Liabilities held for sale	—			501
Total current liabilities	156,511			195,807
Long-term debt and capital leases, less current maturities	255,966			458,941
Deferred income taxes	—			7,657
Other long-term obligations	1,069			1,088
Total liabilities	413,546			663,493
Partners’ capital	410,250			284,990
Accumulated other comprehensive income	—			626
Total partners’ capital	410,250			285,616
Commitments and contingencies
	$	823,796		$	949,109

See accompanying notes to consolidated and condensed financial statements.

2

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenues:
Terminalling and storage  *	$	23,875		$	19,381		$	65,107		$	56,831
Marine transportation  *	22,102			20,773			63,678			57,548
Sulfur services	2,926			2,850			8,777			8,550
Product sales: *
Natural gas services	190,738			159,748			527,666			423,953
Sulfur services	57,670			67,319			193,464			198,310
Terminalling and storage	20,601			17,525			61,482			55,441
	269,009			244,592			782,612			677,704
Total revenues	317,912			287,596			920,174			800,633
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	185,686			156,236			515,928			414,162
Sulfur services *	47,272			59,808			149,582			164,142
Terminalling and storage	18,767			15,676			56,154			49,631
	251,725			231,720			721,664			627,935
Expenses:
Operating expenses  *	36,655			34,354			108,109			100,676
Selling, general and administrative  *	4,680			5,538			13,687			13,015
Depreciation and amortization	9,966			10,025			29,457			29,523
Total costs and expenses	303,026			281,637			872,917			771,149
Other operating income (loss)	(5		)	1,720			368			1,818
Operating income	14,881			7,679			47,625			31,302
Other income (expense):
Equity in earnings (loss) of unconsolidated entities	(169		)	(54		)	(532		)	100
Interest expense	(6,263		)	(4,297		)	(21,735		)	(17,102		)
Debt prepayment premium	—			—			(2,470		)	—
Other, net	587			24			732			125
Total other expense	(5,845		)	(4,327		)	(24,005		)	(16,877		)
Income from continuing operations before taxes	9,036			3,352			23,620			14,425
Income tax expense	(238		)	(218		)	(810		)	(662		)
Income from continuing operations	8,798			3,134			22,810			13,763
Income from discontinued operations, net of income taxes	63,603			2,265			67,312			7,728
Net income	$	72,401		$	5,399		$	90,122		$	21,491

3

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

*Related Party Transactions Included Above

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Revenues:
Terminalling and storage	$	18,531	$	14,210	$	48,611	$	40,045
Marine transportation	3,979		6,352		13,282		19,223
Product Sales	1,636		1,628		5,783		7,197
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	6,761		9,257		18,783		13,679
Sulfur services	4,111		4,762		12,512		13,407
Expenses:
Operating expenses	14,100		16,905		42,308		42,170
Selling, general and administrative	2,764		2,373		8,258		6,344

4

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012		2011
Allocation of net income attributable to:
Limited partner interest:
Continuing operations	$	10,128		$	2,157	$	21,645	$	10,674
Discontinued operations	60,825			1,617		63,874		5,994
	70,953			3,774		85,519		16,668
General partner interest:
Continuing operations	(1,330		)	811		1,165		2,557
Discontinued operations	2,778			537		3,438		1,435
	1,448			1,348		4,603		3,992
Net income attributable to:
Continuing operations	8,798			3,134		22,810		13,763
Discontinued operations	63,603			2,265		67,312		7,728
	$	72,401		$	5,399	$	90,122	$	21,491
Net income attributable to limited partners:
Basic:
Continuing operations	$	0.44		$	0.11	$	0.94	$	0.56
Discontinued operations	2.63			0.09		2.79		0.31
	$	3.07		$	0.20	$	3.73	$	0.87
Weighted average limited partner units - basic	23,101			19,158		22,929		19,161
Diluted:
Continuing operations	$	0.44		$	0.11	$	0.94	$	0.56
Discontinued operations	2.63			0.09		2.79		0.31
	$	3.07		$	0.20	$	3.73	$	0.87
Weighted average limited partner units - diluted	23,105			19,163		22,932		19,163

See accompanying notes to consolidated and condensed financial statements.

5

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net income	$	72,401		$	5,399		$	90,122		$	21,491
Other comprehensive income adjustments:
Changes in fair values of commodity cash flow hedges	—			1,295			126			1,231
Commodity cash flow hedging gains (losses) reclassified to earnings	(63		)	(538		)	(752		)	(1,291		)
Interest rate cash flow hedging gains reclassified to earnings	—			—			—			18
Other comprehensive income	(63		)	757			(626		)	(42		)
Comprehensive income	$	72,338		$	6,156		$	89,496		$	21,449

See accompanying notes to consolidated and condensed financial statements.

6

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)

	Partners’ Capital
	Common Limited					Subordinated Limited			General Partner			Accumulated Other Comprehensive Income
	Units		Amount			Units	Amount		Amount			(Loss)			Total
Balances - January 1, 2011	17,707,832		$	250,785		889,444	$	17,721	$	4,881		$	1,419		$	274,806
Net income	—		17,499			—	—		3,992			—			21,491
Recognition of beneficial conversion feature	—		(831		)	—	831		—			—			—
Follow-on public offering	1,874,500		70,330			—	—		—			—			70,330
General partner contribution	—		—			—	—		1,505			—			1,505
Cash distributions	—		(43,321		)	—	—		(4,635		)	—			(47,956		)
Excess purchase price over carrying value of acquired assets	—		(19,685		)	—	—		—			—			(19,685		)
Unit-based compensation	15,530		131			—	—		—			—			131
Purchase of treasury units	(14,850	)	(582		)	—	—		—			—			(582		)
Unit-based compensation grant forfeitures	(500	)	—			—	—		—			—			—
Adjustment in fair value of derivatives	—		—			—	—		—			(42		)	(42		)
Balances - September 30, 2011	19,582,512		$	274,326		889,444	$	18,552	$	5,743		$	1,377		$	299,998
Balances - January 1, 2012	20,471,776		$	279,562		—	$	—	$	5,428		$	626		$	285,616
Net income	—		85,519			—	—		4,603			—			90,122
Follow-on public offering	2,645,000		91,361			—	—		—			—			91,361
General partner contribution	—		—			—	—		1,951			—			1,951
Cash distributions	—		(52,880		)	—	—		(5,452		)	—			(58,332		)
Unit-based compensation	6,250		379			—	—		—			—			379
Purchase of treasury units	(6,250	)	(221		)	—	—		—			—			(221		)
Adjustment in fair value of derivatives	—		—			—	—		—			(626		)	(626		)
Balances - September 30, 2012	23,116,776		$	403,720		—	$	—	$	6,530		$	—		$	410,250

See accompanying notes to consolidated and condensed financial statements.

7

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Nine Months Ended
	September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	90,122		$	21,491
Less:  Income from discontinued operations	(67,312		)	(7,728		)
Net income from continuing operations	22,810			13,763
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	29,457			29,523
Amortization of deferred debt issuance costs	2,611			3,071
Amortization of debt discount	504			262
Loss on sale of property, plant and equipment	7			405
Gain on sale of equity method investment	(486		)	—
Equity in earnings (loss) of unconsolidated entities	532			(100		)
Other	379			131
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(6,328		)	(4,788		)
Product exchange receivables	12,190			(16,552		)
Inventories	(38,583		)	(28,057		)
Due from affiliates	(27,795		)	221
Other current assets	431			1,874
Trade and other accounts payable	(8,533		)	11,733
Product exchange payables	(9,405		)	27,350
Due to affiliates	4,469			3,430
Income taxes payable	(96		)	(799		)
Other accrued liabilities	840			4,218
Change in other non-current assets and liabilities	(1,126		)	(123		)
Net cash provided by (used in) continuing operating activities	(18,122		)	45,562
Net cash provided by discontinued operating activities	120			12,272
Net cash provided by (used in) operating activities	(18,002		)	57,834
Cash flows from investing activities:
Payments for property, plant and equipment	(63,009		)	(48,769		)
Acquisitions	—			(16,815		)
Payments for plant turnaround costs	(2,578		)	(2,103		)
Proceeds from sale of property, plant and equipment	33			530
Proceeds from sale of equity method investment	531			—
Investment in unconsolidated subsidiaries	(775		)	(59,319		)
Return of investments from unconsolidated entities	5,133			383
Distributions from (contributions to) unconsolidated entities for operations	(22,786		)	(929		)
Net cash used in continuing investing activities	(83,451		)	(127,022		)
Net cash provided by (used in) discontinued investing activities	271,181			(8,253		)
Net cash provided by (used in) investing activities	187,730			(135,275		)
Cash flows from financing activities:
Payments of long-term debt	(547,000		)	(389,000		)
Payments of notes payable and capital lease obligations	(6,522		)	(831		)
Proceeds from long-term debt	349,000			456,000
Net proceeds from follow on offering	91,361			70,330
General partner contribution	1,951			1,505
Treasury units purchased	(221		)	(582		)
Payment of debt issuance costs	(204		)	(3,424		)
Excess purchase price over carrying value of acquired assets	—			(19,685		)
Cash distributions paid	(58,332		)	(47,956		)
Net cash provided by (used in) financing activities	(169,967		)	66,357
Net decrease in cash	(239		)	(11,084		)
Cash at beginning of period	266			11,380
Cash at end of period	$	27		$	296

See accompanying notes to consolidated and condensed financial statements.

8

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

(1) General

Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products, natural gas services, sulfur and sulfur-based products processing, manufacturing, marketing and distribution, and marine transportation services for petroleum products and by-products.

The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and United States generally accepted accounting principles for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by generally accepted accounting principles 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 results of operations, financial position 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, 2011, filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2012. On August 21, 2012, Part II, Items 6, 7, and 8 of the Partnership's Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012, was updated on Form 8-K to reflect the operations related to the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets as discontinued operations

As discussed in Note 4, on July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets.  These assets, along with additional gathering and processing assets discussed in Note 4 are collectively referred to as the "Prism Assets".  The Partnership classified the Prism Assets, including related liabilities as held for sale at December 31, 2011, and has presented the results of operations and cash flows as discontinued operations for the periods ended September 30, 2012 and 2011, respectively. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the net assets and operations and cash flows of the Prism Assets as assets held for sale and discontinued operations, respectively.

(a) Use of Estimates

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 financial statements in conformity with accounting principles generally accepted in the United States.  Actual results could differ from those estimates.

(b) Unit Grants

In May 2012, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 6,250 treasury units purchased by the Partnership in the open market for $221.  These units vest in 25% increments beginning in January 2013 and will be fully vested in January 2016.

In May 2011, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 5,750 treasury units purchased by the Partnership in the open market for $235 and 500 treasury units from forfeitures.  These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.

In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for $347.  On July 31, 2012, 6,850 of these units were fully vested to certain employees in connection with the sale of the Prism Assets. The remaining 2,250 units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015.

The cost resulting from share-based payment transactions was $261 and $36 for the three months ended September 30, 2012 and 2011, respectively, and $379 and $131 for the nine months ended September 30, 2012 and 2011, respectively.

9

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

(c) Incentive Distribution Rights

The Partnership’s general partner, Martin Midstream GP LLC, 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 of the Partnership (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. As discussed further in Note 16, on October 2, 2012, the Partnership Agreement was amended to provide that the General Partner shall not receive the next $18,000 in incentive distributions that it would otherwise be entitled to receive. Therefore, no incentive distributions were allocated to the general partner for the three months ended September 30, 2012, which would have been payable to the general partner on November 14, 2012.

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

For the three months ended September 30, 2012 and 2011, the general partner received $0 and $1,265, respectively, in incentive distributions.  For the nine months ended September 30, 2012 and 2011, the general partner received $2,857 and $3,635, respectively, in incentive distributions.

(d) Net Income per Unit

The Partnership follows the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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 IDR would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement.

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 beneficial conversion feature is added back to net income available to common limited partners, 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.

10

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	8,798		$	3,134		$	22,810	$	13,763
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	(1,536		)	763			723		2,328
Distributions payable on behalf of general partner interest	(320		)	207			295		640
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	526			(159		)	147		(411		)
Less beneficial conversion feature	—			166			—		532
Limited partners’ interest in net income	$	10,128		$	2,157		$	21,645	$	10,674

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	63,603	$	2,265		$	67,312	$	7,728
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	1,536		502			2,134		1,307
Distributions payable on behalf of general partner interest	709		138			872		360
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	533		(103		)	432		(232		)
Less beneficial conversion feature	—		111			—		299
Limited partners’ interest in net income	$	60,825	$	1,617		$	63,874	$	5,994

The Partnership allocates the General Partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income. The allocation is done at each period end on an annual basis, resulting in each quarter representing the difference between year to date of the current quarter and year to date as of the previous quarter.

The weighted average units outstanding for basic net income per unit were 23,101,233 and 22,929,172 for the three and nine months ended September 30, 2012, respectively, and 19,158,334 and 19,161,403 for the three and nine months ended September 30, 2011, respectively.  For diluted net income per unit, the weighted average units outstanding were increased by 3,596 and 3,164 for the three and nine months ended September 30, 2012, respectively, and 4,794 and 1,663 for the three and nine months ended September 30, 2011, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(e) Income Taxes

With respect to the Partnership’s taxable subsidiary, Woodlawn Pipeline Co., Inc. (“Woodlawn”), income taxes are accounted for under the asset and liability method.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(2) New Accounting Pronouncements

11

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

In September 2011, the FASB amended the provisions of ASC 350 related to testing goodwill for impairment.  This update simplifies the goodwill impairment assessment by allowing a company to first review qualitative factors to determine the likelihood of whether the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, the company would not be required to perform the two-step goodwill impairment test for that reporting unit. This update is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  This amended guidance was adopted by the Partnership effective January 1, 2012.

In June 2011, the FASB amended the provisions of ASC 220 related to other comprehensive income. This newly issued guidance: (1) eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity; (2) requires the consecutive presentation of the statement of net income and other comprehensive income; and (3) requires an entity to present reclassification adjustments on the face of the financial statements from other comprehensive income to net income. The amendments in this guidance do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income nor do the amendments affect how earnings per share is calculated or presented. This guidance is required to be applied retrospectively and is effective for fiscal years and interim periods within those years beginning after December 15, 2011.  This amended guidance was adopted by the Partnership effective January 1, 2012.  As this new guidance only requires enhanced disclosure, adoption did not impact the Partnership’s financial position or results of operations.

(3) Acquisitions

Redbird Gas Storage

On May 31, 2011, the Partnership acquired all of the Class B equity interests in Redbird Gas Storage LLC (“Redbird”) for approximately $59,319.  This amount was recorded as an investment in an unconsolidated entity.  Redbird, a subsidiary of Martin Resource Management, is a natural gas storage joint venture formed to invest in Cardinal Gas Storage Partners, LLC (“Cardinal”).  Cardinal is a joint venture between Redbird and Energy Capital Partners that is focused on the development, construction, operation and management of natural gas storage facilities across North America.  Redbird owns an unconsolidated 40.95% interest in Cardinal.  Concurrent with the closing of this transaction, Cardinal acquired all of the outstanding equity interests in Monroe Gas Storage Company, LLC (“Monroe”) as well as an option on development rights to an adjacent depleted reservoir facility.  This acquisition was funded by borrowings under the Partnership’s revolving credit facility.  In addition to owning all of the Class B equity interests of Redbird, the Partnership also owns 10.74% of the Class A equity interests of Redbird at September 30, 2012.

Terminalling Facilities

On January 31, 2011, the Partnership acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for $36,500.  These assets are located across the Louisiana Gulf Coast.  This acquisition was funded by borrowings under the Partnership’s revolving credit facility.

These terminalling assets were acquired by Martin Resource Management in its acquisition of L&L Holdings LLC (“L&L”) on January 31, 2011.  During the second quarter of 2011, Martin Resource Management finalized the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the terminalling assets acquired by the Partnership.  The Partnership recorded an adjustment in the amount of $19,685 to reduce property, plant and equipment and partners’ capital for the difference between the purchase price and the fair value of the terminalling assets acquired based on Martin Resource Management’s final purchase price allocation.

(4) Discontinued operations and divestitures

On July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas Systems I, L.P. (“Prism Gas”), a wholly-owned subsidiary of the Partnership, and other natural gas gathering and processing assets also owned by the Partnership to a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”). The Partnership received net cash proceeds from the sale of $273,269.  The asset sale includes

12

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

the Partnership’s 50% operating interest in Waskom Gas Processing Company (“Waskom”).  A subsidiary of CenterPoint owned the other 50% percent interest.  

Additionally, on September 18, 2012, the Partnership completed the sale of its interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) to a private investor group for $1,530.  

The assets described above collectively are referred to herein as the Prism Assets.

The Partnership classified the results of operations of the Prism Assets which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the consolidated and condensed statements of operations for all periods presented. The assets and liabilities to be sold met the accounting criteria to be classified as held for sale and were aggregated and reported on separate lines in the consolidated and condensed balance sheet at December 31, 2011.

The assets and liabilities classified held for sale as of December 31, 2011 were as follows:

	December 31, 2011
Assets
Inventories	$	486
Property, plant and equipment	78,324
Accumulated depreciation	(18,438		)
Goodwill	28,931
Investment in unconsolidated entities	107,549
Other assets, net	15,935
Assets held for sale	$	212,787
Liabilities
Other long-term obligations	501
Liabilities held for sale	$	501

The Prism Assets’ operating results, which are included within income from discontinued operations, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Total revenues from third parties1	$	9,269		$	28,714		$	66,842		$	90,917
Total costs and expenses, excluding depreciation and amortization	(9,296		)	(26,892		)	(64,556		)	(85,888		)
Depreciation and amortization	—			(1,375		)	(2,320		)	(4,128		)
Other operating income2	62,251			—			61,421			3
Equity in earnings of Waskom, Matagorda, and PIPE	377			1,839			4,611			6,854
Income from discontinued operations before income taxes	62,601			2,286			65,998			7,758
Income tax expense (benefit)	(1,002		)	21			(1,314		)	30
Income from discontinued operations, net of income taxes	$	63,603		$	2,265		$	67,312		$	7,728

¹ Total revenues from third parties excludes intercompany revenues of $3,285, $17,741, $26,431, and $49,444 for the three months ended September 30, 2012 and 2011, and nine months ended September 30, 2012 and 2011, respectively.

² The Partnership recognized a gain on the sale of its Prism Gas Business of $62,251 and $61,411 in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011, respectively.

(5) Inventories

13

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

Components of inventories at September 30, 2012 and December 31, 2011 were as follows: 

	September 30, 2012		December 31, 2011
Natural gas liquids	$	64,783	$	25,178
Sulfur	26,460		24,335
Sulfur based products	14,115		14,857
Lubricants	8,471		11,012
Other	2,431		2,295
	$	116,260	$	77,677

(6) Investments in Unconsolidated Entities and Joint Ventures

As discussed in detail in Note 4, the Partnership sold its 50% interests in Waskom, Matagorda, and PIPE. The equity in earnings associated with these investments during the periods owned is recorded in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011.

The Partnership and Martin Resource Management formed Redbird, a natural gas storage joint venture formed to invest in Cardinal.  The Partnership owns 10.74% of the Class A equity interests and all the Class B equity interests in Redbird.  Redbird owns an unconsolidated 40.95% interest in Cardinal.   Redbird utilized the investments by the Partnership to invest in Cardinal to fund projects for natural gas storage facilities.

During the second quarter of 2012, the Partnership acquired an unconsolidated 50% interest in Caliber Gathering System, LLC (“Caliber”) and Pecos Valley Producer Services LLC (“Pecos Valley”). The Partnership sold its interest in Pecos Valley during the third quarter of 2012 for $531, resulting in a gain of $486 recorded in Other, Net in the Partnership's consolidated and condensed statement of operations for the three and nine months ended September 30, 2012.

These investments are accounted for by the equity method.

The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s consolidated and condensed balance sheets and the components of equity in earnings of unconsolidated entities included in the Partnership’s consolidated and condensed statements of operations:

	September 30, 2012		December 31, 2011
Investment in Waskom1	$	—	$	102,896
Investment in PIPE1	—		1,291
Investment in Matagorda1	—		3,362
Investment in unconsolidated entities classified as assets held for sale	—		107,549
Investment in Redbird	80,168		62,948
Investment in Caliber	631		—
Investment in unconsolidated entities	80,799		62,948
Total Investment in unconsolidated entities	$	80,799	$	170,497

¹ As of December 31, 2011, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed balance sheet as assets held for sale.

14

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Equity in earnings of Waskom1	$	287		$	1,767		$	4,172		$	6,779
Equity in earnings of PIPE1	10			(15		)	(60		)	(45		)
Equity in earnings of Matagorda1	80			87			499			120
Equity in earnings of discontinued operations	377			1,839			4,611			6,854
Equity in earnings of Redbird	(103		)	(54		)	(433		)	100
Equity in earnings of Caliber	(98		)	—			(119		)	—
Equity in earnings of Pecos Valley	32			—			20			—
Equity in earnings of unconsolidated entities	(169		)	(54		)	(532		)	100
Total equity in earnings of unconsolidated entities	$	208		$	1,785		$	4,079		$	6,954

¹ For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed statement of operations and cash flows as discontinued operations.

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

	As of September 30				Three Months Ended September 30				Nine Months Ended September 30
	Total Assets		Partner’s Capital		Revenues1		Net Income1		Revenues1		Net Income1
2012
Waskom	$	—	$	—	$	8,171	$	668	$	66,662	$	8,986
	As of December 31
2011
Waskom	$	146,655	$	126,863	$	29,508	$	3,808	$	95,086	$	14,382

¹ Revenues and Net Income for Waskom include financial information only for the periods owned. Three months ended September 30, 2012 only includes financial information for the one month ended July 31, 2012. Nine months ended September 30, 2012 only includes financial information for the seven months ended July 31, 2012.

As of September 30, 2012 and December 31, 2011 the amount of the Partnership’s consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity-method investees is $0 and $47,152, respectively.  There are no material restrictions to transfer funds in the form of dividends, loans or advances related to the equity-method investees.

As of September 30, 2012 and December 31, 2011, the Partnership’s interest in cash of the unconsolidated equity-method investees was $502 and $565, respectively.

(7) Derivative Instruments and Hedging Activities

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

The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of its outstanding hedge contracts, including assessing the possibility of counterparty default. If the Partnership determines that a derivative is no longer expected to be highly effective, the Partnership discontinues hedge accounting prospectively and recognizes subsequent changes in the fair value of the hedge in earnings.

15

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings. The Partnership is exposed to the risk that periodic changes in the fair value of derivatives qualifying for hedge accounting will not be effective, as defined, or that derivatives will no longer qualify for hedge accounting. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is recorded to earnings. Likewise, if a hedge ceases to qualify for hedge accounting, any change in the fair value of derivative instruments since the last period is recorded to earnings; however, any amounts previously recorded to AOCI would remain there until such time as the original forecasted transaction occurs, then would be reclassified to earnings or if it is determined that continued reporting of losses in AOCI would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods, then the losses would be immediately reclassified to earnings.  If a forecasted hedge transaction is no longer probable of occurring, any gain or loss in AOCI is reclassified to earnings.

For derivative instruments that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. The effective portion of the derivative represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. To the extent the change in the fair value of the hedge does not perfectly offset the change in the fair value of the hedged item, the ineffective portion of the hedge is immediately recognized in earnings.

(a) Commodity Derivative Instruments

The Partnership is exposed to market risks associated with commodity prices and from time to time uses derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure.  These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership is focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

Due to the sale of the Prism Assets completed on July 31, 2012, as of September 30, 2012, the Partnership has terminated and settled all of its commodity derivative instruments.  For the three and nine months ended September 30, 2012, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in AOCI as a component of partners’ capital.

(b) Impact of Commodity Cash Flow Hedges

Crude Oil.  For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts decreased and increased crude revenue (included in income from discontinued operations) by $36 and $361, respectively.  For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased crude revenue (included in income from discontinued operations) by $496 and $658, respectively.

Natural Gas.  For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $77 and $72, respectively.  For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $813 and $215, respectively.  

Natural Gas Liquids.  For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $5 and $236, respectively.  For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $1,066 and $458, respectively. 

For information regarding fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note.

16

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

(c) Impact of Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt credit facility and its’ senior notes. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in AOCI until such time as the hedged item is recognized in earnings.

In August 2011, the Partnership terminated all of its existing interest swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes as described in Note 11.  These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings.  Termination fees of $2,800 were received on the early extinguishment of the interest rate swap agreements in August 2011.

The Partnership was not a party to interest rate derivatives during the nine months ended September 30, 2012.  The Partnership recognized decreases in interest expense of $3,244 and $5,779 for the three and nine months ended September 30, 2011, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges.

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

(d) Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items

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

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	September 30, 2012		December 31, 2011		Balance Sheet Location	September 30, 2012		December 31, 2011
Derivatives designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	622	Fair value of derivatives	$	—	$	245
Total derivatives designated as hedging instruments		$	—	$	622		$	—	$	245
Derivatives not designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	117
Total derivatives not designated as hedging instruments		$	—	$	—		$	—	$	117

17

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

	Effect of Derivative Instruments on the Consolidated Statement of Operations For the Three Months Ended September 30, 2012 and 2011
	Effective Portion									Ineffective Portion and Amount  Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives				Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income				Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011			2012		2011			2012		2011
Derivatives designated as hedging instruments:
Commodity contracts	$	—	$	1,295	Income from discontinued operations	$	63	$	500	Income from discontinued operations	$	—	$	38
Total derivatives designated as hedging instruments	$	—	$	1,295		$	63	$	500		$	—	$	38

	Location of Gain or (Loss) Recognized in Income on  Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012			2011
Derivatives not designated as hedging instruments:
Interest rate contracts	Interest expense	$	—		$	3,244
Commodity contracts	Income from discontinued operations	(18		)	131
Total derivatives not designated as hedging instruments		$	(18	)	$	3,375

18

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

Effect of Derivative Instruments on the Consolidated Statement of Operations

For the Nine Months Ended September 30, 2012 and 2011

	Effective Portion										Ineffective Portion and Amount  Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives				Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income					Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011			2012		2011				2012		2011
Derivatives designated as hedging instruments
Interest rate contracts	$	—	$	—	Interest expense	$	—	$	(18	)	Interest expense	$	—	$	—
Commodity contracts	126		1,231		Income from discontinued operations	748		1,264			Income from discontinued operations	4		$	27
Total derivatives designated as hedging instruments	$	126	$	1,231		$	748	$	1,246			$	4	$	27

	Location of Gain or (Loss) Recognized in Income on  Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012		2011
Derivatives not designated as hedging instruments
Interest rate contracts	Interest Expense	$	—	$	5,797
Commodity contracts	Income from discontinued operations	1,623		41
Total derivatives not designated as hedging instruments		$	1,623	$	5,838

No amounts are expected to be reclassified into earnings for the subsequent 12-month period for commodity cash flow hedges.

(8) Fair Value Measurements

The Partnership provides disclosures pursuant to certain provisions of ASC 820, which provides a framework for measuring fair value and expanded disclosures about fair value measurements.  ASC 820 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value into one of the following categories:

Level 1: Quoted market prices in active markets for identical assets or liabilities.

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

Level 3: Unobservable inputs that are not corroborated by market data.

The Partnership’s derivative instruments, which consist of commodity and interest rate swaps, are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets, which is considered Level 2. Refer to Note 7 for further information on the Partnership’s derivative instruments and hedging activities.

19

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at December 31, 2011:

	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	December 31, 2011		(Level 1)		(Level 2)		(Level 3)
Assets
Natural gas derivatives	$	622	$	—	$	622	$	—
Total assets	$	622	$	—	$	622	$	—
Liabilities
Crude oil derivatives	245		—		245		—
Natural gas liquids derivatives	117		—		117		—
Total liabilities	$	362	$	—	$	362	$	—

ASC 825-10-65, related to disclosures about fair value of financial instruments, requires that the Partnership disclose estimated fair values for its financial instruments.  Fair value estimates are set forth below for the Partnership’s financial instruments.  The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

• Accounts and other receivables, trade and other accounts payable, 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.

• Long-term debt including current installments — the carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate.

The estimated fair value of the Senior Notes was approximately $189,557 as of September 30, 2012 based on quoted market prices of similar debt at September 30, 2012, which is deemed a Level 2 measurement.

(9) Related Party Transactions

As of September 30, 2012, Martin Resource Management owns 6,593,267 of the Partnership’s common units representing approximately 28.5% of the Partnership’s outstanding limited partnership units.  The Partnership’s general partner is a wholly-owned subsidiary of Martin Resource Management.  The Partnership’s general partner owns a 2.0% general partner interest in the Partnership and the Partnership’s incentive distribution rights.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of September 30, 2012, of approximately 28.5% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

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

Omnibus Agreement

Omnibus Agreement.   The Partnership and its general partner are parties to an omnibus agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain of Martin Resource Management’s trade names and trademarks. The omnibus agreement was amended on November 24, 2009, to include processing crude oil into finished

20

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The omnibus agreement was amended further on October 2, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. See Note 16.   

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, refining, processing, distribution and midstream logistical services for hydrocarbon products and by-products;

• providing marine and other transportation of hydrocarbon products and by-products; and

• manufacturing and marketing fertilizers and related sulfur-based products.

This restriction does not apply to:

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

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

◦ providing land transportation of various liquids;

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

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

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

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

◦ building and marketing sulfur processing equipment; and

◦ developing an underground natural gas storage facility in Arcadia, Louisiana.

• 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; and

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

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

21

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

Effective October 1, 2011, through September 30, 2012, the Conflicts Committee of the board of directors of the general partner of the Partnership (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $6,582.  The Partnership reimbursed Martin Resource Management for $1,646 and $4,937 of indirect expenses for the three and nine months ended September 30, 2012, respectively.  The Partnership reimbursed Martin Resource Management $1,042 and $3,126 of indirect expenses for the three and nine months ended September 30, 2011, 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 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 of the general partner’s board of directors. For purposes of the omnibus agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read “Services” above.

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

Amendment and Termination. The omnibus agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the conflicts committee of the Partnership’s general partner if such amendment would adversely affect the unitholders. The omnibus agreement was first amended on November 24, 2009, to permit the Partnership to provide refining services to Martin Resource Management.  The omnibus agreement was amended further on October 2, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.  See Note 16. Such amendments were approved by the conflicts committee of the Partnership’s general partner.  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, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations.  This agreement replaced a prior agreement effective November 1, 2002, between the Partnership and Martin Transport, Inc. for land transportation services.  Under the agreement, Martin Transport, Inc. agreed to ship our NGL shipments as well as other liquid products.

Term and Pricing. This agreement was amended in November 2006, January 2007, April 2007 and January 2008 to add additional point-to-point rates and to modify certain fuel and insurance surcharges being charged to the Partnership.  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.  Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustment which are mutually agreed 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.

Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin

22

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

Resource Management on a spot-contract basis at applicable market rates. This agreement replaced a prior agreement effective November 1, 2002 between the Partnership and Martin Resource Management covering marine transportation services which expired November 2005.  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.

Cross Marine Charter Agreements. Cross Oil & Refining Marketing, Inc. (“Cross”) entered into two marine charter agreements with the Partnership effective March 1, 2012.  These agreements have an initial term of five years and continue indefinitely thereafter subject to cancellation after the initial term by either party upon a 30 day written notice of cancellation. The charter hire payable under these agreements will be adjusted annually to reflect the percentage change in the Consumer Price Index.

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

Terminal Services Agreements

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

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

Other Agreements

 Cross Tolling Agreement. The Partnership is a party to an agreement under which it processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The Tolling Agreement has a 22 year term which expires November 25, 2031.   Under this Tolling Agreement, Martin Resource Management 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, Martin Resource Management agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement.  All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period.  In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. The Partnership is party to an agreement under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations.  This agreement, which was amended and restated in July 2011, will remain in place until the Partnership terminates it by providing 180 days’ written notice.  Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management.  Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

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

23

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

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 Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the consolidated financial statement and do not reflect a statement of profits and losses for related party transactions.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Revenues:
Terminalling and storage	$	18,531		$	14,210	$	48,611	$	40,045
Marine transportation	3,979			6,352		13,282		19,223
Product sales:
Natural gas services	(1		)	29		104		663
Sulfur services	1,469			1,537		4,829		6,358
Terminalling and storage	168			62		850		176
	1,636			1,628		5,783		7,197
	$	24,146		$	22,190	$	67,676	$	66,465

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

Cost of products sold:
Natural gas services	$	6,761	$	9,257	$	18,783	$	13,679
Sulfur services	4,111		4,762		12,512		13,407
Terminalling and storage	127		45		292		183
	$	10,999	$	14,064	$	31,587	$	27,269

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

Expenses:
Operating expenses
Marine transportation	$	7,236	$	8,631	$	21,217	$	21,412
Natural gas services	453		480		1,368		1,176
Sulfur services	1,494		1,901		4,796		4,803
Terminalling and storage	4,917		5,893		14,927		14,779
	$	14,100	$	16,905	$	42,308	$	42,170

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

Selling, general and administrative:
Marine transportation	$	15	$	19	$	47	$	49
Natural gas services	366		308		1,052		884
Sulfur services	737		1,004		2,183		2,285
Terminalling and storage	—		—		39		—
Indirect overhead allocation, net of reimbursement	1,646		1,042		4,937		3,126
	$	2,764	$	2,373	$	8,258	$	6,344

(10) Business Segments

24

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

The Partnership has four reportable segments: terminalling and storage, natural gas services, sulfur services and marine transportation. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

The accounting policies of the operating segments are the same as those described in Note 2 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all periods.  See Note 4.

25

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (loss) after eliminations			Capital Expenditures
Three Months Ended September 30, 2012
Terminalling and storage	$	45,667	$	(1,191	)	$	44,476	$	5,503	$	5,493		$	7,990
Natural gas services	190,738		—			190,738		149		3,270			143
Sulfur services	60,596		—			60,596		1,750		7,273			7,549
Marine transportation	22,879		(777		)	22,102		2,564		811			1,711
Indirect selling, general and administrative	—		—			—		—		(1,966		)	—
Total	$	319,880	$	(1,968	)	$	317,912	$	9,966	$	14,881		$	17,393
Three Months Ended September 30, 2011
Terminalling and storage	$	38,080	$	(1,174	)	$	36,906	$	4,829	$	3,457		$	14,360
Natural gas services	159,748		—			159,748		148		2,164			277
Sulfur services	70,169		—			70,169		1,676		5,921			2,598
Marine transportation	22,411		(1,638		)	20,773		3,372		(896		)	2,061
Indirect selling, general and administrative	—		—			—		—		(2,967		)	—
Total	$	290,408	$	(2,812	)	$	287,596	$	10,025	$	7,679		$	19,296
Nine Months Ended September 30, 2012
Terminalling and storage	$	130,131	$	(3,542	)	$	126,589	$	15,170	$	12,919		$	45,768
Natural gas services	527,666		—			527,666		436		6,457			410
Sulfur services	202,241		—			202,241		5,325		34,320			9,204
Marine transportation	65,912		(2,234		)	63,678		8,526		662			7,627
Indirect selling, general and administrative	—		—			—		—		(6,733		)	—
Total	$	925,950	$	(5,776	)	$	920,174	$	29,457	$	47,625		$	63,009
Nine Months Ended September 30, 2011
Terminalling and storage	$	115,492	$	(3,220	)	$	112,272	$	14,114	$	9,576		$	24,270
Natural gas services	423,953		—			423,953		435		5,598			581
Sulfur services	206,860		—			206,860		4,998		27,818			14,826
Marine transportation	63,201		(5,653		)	57,548		9,976		(5,143		)	9,092
Indirect selling, general and administrative	—		—			—		—		(6,547		)	—
Total	$	809,506	$	(8,873	)	$	800,633	$	29,523	$	31,302		$	48,769

The Partnership's assets by reportable segment, which exclude assets held for sale of $0 and $212,787, respectively, as of September 30, 2012 and December 31, 2011, are as follows:

26

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

	September 30, 2012		December 31, 2011
Total assets:
Terminalling and storage	$	161,544	$	231,764
Natural gas services	288,003		198,845
Sulfur services	258,712		162,289
Marine transportation	115,537		143,424
Total assets	$	823,796	$	736,322

(11) Long-Term Debt and Capital Leases

At September 30, 2012 and December 31, 2011, long-term debt consisted of the following:

	September 30, 2012		December 31, 2011
$200,000*** Senior notes, 8.875% interest, net of unamortized discount of $1,688 and $2,192, respectively, issued March 2010 and due April 2018, unsecured**	$	173,312	$	197,808
$400,000 Revolving loan facility at variable interest rate (3.72%* weighted average at September 30, 2012), due April 2016 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	77,000		250,000
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured by equipment	—		6,363
Capital lease obligations	5,871		6,031
Total long-term debt and capital lease obligations	256,183		460,202
Less current installments	217		1,261
Long-term debt and capital lease obligations, net of current installments	$	255,966	$	458,941

     * Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%.  The applicable margin for existing LIBOR borrowings is 3.00%.  Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%.  Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to floating rate.  The floating rate cost was the applicable three-month LIBOR rate.  This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to floating rate.  The floating rate cost was the applicable three-month LIBOR rate.  This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

*** Pursuant to the Indenture under which the Senior Notes were issued, the Partnership has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings.  On April 24, 2012, the Partnership notified the Trustee of its intention to exercise a partial redemption of the Partnership’s Senior Notes pursuant to the Indenture.  On May 24, 2012, the Partnership redeemed $25,000 of the Senior Notes from various holders using proceeds of the Partnership’s January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under the Partnership’s revolving credit facility.  In

27

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

conjunction with the redemption, the Partnership incurred a debt prepayment premium in the amount of $2,219, which is included in the consolidated and condensed statements of operations for the nine months ended September 30, 2012.

In August 2011, the Partnership terminated all of its existing interest rate swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes.  These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings.  The Partnership received a termination benefit of $2,800 upon cancellation of these swap agreements.

Effective May 10, 2012, the Partnership increased the maximum amount of borrowings and letters of credit available under the Credit Facility from $375,000 to $400,000.

The Partnership paid cash interest in the amount of $4,696 and $2,813 for the three months ended September 30, 2012 and 2011, respectively.  The Partnership paid cash interest in the amount of $19,039 and $6,662 for the nine months ended September 30, 2012 and 2011, respectively.  Capitalized interest was $175 and $127 for the three months ended September 30, 2012 and 2011, respectively.  Capitalized interest was $799 and $373 for the nine months ended September 30, 2012 and 2011, respectively.

(12) Equity Offering

On January 25, 2012, the Partnership completed a public offering of 2,645,000 common units at a price of $36.15 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 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91,361.  The Partnership’s general partner contributed $1,951 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership.  On January 25, 2012, all of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

On February 9, 2011, the Partnership completed a public offering of 1,874,500 common units at a price of $39.35 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 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70,330.  The Partnership’s general partner contributed $1,505 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership.  The net proceeds were used to reduce the outstanding balance under its revolving credit facility.

(13) Income Taxes

Because its income is taxed directly to its partners, the operations of a partnership are generally not subject to income taxes, except as discussed below.  Effective January 1, 2007, the Partnership became subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the consolidated statements of operations.

The Partnership’s taxable subsidiary, Woodlawn, is subject to income taxes due to its corporate structure. Income tax expense related to Woodlawn is recorded in discontinued operations.  A current state income tax expense of $568 and $574, related to Woodlawn was recorded for the three and nine months ended September 30, 2012. A current state income tax expense of $6 and $17 related to Woodlawn was recorded for the three and nine months ended September 30, 2011, respectively.  

A deferred tax benefit related to the Woodlawn basis differences of  $7,373 and $7,695 was recorded for the three and nine months ended September 30, 2012, respectively. A deferred tax expense of $33 and $2 was recorded for the three and nine months ended September 30, 2011, respectively.  A deferred tax (asset) liability of $(38) and $7,657 related to the basis differences existed at September 30, 2012 and December 31, 2011, respectively.

Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.  State income taxes attributable to the Texas margin tax of $238 and $810 were recorded in

28

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

current income tax expense in continuing operations for the three and nine months ended September 30, 2012 and $218 and $662 for the three and nine months ended September 30, 2011, respectively.

The components of income tax expense (benefit) from operations recorded for the three and nine months ended September 30, 2012 and 2011 are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	806			223			1,384			679
	6,609			206			7,191			690
Deferred:
Federal	(7,373		)	33			(7,695		)	2
Total income tax expense (benefit)	$	(764	)	$	239		$	(504	)	$	692

Total income tax expense was allocated to continuing and discontinued operations as follows:

Income tax expense (benefit) from continuing operations:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Current:
State	$	238	$	218	$	810	$	662
Total income tax expense from continuing operations	$	238	$	218	$	810	$	662

Income tax expense (benefit) from discontinued operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	568			6			574			17
	6,371			(11		)	6,381			28
Deferred:
Federal	(7,373		)	32			(7,695		)	2
Total income tax expense (benefit) from discontinued operations	$	(1,002	)	$	21		$	(1,314	)	$	30

(14) Commitments and Contingencies

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

On October 2, 2012, the Partnership announced that the ongoing litigation and disputes involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all the lawsuits and disputes referenced in this section. Accordingly, none of the following matters are currently pending and such information is being provided for reference only.

29

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

On May 2, 2008, the Partnership received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management.  In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment adverse to the Defendant which contained monetary damages and specific performance components (the “Judgment”).   The Defendant appealed the Judgment.  On November 3, 2010, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment.  The Appellate Court’s opinion rendered a take-nothing judgment against the Plaintiff and found in favor of the Defendant.  The Supreme Court of Texas denied the Plaintiff’s petition for review and therefore the opinion of the Sixth Appellate District of Texas at Texarkana has become final.

On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court (the “Harris County Litigation”) against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of the Partnership’s general partner. The Partnership is not a party to this lawsuit, and it does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations, or (iii) against the MRMC Director Defendants or other MRMC Defendants with respect to their service to the Partnership.

The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley M. Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Trust (the “ESOT”), and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares.  The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The case was abated in July 2009 during the pendency of a mandamus proceeding in the Texas Supreme Court. The Supreme Court denied mandamus relief on November 20, 2009.  This lawsuit was amended to add the ESOT as a party and was subsequently removed to Federal Court by the ESOT.  This lawsuit was remanded from Federal Court to the State District Court. The trial was previously set for August of 2012 but has been removed from the trial docket.  The trial is nonetheless stayed pending the outcome of procedural matters pending in the appellate courts.

The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against Scott Martin, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that he has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached fiduciary duties owed to Angela Jones Alexander, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, the Partnership has been informed that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above, Angela Jones Alexander amended her claims to include her grandmother, Margaret Martin, as a defendant, but subsequently dropped her claims against Mrs. Martin.  Additionally, all claims pertaining to Karen Yost have been resolved.  All claims pertaining to Defendant have been preliminarily resolved, as the court, on February 9, 2011, issued an order that granted the parties’ Joint Motion for Administrative Closure.  With respect to the lawsuit referenced in (i) above, the case was tried in October 2009 and the jury returned a verdict in favor of the Defendant’s daughters against Scott Martin in the amount of $4,900.  On December 22, 2009, the court entered a judgment, reflecting an amount consistent with the verdict and additionally awarded attorneys’ fees and interest. On January 7, 2010, the court modified its original judgment and awarded the Defendant’s daughters approximately $2,700 in damages and attorneys’ fees, plus interest. Scott Martin has appealed the

30

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

judgment.  On March 20, 2012, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment.  While the Appellate Court found that there was sufficient evidence to support the jury’s finding that a breach of fiduciary duty occurred, it found insufficient evidence to support any damages and therefore rendered a take-nothing judgment against the daughters of the Defendant.  A motion for rehearing at the Appellate Court was overruled on April 26, 2012.  The Defendant’s daughters have indicated they will appeal the Appellate Court’s ruling.

On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which the board of directors of Martin Resource Management determined was detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of the Partnership’s general partner. This position on the board of directors was filled on July 26, 2010, by Charles Henry “Hank” Still.

On February 22, 2010, as a result of the Harris County Litigation being derivative in nature, Martin Resource Management formed a special committee of its board of directors and designated such committee as the Martin Resource Management authority for the purpose of assessing, analyzing and monitoring the Harris County Litigation and any other related litigation and making any and all determinations in respect of such litigation on behalf of Martin Resource Management.  Such authorization includes, but is not limited to, reviewing the merits of the litigation, assessing whether to pursue claims or counterclaims against various persons or entities, assess whether to appoint or retain experts or disinterested persons to make determinations in respect of such litigation, and advising and directing Martin Resource Management’s general counsel and outside legal counsel with respect to such litigation.  The special committee consists of Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton.

On May 4, 2010, the Partnership received a copy of a petition filed in a new case with the District Clerk of Gregg County, Texas by Martin Resource Management against the Plaintiff and others with respect to certain matters relating to Martin Resource Management (“the Gregg County Matter”). As noted above, the Plaintiff was a former director of Martin Resource Management.  The lawsuit alleges that the Plaintiff with help from others breached the fiduciary duties the Plaintiff owed to Martin Resource Management.   The Partnership is not a party to the lawsuit, and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations, or (iii) against the Plaintiff with respect to his service as an officer or former director of the general partner of the Partnership. With respect to this lawsuit, the case was tried in January 2012 and the jury returned a verdict in favor of Martin Resource Management against Scott D. Martin for breach of fiduciary duty and awarded an amount of $1,800.  The court entered a judgment in favor of Martin Resource Management in the amount awarded by the jury plus interest.  Scott D. Martin is appealing this judgment.

Additionally, on July 11, 2011, Scott D. Martin sued Martin Resource Management in State District Court in Harris County, Texas, alleging that it tortiously interfered with his rights under an existing insurance policy.  A motion to transfer this case was granted and this case is currently pending in the 188th District Court of Gregg County, Texas.  

On June 22, 2012, the Partnership received from Scott D. Martin a demand that the Partnership indemnify him for legal fees and damages adjudged against him in the Gregg County Matter.  He followed this up with an additional demand that the Partnership indemnify him for legal fees and expenses he paid in defending the lawsuit brought in Gregg County, Texas by the daughters of the Defendant.  On June 25, 2012, the Partnership filed a petition in the District Court of Gregg County, Texas against Scott D. Martin, seeking a declaratory judgment regarding the Partnership’s obligations to indemnify Scott D. Martin.

31

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2012

(Unaudited)

(15) Consolidating Financial Statements

Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, has issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. The Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has no independent assets or operations, the guarantees are full and unconditional, and the other subsidiary of the Partnership is minor. There are no significant restrictions on the ability of the Partnership or the Operating Partnership to obtain funds from any of their respective subsidiaries by dividend or loan.

(16) Subsequent Events

Litigation Settlement. On October 2, 2012, the Partnership announced that the ongoing litigation and disputes as described in Note 14 involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all of the lawsuits and disputes referenced in Note 14. In connection with the settlement, Martin Resource Management transferred 1,500,000 common units of the Partnership to KCM, LLC, and Martin Resource Management now owns 5,093,267 common units of the Partnership.

Acquisition of Lubricant Packaging Assets. On October 2, 2012, the Partnership purchased certain specialty lubricant packaging assets from Cross Oil Refining & Marketing, Inc., a wholly-owned subsidiary of Martin Resource Management. The consideration consisted of $121,800 in cash, including working capital of approximately $36,800, subject to certain post-closing adjustments. The purchase was funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these packaging assets will be recorded at amounts based on the historical carrying value of the assets at the acquisition date, and we are required to revise our historical financial statements to include the activities of the packaging assets as of the date of common control. Our historical financial statements will be retrospectively revised to reflect the financial position, cash flows and results of operations attributable to these packaging assets as if we owned them for each period presented.

Acquisition of Redbird Class A Interests. On October 2, 2012, the Partnership acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150,000 in cash. Prior to the transaction, the Partnership owned a 10.74% Class A interest and a 100% Class B interest in Redbird. This transaction was also funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these interests will be recorded at amounts based on the historical carrying value of the interests at the acquisition date, and we are required to revise our historical financial statements to include the activities of the Class A interests as of the date of common control. Our historical financial statements will be retrospectively revised to reflect the financial position, cash flows and results of operations attributable to these packaging assets as if we owned them for each period presented.

Amendment No. 2 to Omnibus Agreement. In connection with the purchase of the Cross packaging assets, on October 2, 2012, the Partnership entered into Amendment No. 2 to the Partnership's omnibus agreement (the “Amendment”) with Martin Resource Management, the General Partner, and Martin Operating Partnership L.P. The Amendment allows the Partnership to provide certain products and services to Martin Resource Management under the Omnibus Agreement by amending the definition of the term “Business” to reflect the operation of the packaging assets acquired by the Partnership pursuant to the purchase agreement.

Amendment No. 3 to the Second Amendment and Restated Agreement of Limited Partnership. In conjunction with the Redbird purchase agreement, on October 2, 2012, the General Partner executed Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (“the Partnership Agreement”). The Partnership Agreement Amendment provides that the General Partner, currently the holder of the incentive distribution rights, shall not receive the next $18,000 in incentive distributions that it would otherwise be entitled to receive.

32

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

References in this quarterly report on Form 10-Q to “Martin Resource Management” refers to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires. You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated and condensed financial statements and the notes thereto included elsewhere in this quarterly report.

Forward-Looking Statements

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this quarterly report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue”, or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2011, filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2012, and in this report.

Overview

We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Our four primary business lines include:

• Terminalling and storage services for petroleum and by-products;

• Natural gas services;

• 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 Gulf Coast region of the United States. 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 hydrocarbon products and by-products and other bulk liquids. Martin Resource Management owns an approximate 28.0% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest in us and all of our incentive distribution rights.

33

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

Recent Developments

We believe one of the rationales driving investment in master limited partnerships, including us, is the opportunity for distribution growth offered by the partnerships. Such distribution growth is a function of having access to liquidity in the financial markets used for incremental capital investment (development projects and acquisitions) to grow distributable cash flow. Growth opportunities can be constrained by a lack of liquidity or access to the financial markets.  During 2011 and thus far in 2012, the financial markets were available to us.  As such, we were able to issue equity in February 2011 and January 2012 for the purpose of reducing outstanding indebtedness under our credit facility.  Our credit facility is our primary source of liquidity and was refinanced in April 2011.  Additionally, we upsized our credit facility in April 2011, December 2011, and May 2012.

Conditions in our industry continue to be challenging in 2012.  For example:

• Coupled with the general decline in drilling activity are the federal government’s enhanced safety regulations and inspection requirements as it relates to deep-water drilling in the Gulf of Mexico.  These enhanced safety regulations and inspection requirements of the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) continue to provide uncertainty surrounding the requirements for and pace of issuance of permits on the Gulf of Mexico Outer Continental Shelf (OCS). Although permits began to be issued by the BOEMRE again during first quarter 2011, they have not been approved in a timely manner consistent with pre-BP/Macondo spill levels.

Despite the industry challenges we have faced, we are positioning ourselves for continued growth.  In particular:

• We continue to adjust our business strategy to focus on maximizing our liquidity, maintaining a stable asset base, and improving the profitability of our assets by increasing their utilization while controlling costs.  Over the past year we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth.  Our goal over the next two years will be to increase growth capital expenditures primarily in our Terminalling and Storage and Sulfur Services segments.

• We continue to evaluate opportunities to enter into interest rate and commodity hedging transactions.  We believe these transactions can beneficially remove risks associated with interest rate and commodity price volatility.

• During this past year, we have experienced positive changing market dynamics in our Terminalling and Storage and Marine Transportation segments including activity associated with the rapidly developing basins such as the Eagle Ford shale in South Texas.

On July 31, 2012, we completed the sale of our East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas Systems I, L.P. (“Prism Gas”), our wholly-owned subsidiary, and other natural gas gathering and processing assets also owned by us to a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”). We received net cash proceeds from the sale of $273.3 million.  The asset sale includes our 50% operating interest in Waskom Gas Processing Company (“Waskom”).  A subsidiary of CenterPoint currently owns the other 50% percent interest.  

Additionally, on September 18, 2012, we completed the sale of our interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) to a private investor group for $1.5 million.

Acquisition of Lubricant Packaging Assets. On October 2, 2012, we purchased certain specialty lubricant packaging assets from Cross Oil Refining & Marketing, Inc., a wholly-owned subsidiary of Martin Resource Management. The consideration consisted of $121.8 million in cash, including working capital of approximately $36.8 million, subject to certain post-closing adjustments. The purchase was funded by borrowings under our revolving credit facility.

Acquisition of Redbird Class A Interests. On October 2, 2012, we acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150.0 million in cash. Prior to the transaction, we owned a 10.7% Class A

34

interest and a 100% Class B interest in Redbird. This transaction was also funded by borrowings under our revolving credit facility.  

Critical Accounting Policies

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 generally accepted accounting principles. The preparation of these financial statements required us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Our results may differ from these estimates. Currently, we believe that our accounting policies do not require us to make estimates using assumptions about matters that are highly uncertain. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 350 related to goodwill. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2011, and there have been no material changes to these policies through September 30, 2012.

Our Relationship with Martin Resource Management

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

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

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

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

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

• operating a lube oil processing facility in Smackover, Arkansas;

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

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

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

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

Ownership

Martin Resource Management owns an approximate 28.0% limited partnership interest and a 2% general partnership interest in us and all of our incentive distribution rights.

Management

Martin Resource Management directs our business operations through its ownership 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

35

We are a party to an omnibus agreement with Martin Resource Management. 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 $26.2 million of direct costs and expenses for the three months ended September 30, 2012 compared to $32.3 million for the three months ended September 30, 2011. We reimbursed Martin Resource Management for $77.2 million of direct costs and expenses for the nine months ended September 30, 2012 compared to $72.7 million for the nine months ended September 30, 2011. 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.   Effective October 1, 2011 through September 30, 2012, the Conflicts Committee of the board of directors of our general partner (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $6.6 million.  We reimbursed Martin Resource Management for $1.6 and $1.0 million of indirect expenses for the three months ended September 30, 2012 and 2011, respectively.  We reimbursed Martin Resource Management for $4.9 and $3.1 million of indirect expenses for the nine months ended September 30, 2012 and 2011, respectively.  These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical 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 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.

In addition to the omnibus agreement, we and Martin Resource Management have entered into various other agreements including, but not limited to, a motor carrier agreement, terminal services agreements, marine transportation agreements and other agreements for the provision of various goods and services.  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 – Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012.

Commercial

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

We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.4 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

In the aggregate, our purchases of land transportation services, NGL storage services, sulfuric acid and lube oil product purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 4% and 6% of our total cost of products sold during the three months ended September 30, 2012 and 2011, respectively and approximately 4% and 4% of our total cost of products sold for the nine months ended September 30, 2012 and 2011, 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. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for approximately 8% of our total revenues for both the three months ended September 30, 2012 and 2011.  Our sales to Martin Resource Management accounted for approximately 7% and 8% of our total revenues for the nine months ended September 30, 2012 and 2011, respectively. We provide terminalling and storage and marine transportation services to Martin Energy Services LLC and Martin Energy Services LLC provides terminal services to us to handle lubricants, greases and drilling fluids.

36

For a more comprehensive discussion concerning the agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions – Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012.

Approval and Review of Related Party Transactions

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee, as constituted under our limited partnership agreement. Certain related party transactions are required to be submitted to the Conflicts Committee. 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.

Results of Operations

The results of operations for the three and nine months ended September 30, 2012 and 2011 have been derived from our consolidated and condensed financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues.  The following table sets forth our operating revenues and operating income by segment for the three and nine months ended September 30, 2012 and 2011.  The results of operations for these interim periods during the year are not necessarily indicative of the results of operations which might be expected for the entire year.

The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all periods.

37

	Operating Revenues		Revenues Intersegment Eliminations			Operating Revenues  after Eliminations		Operating Income (loss)			Operating Income Intersegment Eliminations			Operating Income (loss)  after Eliminations
	(In thousands)
Three Months Ended September 30, 2012
Terminalling and storage	$	45,667	$	(1,191	)	$	44,476	$	6,148		$	(655	)	$	5,493
Natural gas services	190,738		—			190,738		2,876			394			3,270
Sulfur services	60,596		—			60,596		6,114			1,159			7,273
Marine transportation	22,879		(777		)	22,102		1,709			(898		)	811
Indirect selling, general and administrative	—		—			—		(1,966		)	—			(1,966		)
Total	$	319,880	$	(1,968	)	$	317,912	$	14,881		$	—		$	14,881
Three Months Ended September 30, 2011
Terminalling and storage	$	38,080	$	(1,174	)	$	36,906	$	3,810		$	(353	)	$	3,457
Natural gas services	159,748		—			159,748		1,793			371			2,164
Sulfur services	70,169		—			70,169		4,301			1,620			5,921
Marine transportation	22,411		(1,638		)	20,773		742			(1,638		)	(896		)
Indirect selling, general and administrative	—		—			—		(2,967		)	—			(2,967		)
Total	$	290,408	$	(2,812	)	$	287,596	$	7,679		$	—		$	7,679
Nine Months Ended September 30, 2012
Terminalling and storage	$	130,131	$	(3,542	)	$	126,589	$	14,882		$	(1,963	)	$	12,919
Natural gas services	527,666		—			527,666		5,302			1,155			6,457
Sulfur services	202,241		—			202,241		30,927			3,393			34,320
Marine transportation	65,912		(2,234		)	63,678		3,247			(2,585		)	662
Indirect selling, general and administrative	—		—			—		(6,733		)	—			(6,733		)
Total	$	925,950	$	(5,776	)	$	920,174	$	47,625		$	—		$	47,625
Nine Months Ended September 30, 2011
Terminalling and storage	$	115,492	$	(3,220	)	$	112,272	$	10,150		$	(574	)	$	9,576
Natural gas services	423,953		—			423,953		4,779			819			5,598
Sulfur services	206,860		—			206,860		22,430			5,388			27,818
Marine transportation	63,201		(5,653		)	57,548		490			(5,633		)	(5,143		)
Indirect selling, general and administrative	—		—			—		(6,547		)	—			(6,547		)
Total	$	809,506	$	(8,873	)	$	800,633	$	31,302		$	—		$	31,302

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

Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2011

38

Our total revenues before eliminations were $319.9 million for the three months ended September 30, 2012, compared to $290.4 million for the three months ended September 30, 2011, an increase of $29.5 million, or 10%. Our operating income before eliminations was $14.9 million for the three months ended September 30, 2012, compared to $7.7 million for the three months ended September 30, 2011, an increase of $7.2 million, or 94%.

The results of operations are described in greater detail on a segment basis below.

Terminalling and Storage Segment

The following table summarizes our results of operations in our terminalling and storage segment.

	Three Months Ended September 30,
	2012		2011
	(In thousands)
Revenues:
Services	$	25,066	$	20,555
Products	20,601		17,525
Total revenues	45,667		38,080
Cost of products sold	19,303		16,497
Operating expenses	14,373		12,891
Selling, general and administrative expenses	340		53
Depreciation and amortization	5,503		4,829
Operating income	$	6,148	$	3,810

Revenues.  Our terminalling and storage revenues increased $7.6 million, or 20%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.  Of the increase, $4.5 million is related to new terminalling assets commissioned in the second quarter of 2012 and fourth quarter of 2011. Product revenues increased $3.1 million compared to the prior year period. This increase is primarily related to a new trade agreement executed during the fourth quarter of 2011 with a customer operating out of our River Ridge location.

Cost of products sold.  Our cost of products increased $2.8 million, or 17%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. This increase is primarily related to a new trade agreement executed during the fourth quarter of 2011 with a customer operating out of our River Ridge location.

Operating Expenses. Operating expenses increased $1.5 million, or 12%, for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The increase in operating expenses is primarily due to having a full quarter of operations from new terminalling assets commissioned in the second quarter of 2012 and fourth quarter of 2011.

Selling, general and administrative expenses.  Selling, general, and administrative expenses increased $0.3 million for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.  This increase is related to an increase of $0.3 million in compensation expense.

Depreciation and amortization.  Depreciation and amortization increased $0.7 million, or 14%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011 resulting from capital expenditures made during the past twelve months.

In summary, our terminalling and storage operating income increased $2.4 million, or 61%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

Natural Gas Services Segment

The following table summarizes our results of operations in our natural gas services segment.

39

	Three Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	190,738	$	159,748
Cost of products sold	186,080		156,607
Operating expenses	847		762
Selling, general and administrative expenses	786		438
Depreciation and amortization	149		148
Operating income	$	2,876	$	1,793
NGLs Volumes (Bbls)	3,092		2,068

Revenues. Our natural gas services revenues increased $31.0 million, or 19% for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  NGL sales volumes for the three months of 2012 increased 50% compared to the same period of 2011, resulting in a positive impact on revenues of $62.4 million.  Our NGL average sales price per barrel for the three months ended September 30, 2012, decreased $15.60, or 20% compared to the same period of 2011, resulting in a decrease in revenue of $31.4 million.

Cost of products sold.   Our cost of products sold increased $29.5 million, or 19%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  The percentage increase in NGL cost of products sold was approximately the same as our percentage increase in NGL revenues, resulting in increased margins of 20% for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Operating expenses.  Operating expenses remained consistent for the three months ended September 30, 2012, as compared to the three months ended September 30, 2011.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $0.3 million, or 79%, for the three months ended September 30, 2012, as compared to the three months ended September 30, 2011.  This is primarily due to an increase in the reserve of an uncollectible customer receivable of $0.1 million and increased compensation expense of $0.2 million.

Depreciation and amortization. Depreciation and amortization remained consistent for the three months ended September 30, 2012, as compared to the three months ended September 30, 2011.

In summary, our natural gas services operating income increased $1.1 million, or 60%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Sulfur Services Segment

The following table summarizes our results of operations in our sulfur segment.

40

	Three Months Ended September 30,
	2012			2011
	(In thousands)
Revenues:
Services	$	2,926		$	2,850
Products	57,670			67,319
Total revenues	60,596			70,169
Cost of products sold	47,362			59,899
Operating expenses	4,357			4,930
Selling, general and administrative expenses	1,008			774
Depreciation and amortization	1,750			1,676
	6,119			2,890
Other operating income (loss)	(5		)	1,411
Operating income	$	6,114		$	4,301
Sulfur (long tons)	225.6			310.2
Fertilizer (long tons)	61.2			54.2
Sulfur services volumes (long tons)	286.8			364.4

Revenues.  Our total sulfur services revenues decreased $9.6 million, or 14%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. The decrease in products revenue was primarily a result of a 21% decline in volumes sold.

Cost of products sold.  Our cost of products sold decreased $12.5 million, or 21%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  The percentage decrease in sulfur services cost of products sold was higher than our percentage decrease in sulfur services revenues, resulting in an increase in our margin per ton of 77%. 

Operating expenses.  Our operating expenses decreased $0.5 million, or 12%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011. This was primarily a result of decreased outside towing expenses.

Selling, general and administrative expenses.   Selling, general and administrative expenses increased $0.2 million, or 30%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  This increase is related to an increase of $0.1 million in overhead allocation expense and $0.1 million in compensation expense.

Depreciation and amortization.  Depreciation and amortization expense increased $0.1 million, or 4%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Other operating income.  Other operating income decreased $1.4 million for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  This decrease relates to business interruption insurance recoveries from Hurricane Ike that were reimbursed in 2011.

In summary, our sulfur operating income increased $1.8 million, or 42%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.

Marine Transportation Segment

The following table summarizes our results of operations in our marine transportation segment.

41

	Three Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	22,879	$	22,411
Operating expenses	18,026		17,300
Selling, general and administrative expenses	580		1,306
Depreciation and amortization	2,564		3,372
	1,709		433
Other operating income	—		309
Operating income	$	1,709	$	742

Revenues.  Our marine transportation revenues increased $0.5 million, or 2%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  This increase was primarily a result of an increase in our offshore marine operations somewhat offset by a decrease in our inland marine operations.  Our offshore revenues increased $1.7 million, primarily due to increased utilization of the offshore fleet in 2012 of $1.1 million due to increased demand for our two offshore tows which operate in the spot market and an increase in ancillary charges of $0.6 million.  Our inland marine operations decreased $1.2 million, of which $1.3 million is attributed to decreased utilization of the inland fleet and $0.1 million in increased ancillary charges, primarily related to fuel.

Operating expenses.  Operating expenses increased $0.7 million, or 4%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  This increase in operating costs is primarily due to increases in fuel expense of $0.7 million, increased repairs and maintenance expense of $0.6 million, decreased outside towing expense of $0.3 million, and decreased barge cleaning and lease rental of $0.3 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased $0.7 million, or 56%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  This decrease was primarily related to a decrease in expense related to an uncollectible customer accounts receivable.

Depreciation and amortization.  Depreciation and amortization decreased $0.8 million, or 24%, for the three months ended September 30, 2012, compared to the three months ended September 30, 2011.  This decrease was primarily a result of a reduction in depreciation from disposal of equipment made in the last twelve months somewhat offset by capital expenditures made in the last twelve months.

In summary, our marine transportation operating income increased $1.0 million, or 130% for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

Our total revenues before eliminations were $926.0 million for the nine months endedSeptember 30, 2012 compared to $809.5 million for the nine months endedSeptember 30, 2011, an increase of $116.5 million, or 14%. Our operating income before eliminations was $47.6 million for the nine months endedSeptember 30, 2012 compared to $31.3 million for the nine months endedSeptember 30, 2011, an increase of $16.3 million, or 52%.

The results of operations are described in greater detail on a segment basis below.

Terminalling and Storage Segment

The following table summarizes our results of operations in our terminalling and storage segment.

42

	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Revenues:
Services	$	68,649	$	60,031
Products	61,482		55,461
Total revenues	130,131		115,492
Cost of products sold	57,733		52,277
Operating expenses	42,340		38,145
Selling, general and administrative expenses	401		229
Depreciation and amortization	15,170		14,114
	14,487		10,727
Other operating income (loss)	395		(577		)
Operating income	$	14,882	$	10,150

Revenues.  Our terminalling and storage revenues increased $14.6 million, or 13%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.  Of the increase in total revenues, $8.6 million is attributable to services revenue and $6.0 million pertains to product revenues. The increase in services revenue is primarily related to certain terminalling assets commissioned during the nine months of 2012 and the fourth quarter of 2011. Of the increase in product revenues, $9.8 million was due to the conversion of a consigned product delivery agreement with one of our customers during December 2011. This increase was offset by decreased revenues of $3.8 million from reduced sales volumes.

Cost of products sold.  Our cost of products sold increased $5.5 million, or 10%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.  Of this increase, $9.1 million was primarily due to the conversion of a consigned product delivery agreement with one of our customers during December 2011. The increase was offset by a $3.4 million decrease in cost of sales from reduced sales volumes.

Operating expenses. Operating expenses increased $4.2 million, or 11%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. Of this increase, $4.0 million was due primarily to increased operating expenses associated with certain terminalling assets commissioned during the nine months of 2012 and the fourth quarter of 2011.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $0.2 million, or 75%, for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011.  This is primarily due to increased compensation expense of $0.2 million.

Depreciation and amortization.  Depreciation and amortization increased $1.1 million, or 7%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.  The balance of the increase was a result of capital expenditures made during the past twelve months.

Other operating income.   Other operating income of $0.4 million for the nine months ended September 30, 2012 consisted of the final indemnity payment related to the sale of our Mont Belvieu facility in 2009.  Other operating income for the nine months ended September 30, 2011 includes a loss of $0.7 million on the disposition of certain property, plant and equipment at our terminal located in Corpus Christi, Texas.  The disposition was executed to facilitate the construction of a new crude terminal adjacent to our existing facility.  The loss was offset primarily by business interruption insurance recoveries of $0.1 million received during the second quarter of 2011.

In summary, our terminalling and storage operating income increased $4.7 million, or 47%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Natural Gas Services Segment

The following table summarizes our results of operations in our natural gas services segment.

43

	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	527,666	$	423,953
Cost of products sold	517,083		414,981
Operating expenses	2,603		2,249
Selling, general and administrative expenses	2,242		1,509
Depreciation and amortization	436		435
Operating income	$	5,302	$	4,779
NGLs Volumes (Bbls)	7,825		5,444

Revenues. Our natural gas services revenues increased $103.7 million, or 24% for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  Natural gas services volumes for the nine months of 2012 increased 44% compared to the same period of 2011, positively impacting revenues $160.0 million.  Our NGL average sales price per barrel for the nine months ended September 30, 2012, decreased $10.44, or 13% compared to the same period of 2011, resulting in an offsetting decrease to revenues of $56.3 million.

Cost of products sold.   Our cost of products sold increased $102.1 million, or 25%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  The percentage increase in NGL cost of products sold was slightly higher than our percentage increase in NGL revenues, resulting in decreased margins of $0.30 per barrel.

Operating expenses.  Operating expenses increased $0.4 million, or 16%, for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011.  This is primarily related to increased compensation expense of $0.1 million and increased pipeline maintenance expenses of $0.2 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $0.7 million, or 49%, for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011.  This is primarily due to an increase in the reserve of an uncollectible customer receivable of $0.4 million, increased compensation expense of $0.1 million, and increased property tax expense of $0.1 million.

Depreciation and amortization. Depreciation and amortization remained consistent for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011.

In summary, our natural gas services operating income increased $0.5 million, or 11%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.

Sulfur Services Segment

The following table summarizes our results of operations in our sulfur services segment.

44

	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Revenues:
Services	$	8,777		$	8,550
Products	193,464			198,310
Total revenues	202,241			206,860
Cost of products sold	149,853			164,414
Operating expenses	13,164			14,587
Selling, general and administrative expenses	2,945			2,517
Depreciation and amortization	5,325			4,998
	30,954			20,344
Other operating income (loss)	(27		)	2,086
Operating income	$	30,927		$	22,430
Sulfur (long tons)	861.8			998.7
Fertilizer (long tons)	238.7			201.2
Sulfur services volumes (long tons)	1,100.5			1,199.9

Revenues.  Our total sulfur services revenues decreased $4.7 million, or 2%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. The decrease in product revenue was primarily a result of an 8% decrease in our volumes sold, offset by a 6% increase in average sales price.

Cost of products sold.  Our cost of products sold decreased $14.5 million, or 9%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.  The percentage decrease in sulfur services cost of products sold was higher than our percentage decrease in sulfur services revenues, resulting in an increase in our margin per ton of 40%.  This decrease is also related to a decline in the market price of our sulfur products.

Operating expenses.  Our operating expenses decreased $1.4 million, or 10%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. This decrease was a result of decreased outside towing expenses of $1.4 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $0.4 million, or 17%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  This increase is related to an increase of $0.2 million in overhead allocation expense and $0.2 million in compensation expense.

Depreciation and amortization.  Depreciation and amortization expense increased $0.3 million, or 7%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. This increase is a result of capital expenditures made during the past twelve months.

Other operating income.  Other operating income decreased $2.1 million for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  This decrease consists of a $1.4 million received for the termination of a rail services agreement and $0.7 million for business interruption insurance recoveries from Hurricane Ike both occurring in 2011.

In summary, our sulfur services operating income increased $8.5 million, or 38%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Marine Transportation Segment

The following table summarizes our results of operations in our marine transportation segment.

45

	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Revenues	$	65,912	$	63,201
Operating expenses	52,773		50,831
Selling, general and administrative expenses	1,366		2,213
Depreciation and amortization	8,526		9,976
	3,247		181
Other operating income	—		309
Operating income	$	3,247	$	490

Revenues.  Our marine transportation revenues increased $2.7 million, or 4%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  This increase was primarily a result of an increase in our offshore marine operations, offset by a decrease in our inland marine operations. Our offshore revenues increased $5.6 million primarily due to increased utilization of the offshore fleet in 2012 of $4.5 million due to increased demand for our two offshore tows which operate in the spot market and an increase in ancillary charges of $1.1 million. Our inland marine operations decreased $2.9 million, of which $3.2 million is attributed to decreased utilization of the inland fleet offset by $0.3 million in increased ancillary charges, primarily related to fuel.

Operating expenses.  Operating expenses increased $1.9 million, or 4%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  This increase in operating costs is primarily due to an increase in fuel expense of $1.9 million, increased compensation expense of $0.9 million, and increased assist tug expense of $0.3 million.  These increases were offset by a decrease in outside towing expense of $1.3 million.  

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased $0.8 million, or 38%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  This decrease was primarily related to a decrease in expense related to an uncollectible customer receivable.

Depreciation and amortization.  Depreciation and amortization decreased $1.5 million, or 15%, for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011.  This decrease was primarily a result of disposal of equipment made in the last twelve months offset by capital expenditures made in the last twelve months.

In summary, our marine transportation operating income increased $2.8 million for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Equity in Earnings of Unconsolidated Entities

For the three and nine months ended September 30, 2012, equity in earnings of unconsolidated entities relates to our unconsolidated interests in Redbird, Caliber Gathering System, LLC, and Pecos Valley Producer Services LLC.  For the three and nine months ended September 30, 2011, equity in earnings of unconsolidated entities relates to our unconsolidated interest in Redbird.

Equity in earnings (loss) of unconsolidated entities remained consistent for the three months ended September 30, 2012 and 2011.

Equity in earnings (loss) of unconsolidated entities was $(0.5) million for the nine months ended September 30, 2012 compared to $0.1 million for the nine months ended September 30, 2011, a decrease of $0.6 million. This decrease is primarily related to Redbird’s share of a base gas liability adjustment during second quarter 2012.

Interest Expense

Our interest expense for all operations was $6.3 million for the three months ended September 30, 2012, compared to $4.3 million for the three months ended September 30, 2011, an increase of $2.0 million, or 46%.  This increase was primarily due to fees received related to the termination of all our interest rate swaps of $2.8 million during third quarter 2011.

46

Our interest expense for all operations was $21.7 million for the nine months ended September 30, 2012, compared to $17.1 million for the nine months ended September 30, 2011, an increase of $4.6 million, or 27%.  This increase was primarily due to fees received related to the termination of all our interest rate swaps of $2.8 million during third quarter 2011 and decreases in interest expense related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps.

In conjunction with the redemption of our senior notes, we incurred a debt prepayment premium in the amount of $2.2 million for the nine months ended September 30, 2012.

Indirect Selling, General and Administrative Expenses

Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses.  This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services.  Generally accepted accounting principles also permit 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 allocating these expenses.  Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

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.   Effective October 1, 2011 through September 30, 2012, the Conflicts Committee of the board of directors of our general partner (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $6.6 million.  We reimbursed Martin Resource Management for $1.6 and $1.0 million of indirect expenses for the three months ended September 30, 2012 and 2011, respectively.  We reimbursed Martin Resource Management $4.9 and $3.1 million of indirect expenses for the nine months ended September 30, 2012 and 2011, respectively.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

Indirect selling, general and administrative expenses were $1.6 million for the three months ended September 30, 2012 compared to $1.0 million for the three months ended September 30, 2011, an increase of $0.6 million, or 60% primarily due to an increase in allocated overhead expenses from Martin Resource Management.   Indirect selling, general and administrative expenses were $4.9 million for the nine months ended September 30, 2012 compared to $3.1 million for the nine months ended September 30, 2011, an increase of $1.8 million, or 58% primarily due to an increase in allocated overhead expenses from Martin Resource Management.

Liquidity and Capital Resources

General

Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private.  During 2012 and 2011, we completed several transactions that have improved our liquidity position.  In July 2012, we completed the sale of certain gas gathering and processing assets for approximately $273.3 million.  In January 2012, we received net proceeds of $91.4 million from a public offering of common units.  In February 2011, we received net proceeds of $70.3 million from a public offering of common units.  Additionally, we made certain strategic amendments to our credit facility which provides for a maximum borrowing capacity of $400 million under our revolving credit facility.

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

Our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks.  Please read “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012, as well as our updated risk factors contained in “Item 1A. Risk Factors” set forth elsewhere herein, for a discussion of such risks.

47

Debt Financing Activities

On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility.

On May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million.

On December 5, 2011, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $350.0 million to $375.0 million.

On September 7, 2011, we amended our revolving credit facility to (1) increase the maximum amount of investments made in permitted joint ventures to $50.0 million, and (2) increase the maximum amount of investments made in Redbird and Cardinal to $120.0 million.

On April 15, 2011, we amended our credit facility to (i) increase the maximum amount of borrowings and letters of credit under the Credit Agreement from $275.0 million to $350.0 million, (ii) extend the maturity date of all amounts outstanding under the Credit Agreement from March 15, 2013 to April 15, 2016, (iii) decrease the applicable interest rate margin on committed revolver loans under the Credit Agreement as described in more detail below, (iv) adjust the financial covenants as described in more detail below, (v) increase the maximum allowable amount of additional outstanding indebtedness of the borrower and the Partnership and certain of its subsidiaries as described in more detail below, and (vi) adjust the commitment fee incurred on the unused portion of the loan facility as described in more detail below.

Equity Offerings

On January 25, 2012, we completed a public offering of 2,645,000 common units at a price of $36.15 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 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91.4 million.  Our general partner contributed $2.0 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us.  On January 25, 2012, all of the net proceeds were used to reduce our outstanding indebtedness.

On February 9, 2011, we completed a public offering of 1,874,500 common units at a price of $39.35 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 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70.3 million.  Our general partner contributed $1.5 million in cash to us in conjunction with the issuance in order to maintain its 2% general partner interest in us.  On February 9, 2011, we made a $65.0 million payment to reduce the outstanding balance under our revolving credit facility.

Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2013.

Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks.  Please read “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012, as well as our updated risk factors contained in “Item 1A. Risk Factors” set forth elsewhere herein, for a discussion of such risks.

Cash Flows and Capital Expenditures

For the nine months ended September 30, 2012, cash decreased $0.2 million as a result of $18.0 million used in operating activities ($18.1 million used in continuing operating activities and $0.1 million provided by discontinued operating activities), $187.7 million provided by investing activities ($83.5 million used in continuing investing activities and $271.2 million provided by discontinued investing activities) and $170.0 million used in financing activities. For the nine months ended September 30, 2011, cash decreased $11.1 million as a result of $57.8 million provided by operating activities ($45.6 million from continuing operating activities and $12.3 million provided by discontinued operating activities), $135.3 million used in investing activities ($127.0 million used in continuing investing activities and $8.3 million used in discontinued investing activities), and $66.4 million provided by financing activities.

48

For the nine months ended September 30, 2012, our cash flows used in continuing investing activities of $83.5 million consisted of capital expenditures, payments for plant turnaround costs, return of investments from unconsolidated entities, contributions to unconsolidated entities, proceeds from the sale of equity method investment, and proceeds from the sale of property, plant, and equipment.  For the nine months ended September 30, 2012, our cash flows provided by discontinued investing activities of $271.2 million consisted of proceeds from the sale of the Prism Assets, capital expenditures, return of investments from unconsolidated entities and contributions to unconsolidated entities.  For the nine months ended September 30, 2011, our cash flows used in continuing investing activities of $127.0 million consisted of capital expenditures, payments for turnaround costs, investments in other long-term assets, return of investments from unconsolidated entities and contributions to unconsolidated entities.  For the nine months ended September 30, 2011, our cash flows used in discontinued investing activities of $8.3 million consisted of capital expenditures, return of investments from unconsolidated entities and contributions to unconsolidated entities.

Generally, our capital expenditure requirements have consisted, and we expect that our capital requirements will continue to consist, of:

• maintenance capital expenditures, which are capital expenditures made to replace assets to maintain our existing operations and to extend the useful lives of our assets; and

• expansion capital expenditures, which are capital expenditures made to grow our business, to expand and upgrade our existing terminalling, marine transportation, storage and manufacturing facilities, and to construct new terminalling facilities, plants, storage facilities and new marine transportation assets.

For the nine months ended September 30, 2012 and 2011, our capital expenditures for property and equipment in continuing investing activities were $63.0 million and $48.8 million, respectively.  For the nine months ended September 30, 2012 and 2011, our capital expenditures for property and equipment in discontinued investing activities were $1.1 million and $0.9 million, respectively.

As to each period:

• For the nine months ended September 30, 2012, we spent $59.4 million for expansion capital expenditures and $3.6 million for maintenance capital expenditures related to continuing operations. Our expansion capital expenditures were made in connection with construction projects associated with our terminalling and sulfur services segments. Our maintenance capital expenditures were primarily made in our sulfur services segment for routine improvements on the facilities as well as marine transportation segment dry dockings of our vessels pursuant to the United States Coast Guard requirements.  For the nine months ended September 30, 2012, we spent $0.6 million for expansion capital expenditures and $0.5 million for maintenance capital expenditures related to discontinued investing activities.

• For the nine months ended September 30, 2011, we spent $39.4 million for expansion capital expenditures and $9.4 million for maintenance capital expenditures related to continuing operations. Our expansion capital expenditures were made in connection with construction projects associated with our terminalling and sulfur services segments. Our maintenance capital expenditures were primarily made in our sulfur services segment for routine improvements on the facilities as well as marine transportation segment dry dockings of our vessels pursuant to the United States Coast Guard requirements.  For the nine months ended September 30, 2011, we spent $0.2 million for expansion capital expenditures and $0.7 million for maintenance capital expenditures related to discontinued investing activities.

For the nine months ended September 30, 2012, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $58.3 million, payments of long term debt to financial lenders of $547.0 million, payments of notes payable and capital lease obligations of $6.5 million, borrowings of long-term debt under our credit facility of $349.0 million, payments of debt issuance costs of $0.2 million, proceeds from a public offering of $91.4 million, purchase of treasury stock of $0.2 million and general partner contributions of $1.9 million.

For the nine months ended September 30, 2011, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $48.0 million, payments of long-term debt to financial lenders of $389.0 million, payments of notes payable and capital lease obligations of $0.8 million, borrowings of long-term debt under our credit facility of $456.0 million, excess purchase price over carrying value of acquired assets of $19.7 million, payments of debt issuance

49

costs of $3.4 million, proceeds from a public offering of $70.3 million, purchase of treasury stock of $0.6 million and general partner contributions of $1.5 million.

With respect to continuing investing activities, we made contributions to unconsolidated entities for operations of $22.8 million and $1.0 million during the nine months ended September 30, 2012 and 2011, respectively.  We made initial investments in unconsolidated entities of $0.8 million and $59.3 million during the nine months ended September 30, 2012 and 2011, respectively.  Additionally, we received distributions from unconsolidated entities of $5.1 million and $0.4 million during the nine months ended September 30, 2012 and 2011, respectively.

With respect to discontinued investing activities, we made contributions to unconsolidated entities for operations of $3.1 million and $8.7 million during the nine months ended September 30, 2012 and 2011, respectively.  Additionally, we received distributions from unconsolidated entities of $0.4 million and $1.3 million during the nine months ended September 30, 2012 and 2011, respectively.

The net investment in unconsolidated entities includes $3.1 million and $7.1 million of expansion capital expenditures in the nine months ended September 30, 2012 and 2011, respectively.

With respect to discontinued operating activities, we received distributions in-kind from unconsolidated entities of $6.4 million and $9.0 million during the nine months ended September 30, 2012 and 2011, respectively.

Capital Resources

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

As of September 30, 2012, we had $256.2 million of outstanding indebtedness, consisting of outstanding borrowings of $173.3 million (net of unamortized discount) under our Senior Notes, $77.0 million under our revolving credit facility, and $5.9 million under capital lease obligations.

Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of September 30, 2012, is as follows (dollars in thousands):

	Payments due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Revolving credit facility	$	77,000	$	—	$	—	$	77,000	$	—
Senior unsecured notes	173,312		—		—		—		173,312
Capital leases including current maturities	5,873		217		608		5,048		—
Non-competition agreements	100		50		50		—		—
Throughput commitment	49,938		4,384		9,981		10,632		24,941
Operating leases	47,201		9,979		24,103		7,379		5,740
Interest expense: ¹
Revolving credit facility	10,126		2,863		5,726		1,537		—
Senior unsecured notes	86,715		15,531		31,062		31,062		9,060
Capital leases	3,346		921		1,713		712		—
Total contractual cash obligations	$	453,611	$	33,945	$	73,243	$	133,370	$	213,053

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

Letter of Credit.  At September 30, 2012, we had outstanding irrevocable letters of credit in the amount of $0.1 million, which were issued under our revolving credit facility.

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

50

Description of Our Long-Term Debt

Senior Notes

We and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of us (collectively, the “Issuers”), entered into (i) a Purchase Agreement, dated as of March 23, 2010 (the “Purchase Agreement”), by and among the Issuers, certain subsidiary guarantors (the “Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets Corporation and UBS Securities LLC, as representatives of a group of initial purchasers (collectively, the “Initial Purchasers”), (ii) an Indenture, dated as of March 26, 2010 (the “Indenture”), among the Issuers, the Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”) and (iii) a Registration Rights Agreement, dated as of March 26, 2010 (the “Registration Rights Agreement”), among the Issuers, the Guarantors and the Initial Purchasers, in connection with a private placement to eligible purchasers of $200 million in aggregate principal amount of the Issuers’ 8.875% senior unsecured notes due 2018 (the “Senior Notes”).  We completed the aforementioned Senior Notes offering on March 26, 2010 and received proceeds of approximately $197.2 million, after deducting initial purchaser discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility.

In connection with the issuance of the Senior Notes, all “non-issuer” wholly-owned subsidiaries issued full, irrevocable, and unconditional guarantees of the Senior Notes.  We do not provide separate financial statements of the operating partnership because it has no independent assets or operations, the guarantees are full and unconditional, and our other subsidiary is minor.

Indenture

Interest and Maturity.  On March 26, 2010, the Issuers issued the Senior Notes pursuant to the Indenture in a transaction exempt from registration requirements under the Securities Act. The Senior Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Senior Notes will mature on April 1, 2018. The interest payment dates are April 1 and October 1.

Optional Redemption.  Prior to April 1, 2013, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the Senior Notes issued under the Indenture at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the Senior Notes with the proceeds of certain equity offerings. Prior to April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on April 1, 2014, 102.219% for the 12-month period beginning on April 1, 2015 and 100.00% for the 12-month period beginning on April 1, 2016, and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Senior Notes.

On April 24, 2012 we notified the Trustee of our intention to exercise a partial redemption of the our Senior Notes pursuant to the Indenture.  On May 24, 2012, we redeemed $25.0 million of the Senior Notes from various holders using proceeds of our January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under our revolving credit facility.

Certain Covenants.  The Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in its subsidiaries; (ii) pay distributions on, redeem or repurchase its units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate.

Events of Default.  The Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the Senior Notes; (ii) default in payment when due of the principal of, or premium, if any, on the Senior Notes; (iii) our failure to comply with certain covenants relating to asset sales, repurchases of the Senior Notes upon a change of control and mergers or consolidations; (iv) our failure, for 180 days after notice, to comply with its reporting

51

obligations under the Securities Exchange Act of 1934; (v) our failure, for 60 days after notice, to comply with any of the other agreements in the Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by us or any of our restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20 million or more, subject to a cure provision; (vii) our or any of our restricted subsidiaries failure to pay final judgments aggregating in excess of $20 million, which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a continuing Event of Default, the Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding Senior Notes, by notice to the Issuers and the Trustee, may declare the Senior Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the Senior Notes to become due and payable.

Registration Rights Agreement.   Under the Registration Rights Agreement, the Issuers and the Guarantors filed with the SEC a registration statement to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act.   We exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018.

Credit Facility

On November 10, 2005, we entered into a $225.0 million multi-bank credit facility, which has subsequently been amended, including most recently on September 7, 2011, when we amended our credit facility to, (1) increase the maximum amount of investments made in permitted joint ventures to $50.0 million, and (2) increase the maximum amount of investments made in Redbird and Cardinal to $120.0 million.  Effective May 10, 2012, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $375.0 million to $400.0 million.   

As of September 30, 2012, we had approximately $77.0 million outstanding under the revolving credit facility and $0.1 million of letters of credit issued, leaving approximately $322.9 million available under our credit facility for future revolving credit borrowings and letters of credit.

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 current fiscal year, draws on our credit facility have ranged from a low of $35.0 million to a high of $309.0 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.  We used the proceeds from our disposition of the Prism Assets to pay down outstanding indebtedness.  

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 which ranges from 0.375% to 0.50% per annum on the unused revolving credit availability under the credit facility. The letter of credit fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the new 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:

52

Leverage Ratio	Base Rate Loans		Eurodollar Rate Loans		Letters of Credit
Less than 2.25 to 1.00	1.00	%	2.00	%	2.00	%
Greater than or equal to 2.25 to 1.00 and less than 3.00 to 1.00	1.25	%	2.25	%	2.25	%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00	1.50	%	2.50	%	2.50	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00	1.75	%	2.75	%	2.75	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00	2.00	%	3.00	%	3.00	%
Greater than or equal to 4.50 to 1.00	2.25	%	3.25	%	3.25	%

The applicable margin for existing LIBOR borrowings is 3.00%.  Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%.  Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.

The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter.  The maximum permitted leverage ratio is 5.00 to 1.00.  The maximum permitted senior leverage ratio (as defined in the new credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.25 to 1.00.  The minimum consolidated interest coverage ratio (as defined in the new credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.75 to 1.00.

In addition, the credit facility contains various covenants that, among other restrictions, limit our and our subsidiaries’ ability to:

• grant or assume liens;

• make investments (including investments in our joint ventures) and acquisitions;

• enter into certain types of hedging agreements;

• incur or assume indebtedness;

• sell, transfer, assign or convey assets;

• 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;

• change the nature of our business;

• engage in transactions with affiliates;

• enter into certain burdensome agreements;

• make certain amendments to the omnibus agreement and our material agreements;

• make capital expenditures; and

• permit our joint ventures to incur indebtedness or grant certain liens. 

Each of the following will be an event of default under the credit facility:

• failure to pay any principal, interest, fees, expenses or other amounts when due;

• failure to meet the quarterly financial covenants;

53

• 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;

• the failure of any representation or warranty to be materially true and correct when made;

• our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount;

• bankruptcy or other insolvency events involving us or any of our subsidiaries;

• judgments against us or any of our subsidiaries, in excess of a threshold amount;

• certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount;

• a change in control (as defined in the credit facility);

• the termination of any material agreement or certain other events with respect to material agreements;

• the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral; and

• any of our joint ventures incurs debt or liens in excess of a threshold amount.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, or if Ruben Martin is not the chief executive officer of our general partner and a successor acceptable to the administrative agent and lenders providing more than 50% of the commitments under our credit facility is not appointed, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, either a bankruptcy event with respect to Martin Resource Management or a judgment with respect to Martin Resource Management 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.  Any event of default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations as well as our ability to make distributions to unitholders.

If any default occurs under our credit facility, or if we are unable to make any of the representations and warranties in the credit facility, we will be unable to borrow funds or have letters of credit issued under our credit facility.

As of November 5, 2012, our outstanding indebtedness includes $355.0  million under our credit facility.

We are subject to interest rate risk on our credit facility and may enter into interest rate swaps to reduce this risk.

Effective September 2010, we entered into an interest rate swap that swapped $40 million of fixed rate to floating rate.  The floating rate cost is the applicable three-month LIBOR rate.  This interest rate swap was not accounted for using hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.

Effective September 2010, we entered into an interest rate swap that swapped $60 million of fixed rate to floating rate.  The floating rate cost is the applicable three-month LIBOR rate.  This interest rate swap was not accounted for using hedge accounting. This swap was scheduled to mature in April 2018, but was terminated in August 2011.

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. The demand for fertilizers is strongest during the early spring planting season. However, our terminalling and

54

storage and marine transportation businesses and the molten sulfur business are typically not impacted by seasonal fluctuations. We expect to derive a majority of our net income 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 businesses.

Impact of Inflation

Inflation did not have a material impact on our results of operations for the three and nine months ended September 30, 2012 and 2011.  Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies.  In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses.  An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the three and nine months ended September 30, 2012 or 2011.

55

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 3.35% as of September 30, 2012.  As of November 5, 2012, we had total indebtedness outstanding under our credit facility of $355.0 million, all of which was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on September 30, 2012, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $3.6 million annually.

We are not exposed to changes in interest rates with respect to our Senior Notes as these obligations are fixed rate.  The estimated fair value of the Senior Notes was approximately $189.6 million as of September 30, 2012, based on market prices of similar debt at September 30, 2012.   Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately an $5.8 million decrease in fair value of our long-term debt at September 30, 2012.

56

Item 4. Controls and Procedures

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

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

57

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 14 in Part I of this Form 10-Q and in Item 5 below.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in our annual report on Form 10-K filed with the SEC on March 5, 2012.

Item 5. Other Information

Certain Other Information. On October 2, 2012, we announced that the ongoing litigation and disputes involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all of the lawsuits and disputes referenced in Note 14 and below. Accordingly, none of the following matters are currently pending and such information is being provided for reference only. In connection with the settlement, Martin Resource Management transferred 1,500,000 of our common units to KCM, LLC.

Litigation Settlement. On October 2, 2012, the Partnership announced that the ongoing litigation and disputes as described in Note 14 and below involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all of the lawsuits and disputes referenced in this section. Accordingly, none of the following matters are currently pending and the information provided in Note 14 and below is for reference only.

On May 2, 2008, we received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management.  In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment adverse to the Defendant which contained monetary damages and specific performance components (the “Judgment”).   The Defendant appealed the Judgment.  On November 3, 2010, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment.  The Appellate Court’s opinion rendered a take-nothing judgment against the Plaintiff and found in favor of the Defendant.  The Supreme Court of Texas denied the Plaintiff’s petition for review and therefore the opinion of the Sixth Appellate District of Texas at Texarkana has become final.

On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court (the “Harris County Litigation”) against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of our general partner.  We are not a party to this lawsuit, and it does not assert any claims (i) against us, (ii) concerning our governance or operations, or (iii) against the MRMC Director Defendants or other MRMC Defendants with respect to their service to us.

The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley M. Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Trust (the “ESOT”), and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares.  The SDM Plaintiffs have amended their Petition to eliminate

58

their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The case was abated in July 2009 during the pendency of a mandamus proceeding in the Texas Supreme Court. The Supreme Court denied mandamus relief on November 20, 2009.  This lawsuit was amended to add the ESOT as a party and was subsequently removed to Federal Court by the ESOT.  This lawsuit was remanded from Federal Court to the State District Court.  The trial was previously set for August 2012 but has been removed from the trial docket.  The trial is nonetheless stayed pending the outcome of procedural matters pending in the appellate courts.

The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against Scott Martin, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that he has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached fiduciary duties owed to Angela Jones Alexander, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, we have been informed that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above, Angela Jones Alexander amended her claims to include her grandmother, Margaret Martin, as a defendant, but subsequently dropped her claims against Mrs. Martin.  Additionally, all claims pertaining to Karen Yost have been resolved.  All claims pertaining to Defendant have been preliminarily resolved, as the court, on February 9, 2011, issued an order that granted the parties’ Joint Motion for Administrative Closure.  With respect to the lawsuit referenced in (i) above, the case was tried in October 2009 and the jury returned a verdict in favor of the Defendant’s daughters against Scott Martin in the amount of $4,900.  On December 22, 2009, the court entered a judgment, reflecting an amount consistent with the verdict and additionally awarded attorneys’ fees and interest. On January 7, 2010, the court modified its original judgment and awarded the Defendant’s daughters approximately $2,700 in damages and attorneys’ fees, plus interest. Scott Martin has appealed the judgment.  On March 20, 2012, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment.  While the Appellate Court found that there was sufficient evidence to support the jury’s finding that a breach of fiduciary duty occurred, it found insufficient evidence to support any damages and therefore rendered a take-nothing judgment against the daughters of the Defendant.  A motion for rehearing at the Appellate Court was overruled on April 26, 2012.  The Defendant’s daughters have indicated they will appeal the Appellate Court’s ruling.

On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which the board of directors of Martin Resource Management determined was detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of our general partner. The position on the board of directors of the Partnership’s general partner vacated by the Plaintiff may be filled in accordance with the existing procedures for replacement of a departing director utilizing the Nominations Committee of the board of directors of the general partner of the Partnership. This position on the board of directors has been filled as of July 26, 2010, by Charles Henry “Hank” Still.

On February 22, 2010, as a result of the Harris County Litigation being derivative in nature, Martin Resource Management formed a special committee of its board of directors and designated such committee as the Martin Resource Management authority for the purpose of assessing, analyzing and monitoring the Harris County Litigation and any other related litigation and making any and all determinations in respect of such litigation on behalf of Martin Resource Management.  Such authorization includes, but is not limited to, reviewing the merits of the litigation, assessing whether to pursue claims or counterclaims against various persons or entities, assess whether to appoint or retain experts or disinterested persons to make determinations in respect of such litigation, and advising and directing Martin Resource Management’s general counsel and outside legal counsel with respect to such litigation.  The special committee consists of Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton.

On May 4, 2010, we received a copy of a petition filed in a new case with the District Clerk of Gregg County, Texas by Martin Resource Management against the Plaintiff and others with respect to certain matters relating to Martin Resource Management (“the “Gregg County Matter”). As noted above, the Plaintiff was a former director of Martin Resource Management.  The lawsuit alleges that the Plaintiff with help from others breached the fiduciary duties the Plaintiff owed to Martin Resource Management.   We are not a party to the lawsuit, and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning our governance or operations, or (iii) against the Plaintiff with respect to his service as an officer or former director of the general partner of the Partnership. With respect to this lawsuit, the case was tried in January 2012 and the jury returned a verdict in favor of Martin Resource Management against Scott D. Martin for breach of fiduciary duty and

59

awarded an amount of $1,800.  The court entered a judgment in favor or Martin Resource Management in the amount awarded by the jury plus interest.  Scott D. Martin is appealing this judgment.

Additionally, on July 11, 2011, Scott D. Martin sued Martin Resource Management in State District Court in Harris County, Texas, alleging that it tortiously interfered with his rights under an existing insurance policy.  A motion to transfer this case was granted and this case is currently pending in 188^th District Court of Gregg County, Texas.

On June 22, 2012, we received from Scott D. Martin a demand that we indemnify him for legal fees and damages adjudged against him in the Gregg County Matter.  He followed this up with an additional demand that we indemnify him for legal fees and  expenses he paid in defending the lawsuit brought in Gregg County, Texas by the daughters of the Defendant.  On June 25, 2012, we filed a petition in the District Court of Gregg County, Texas against Scott D. Martin, seeking a declaratory judgment regarding the Partnership’s obligations to indemnify Scott D. Martin.

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.

60

SIGNATURES

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

	Martin Midstream Partners L.P.
	By:	Martin Midstream GP LLC
		It’s General Partner
Date:  November 5, 2012		By:	/s/ Ruben S. Martin
			Ruben S. Martin
			President and Chief Executive Officer

61

INDEX TO EXHIBITS

Exhibit Number	Exhibit Name
3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.2	Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 25, 2009 (filed as Exhibit 10.1 to the Partnership’s Amendment to Current Report on Form 8-K/A, filed January 19, 2010, and incorporated herein by reference).
3.3	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed February 1, 2011, and incorporated herein by reference).
3.4	Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
3.5	Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.6	Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
3.7	Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.8	Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 33-91706), filed July 1, 2002, and incorporated herein by reference).
3.9	Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.1	Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
4.1	Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
4.2	Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
4.3	Indenture, dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed March 26, 2010, and incorporated herein by reference).
4.4	Registration Rights Agreement, dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 4.2 to the Partnership’s Current Report on Form 8-K, filed March 26, 2010, and incorporated herein by reference).
10.1	Commitment Increase and Joinder Agreement dated May 10, 2012 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 10, 2012 and incorporated herein by reference).
10.2	Membership Interests Purchase Agreement dated October 2, 2012 by and among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Martin Underground Storage, Inc. and Martin Resource Management Corporation (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
10.3	Purchase Price Reimbursement Agreement dated October 2, 2012 by Martin Resource Management Corporation to and for the benefit of Martin Operating Partnership L.P. (filed as Exhibit 10.2 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
10.4	Asset Purchase Agreement, dated October 2, 2012, by and among Martin Operating Partnership L.P., Martin Midstream Partners L.P., Cross Oil Refining & Marketing, Inc. and Martin Resource Management Corporation (filed as Exhibit 10.3 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).
10.5	Amendment No. 2 to Omnibus Agreement dated October 1, 2012, by Martin Resource Management Corporation, Martin Midstream GP, LLC, Martin Midstream Partners L.P., and Martin Operating Partnership L.P. (filed as Exhibit 10.4 to the Partnership's Current Report on Form 8-K, filed October 9, 2012, and incorporated herein by reference).

62

10.6*	Second Amended and Restated LLC Agreement of Redbird Gas Storage LLC, dated as of October 2, 2012.
10.7*	Supply Agreement dated as of October 2, 2012 by and between the Partnership and Cross Oil & Refining Marketing Inc.
10.8*	Noncompetition Agreement dated as of October 2, 2012 by and among the Partnership, Cross Oil Refining & Marketing Inc., and Martin Resource Management Corporation.
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.  Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.  Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2012, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; (5) the Consolidated Statements of Other Comprehensive Income; and (6) the Notes to Consolidated Financial Statements.

* Filed or furnished herewith

63

EX-10.6

EXHIBIT 10.6

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

REDBIRD GAS STORAGE LLC

a Delaware Limited Liability Company

October 2, 2012

THE MEMBERSHIP INTERESTS REPRESENTED BY THIS AGREEMENT HAVE NOT BEEN REGISTERED UNDER ANY SECURITIES LAWS AND MAY NOT BE SOLD, PLEDGED OR OTHERWISE TRANSFERRED ABSENT SUCH REGISTRATION OR AN EXEMPTION THEREFROM. THE TRANSFER OF MEMBERSHIP INTERESTS IS FURTHER RESTRICTED BY ARTICLE X OF THIS AGREEMENT.

i

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS1

1.1. Defined Terms1

1.2. Other Definitions5

1.3. Usage6

ARTICLE II ORGANIZATIONAL MATTERS6

2.1. Formation6

2.2. Name6

2.3. Registered Office and Agent7

2.4. Term7

2.5. Purposes7

2.6. Powers7

2.7. Company Property7

2.8. Consent to Admission of Members7

2.9. Status of Manager and Members7

2.10. Certificates of Membership Interests7

2.11. No State Law Partnership7

2.12. Subsidiaries8

ARTICLE III CAPITAL CONTRIBUTIONS; CAPITAL ACCOUNTS8

3.1. Initial Capital Contributions8

3.2. Additional Capital Contributions8

3.3. Capital Accounts9

3.4. No Right to Return of or Interest on Capital Account9

3.5. Member Loans9

ARTICLE IV ALLOCATIONS AND DISTRIBUTIONS9

4.1. Allocation of Profit or Loss9

4.2. Distributions of Distributable Cash9

4.3. Withholding10

4.4. Limitation on Distributions10

4.5. No Right to Partition or Distributions in Kind10

4.6. Recovery of Erroneous Distributions10

ARTICLE V MANAGEMENT11

5.1. Management and Control of Company Business11

5.2. Delegation of Authority11

5.3. Limitations on Manager Authority11

5.4. Reliance13

5.5. Compensation and Expenses of Members and Manager13

5.6. Standards of Manager and Member Conduct14

5.7. Resignation, Removal, and Replacement of Manager14

ARTICLE VI LIABILITY AND INDEMNIFICATION16

6.1. Limitation of Liability16

6.2. Indemnification by Company16

6.3. Conduct Not Protected17

6.4. Insurance17

6.5. Survival17

ARTICLE VII BOOKS AND RECORDS; REPORTS17

7.1. Maintenance of and Access to Books and Records17

7.2. Fiscal Year18

7.3. Financial, Operating Reports and Inspection Rights18

7.4. Tax Reports18

7.5. Transmission of Communications19

ARTICLE VIII TAX MATTERS19

8.1. Tax Classification19

8.2. Company Returns19

8.3. Tax Elections19

8.4. Consistent Reporting19

8.5. Tax Proceedings20

8.6. Information and Documents to Company20

8.7. Survival20

ARTICLE IX MEETINGS AND VOTING OF MEMBERS20

9.1. Meetings20

9.2. Voting21

ARTICLE X TRANSFER OF MEMBERSHIP INTERESTS            21

10.1. Limitation on Transfers21

10.2. Permitted Transfer of Membership Interest21

10.3. Conditions to Permitted Transfers of Membership Interests22

10.4. Effective Date; Distributions22

10.5. Transferor's Obligations23

10.6. Assignee's Rights and Obligations23

10.7. Effect and Consequences of Prohibited Transfer23

ARTICLE XI ADMISSION OF NEW MEMBERS24

11.1. Substituted Members24

11.2. Additional Members24

11.3. No Required Capital Contributions24

11.4. Amendments to Exhibit A24

ARTICLE XII CONVERSION of Class B Interests24

ARTICLE XIII RESIGNATION OR REMOVAL OF MEMBERS25

13.1. Resignation of Members25

13.2. Removal of Members26

13.3. Status of Former Member26

ARTICLE XIV DISSOLUTION26

14.1. Events Requiring Dissolution or Winding Up            26

14.2. Winding Up Procedures27

14.3. Continuation Without Winding Up27

14.4. Liquidation of Assets and Application and Distribution of Proceeds28

14.5. Certificate of Cancellation28

ARTICLE XV VALUATION29

15.1. Fair Value of Company Property29

15.2. Fair Value of Membership Interests29

ARTICLE XVI GENERAL PROVISIONS30

16.1. Amendments30

16.2. Notice30

16.3. Governing Law; Consent to Jurisdiction30

16.4. Waiver31

16.5. Entire Agreement31

16.6. Successors and Assigns31

16.7. Third-Parties31

16.8. Severability31

16.9. Construction31

16.10. Execution of Agreement                        31

16.11. Further Assurances32

16.12. Power of Attorney32

16.13. Legal Representation32

APPENDIX A PRINCIPLES OF ALLOCATION1

A.1 Introduction1

A.2 Definitions1

A.3 Capital Accounts                            4

A.4 Allocations of Net Profit and Net Loss                    5

A.5 Tax Allocations8

EXHIBITS

A-1Initial Capital Contributions and Percentage Interests

A-2 Capital Contributions and Percentage Interests Immediately Prior to the Effective Time

ACapital Contributions and Percentage Interests as of the Effective Time

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

REDBIRD GAS STORAGE LLC

This Second Amended and Restated Limited Liability Company Agreement (this “Agreement”) is entered into October 2, 2012 (the “Effective Date”), to be effective as of 12:01 A.M. Central Time on October 1, 2012 (the “Effective Time”), by the persons identified on the signature page(s) hereof.

RECITALS

A.The Company was formed pursuant to a Certificate of Formation filed with the Secretary of State of the State of Delaware effective as of May 24, 2011 to hold membership interests in Cardinal Gas Storage Partners LLC, a Delaware limited liability company (“Cardinal”).

B.The Company has been governed by that certain Limited Liability Company Agreement dated effective as of May 27, 2011 (the “Original LLC Agreement”), as amended and restated in that certain Amended and Restated Limited Liability Company Agreement dated effective as of September 11, 2011 (the “Old LLC Agreement”).

C.Martin Underground Storage, Inc., a Texas corporation (“MUS”), and Martin Operating Partnership L.P., a Delaware limited partnership (“MOP”), constitute all the Members of the Company, with MUS holding Class A Interests and MOP holding Class A Interests and Class B Interests as shown on Exhibit A-2 to this Agreement.

D.MUS and MOP, among others, have entered into a Membership Interests Purchase Agreement dated as of October 2, 2012 (the “Purchase Agreement”) and an Assignment of Membership Interests dated of even date therewith pursuant to which MUS has assigned to MOP all of its Class A Interests in the Company.

E.MOP desires to execute this Agreement to set forth the terms of the limited liability company agreement of the Company as of the Effective Time, which is the effective time of the Closing under the Purchase Agreement.

NOW, THEREFORE, the undersigned hereby adopt this Agreement to supersede and replace in its entirety the Old LLC Agreement and constitute the limited liability company agreement of the Company as of the Effective Date:

ARTICLE I

DEFINITIONS

1.Defined Terms. The following definitions and the definitions set forth in Appendix A to this Agreement, apply to the terms used in this Agreement for all purposes.

“Act” means the Delaware Limited Liability Company Act (Del. Code Ann. tit. 6, ch. 18).

“Additional Capital Contribution” means the sum of cash and the Fair Value of any property contributed to the Company with respect to a Membership Interest as permitted under this Agreement, but does not include an Initial Capital Contribution.

“Additional Member” means a person who acquires a Membership Interest from the Company after the Effective Time and is admitted to the Company as a Member pursuant to Section 11.2. For the sake of clarity, no existing Member shall be deemed an Additional Member to the extent that it makes Additional Capital Contributions pursuant to Section 3.2.

“Affiliate” means a person who directly or indirectly controls, is controlled by, or is under common control with the person in question.

“Assignee” means (a) a person to whom a Membership Interest has been transferred by a Member or Assignee in a Permitted Transfer, or in a Prohibited Transfer that the Company is required by law to recognize, but who has not become a Member, and (b) a former Member as described in Section 13.3.

“Capital Contribution” means the sum of the Initial Capital Contribution and Additional Capital Contributions, if any, with respect to a Membership Interest.

“Cardinal LLC Agreement” means the Amended and Restated Limited Liability Company Agreement of Cardinal dated May 1, 2008, as amended from time to time.

“Certificate of Formation” means the certificate of formation filed with respect to the Company as provided in Section 2.1, as such certificate may be corrected, amended, or restated.

“Certificate of Membership Interest” means a certificate representing a Member's Membership Interest in a form approved by the Manager.

“Class” means either the Class A Interests or the Class B Interests, as the case may be. “Classes” means both the Class A Interests and the Class B Interests.

“Class A Interests” shall mean (a) the Class A Membership Interests initially issued to MUS in exchange for the contribution by MUS to the Company of its Category A membership interest in Cardinal; (b) any additional Class A Interests issued to MUS and MOP pursuant to Section 3.2; and (c) any additional Class A Interests issued on Transfer of any Class A Interest or to any Additional Member. As of the Effective Time, MOP owns 100% of the Class A Interests.

“Class B Interests” shall mean (a) the Class B Membership Interests initially issued to MOP in exchange for its contribution to the Company of $59,903,568 of cash through the Effective Date, and which represents 100% of the Company's economic rights associated with Cardinal's investment in Monroe Gas Storage; and (b) any additional Class B Interests issued on Transfer of any Class B Interests or to any Additional Member. As of the Effective Time, MOP owns 100% of the Class B Interests.

“Class A Members” shall mean those Members holding Class A Interests.

“Class B Members” shall mean those Members holding Class B Interests.

“Company” means the limited liability company formed pursuant to the Certificate of Formation.

“Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a person, whether through ownership of voting securities, by contract or otherwise.

“Damages” means any expense or loss (including any court costs, judgment or settlement payment, penalty, fine, tax, and reasonable attorney's fees or other dispute resolution costs) paid or incurred in connection with or as a consequence of any Proceeding, net of any insurance or other recoveries received by the Indemnified Person with respect to the foregoing.

“Distributable Cash” means the cash and cash equivalents held by the Company (determined in accordance with its accounting policies for reporting cash flows), less any amount of such cash that the Manager determines should be retained for the reasonable current and future needs of the Company business.

“Fair Value” means, with respect to an asset or a Membership Interest, its Fair Value determined according to Article XV.

“Fair Market Value” means the price at which property would change hands between a willing seller and a willing buyer, neither being under any compulsion to sell.

“Formation Date” means the effective date of the original Certificate of Formation of the Company.

“Indemnified Person” means (a) a Member or Assignee; (b) a Manager; (c) a Liquidator (if any); (d) any Affiliate of the Company, a Member or Assignee, a Manager, or a Liquidator; and (e) any governing person, officer, employee, agent, or owner of the Company, a Member or Assignee, a Manager, a Liquidator, or any Affiliate of any of the foregoing. A person is an Indemnified Person whether or not such person has the status required to be an Indemnified Person at the time any Proceeding is made or maintained as described in Article VI or at the time any amendment to this Agreement is proposed under Section 16.1, provided such person had the status required to be an Indemnified Person at the time of the relevant actions referenced in the Proceeding.

“Index Rate” means the rate specified in Section 2301 of the Delaware Commerce and Trade Code.

“Initial Capital Contribution” means the sum of any cash and the Fair Value of any property contributed to the Company by a Member with respect to a Membership Interest in connection with the original issuance of a Class of Membership Interest by the Company as set forth on Exhibit A-1 to this Agreement, which is a copy of Exhibit A to the Old LLC Agreement.

“I.R.C.” means the Internal Revenue Code of 1986.

“Majority-in-Interest” means, with respect to each Class of Membership Interests, one or more Members owning collectively more than 50% of the Percentage Interests owned by all Members of the Class entitled to vote on the particular issue.

“Manager” initially means Ruben S. Martin, and thereafter means any person who becomes a replacement Manager hereunder, or the Members when they are acting pursuant to Section 5.7(d), in each case in such person's capacity as Manager and for the period that such person has such capacity.

“Mandatory Distribution” means any distribution that a Member is entitled to receive and as to which the Member has attained the status of a creditor under Section 18-606 of the Act.

“Member” means any person identified as a member on Exhibit A, and any other person who becomes a member of the Company pursuant to this Agreement, who has not ceased to be a Member. “Members” means all persons that are Members, collectively.

“Membership Interest” means a Member's or Assignee's economic interest in the Company or in a Class, as the case may be. The term includes the Member's or Assignee's right to receive allocations of profits and losses and distributions as described in Article IV, and other rights and obligations under this Agreement or the Act of an Assignee who has not been admitted as a Member, but does not include any right to participate in management or any other right reserved under this Agreement or the Act exclusively to a Member.

“Monroe Gas Distributions” means the amount distributed to the Company from Monroe Cash Available for Distribution pursuant to Section 4.3(d) of the Cardinal LLC Agreement.

“Monroe Gas Storage” means Monroe Gas Storage Company, LLC, a Delaware limited liability company, which has been merged with a subsidiary of Cardinal pursuant to the Monroe Merger Agreement and, if such separate entity shall no longer exist, or if any of its assets shall be transferred to Cardinal or any of its subsidiaries, shall mean the aggregate of the business and operations previously conducted by Monroe Gas Storage Company, LLC.

“Monroe Merger Agreement” means that certain Agreement and Plan of Merger among MGS Holding LLC, MGS Merger Sub LLC, and Monroe Gas Storage Company, LLC, dated May 16, 2011, as amended from time to time.

“Overhead Expenses” shall mean the ongoing operating expenses of the Company, including amounts required to reimburse the Manager for certain expenses pursuant to Section 5.5.

“Pad Gas Lease” means that certain Pad Gas Lease, dated June 12, 2009, between Monroe Gas Storage as lessee and Credit Suisse Energy LLC, a Delaware limited liability company as lessor, as amended by that certain Delivery Schedule Amendment No. 1, dated as of May 11, 2010, and as amended from time to time.

“Percentage Interest” means, as to any Member or Assignee, such Member's or Assignee's percentage interest of the Class either as set forth on Exhibit A, as such exhibit is amended from time to time pursuant to the terms of this Agreement, or as otherwise adjusted from time to time pursuant to Section 3.2, Article X or Article XI.

“Permitted Transfer” means any Transfer of a Membership Interest that is described in Section 10.2.

“Proceeding” means (a) any threatened, pending, or completed action or other proceeding, whether civil, criminal, administrative, arbitrative, or investigative; (b) an appeal of any such proceeding; and (c) an inquiry or investigation that could lead to any such proceeding.

“Prohibited Transfer” means any Transfer of a Membership Interest that is not a Permitted Transfer.

“Projects” means all existing and future development projects of Cardinal except any projects relating to Monroe Gas Storage.

“Substituted Member” means a person who is admitted as a Member pursuant to Section 11.1 with respect to the Transfer of an existing Membership Interest.

“Treasury Regulations” means the Treasury regulations promulgated under the I.R.C.

2.Other Definitions. Each of the following defined terms has the meaning given such term in the Section set forth opposite such defined term:

Defined Term	Section Reference
Agreement	Preamble
Appraiser Notice	15.2(b)
Cardinal	Recitals
Cause	5.7(b)(ii)
Contributed Membership Interest	Recitals
Conversion	Article XII
Converting Member	Article XII
Effective Date	Preamble
Liquidator	14.2(b)
MGS Call	3.2(d)
MGS Call Notice	3.2(d)
MOP	Recitals
MUS	Recitals
Notice Date	5.7(a)
Old LLC Agreement	Recitals
Project Call	3.2(b)
Project Call Notice	3.2(b)
Transfer	10.1(a)
Valuation Notice	15.2(a)

3.Usage. In this Agreement, unless a clear contrary intention appears:

(a)the singular number includes the plural number and vice versa;

(b)reference to any person includes such person's successors and assigns but, if applicable, only if such successors and assigns are not prohibited by this Agreement, and reference to a person in a particular capacity excludes such person in any other capacity or individually;

(c)reference to any gender includes the other gender and the neuter;

(d)reference to any agreement or other document means such agreement or other document as amended or modified and in effect from time to time;

(e)reference to any statute, regulation, or other legal requirement means such legal requirement as amended, modified, codified, replaced, or reenacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder, and reference to any section or other provision of any legal requirement means that provision of such legal requirement from time to time in effect and constituting the substantive amendment, modification, codification, replacement, or reenactment of such section or other provision;

(f)“hereunder,” “hereof,” “hereto,” and words of similar import refer to this Agreement as a whole and not to any particular Article, Section, or other provision hereof;

(g)“including” (and with correlative meaning “include”) means including without limiting the generality of any description preceding such term;

(h)“or” is used in the inclusive sense of “and/or”;

(i)with respect to the determination of any period of time, “from” means “from and including” and “to” means “to but excluding”; and

(j)references to agreements or other documents refer as well to all addenda, exhibits, schedules, or amendments thereto.

ARTICLE II

ORGANIZATIONAL MATTERS

1.Formation. The Company was formed pursuant to the Certificate of Formation filed with the Delaware Secretary of State effective as of the Formation Date.

2.Name. The Company's name is as set forth in the Certification of Formation. The Manager may change the Company name at any time without the approval of any Member by filing a certificate of amendment. The Manager shall provide notice of the change to all Members. The Company's business may be conducted under its name and/or any other name or names deemed advisable by the Manager. The Manager shall cause to be executed and filed of record all assumed or fictitious name certificates required by law.

3.Registered Office and Agent. The street address of the initial registered office of the Company in Delaware and the name of the initial registered agent of the Company are as set forth in the Certificate of Formation. The Manager may change the Company's registered office or registered agent at any time by filing a Certificate of Amendment. The Manager shall provide notice of the change to all Members.

4.Term. The Company will continue until terminated in accordance with Article XIV.

5.Purposes. The purposes of the Company are to engage in any activities that are permitted under applicable laws.

6.Powers. Subject to any limitations in this Agreement, the Company may exercise the power to do any and all acts reasonably related to its purposes.

7.Company Property.

(a)All Company property shall be owned in the name of the Company and not in the name of any Member. No Member or Assignee will have any interest in such Company property solely by reason of the Member's status as a Member.

(b)The Manager shall deposit or invest all funds of the Company in an account or accounts in the name of the Company. No funds other than the funds of the Company may be deposited therein. The funds in such accounts shall be used exclusively for the business of the Company (including distributions to the Members) and may be withdrawn only by persons approved by the Manager.

8.Consent to Admission of Members. Each person executing this Agreement consents to the admission as Members in the Company all of the other persons who are Members as of the date such person executes this Agreement.

9.Status of Manager and Members. Except as otherwise provided by this Agreement, the Manager has the status, rights, and obligations of a manager in a limited liability company as set forth in the Act, and each Member has the status, rights, and obligations of a member in a limited liability company as set forth in the Act.

10.Certificates of Membership Interests. Each Member's Membership Interest may be represented by a Certificate of Membership Interest, and shall be broken down by Class. Each Certificate of Membership Interest for any Class shall be numbered and registered in the records of the Company as they are issued, and shall be signed by the Manager. The holder of any Certificate of Membership Interest shall promptly notify the Company of any loss or destruction of the certificate, and the Company shall cause a replacement certificate to be issued to the holder upon receipt of satisfactory evidence of the loss, destruction, or mutilation or the certificate and satisfaction of other reasonable conditions established by the Manager.

11.No State Law Partnership. The Members intend that the Company is not a partnership or joint venture, and that no Manager or Member is a partner or a joint venturer of any other Manager or Member for any purposes other than income tax purposes. No provision of this Agreement may be construed to suggest otherwise.

12.Subsidiaries. The Company may, from time to time, to the extent the Manager determines appropriate in its discretion, cause the formation of one or more Subsidiaries of the Company.

ARTICLE III

CAPITAL CONTRIBUTIONS; CAPITAL ACCOUNTS

1.Initial Capital Contributions. Each Member's Initial Capital Contributions were as set forth on Exhibit A‑1 attached hereto. Exhibit A‑2 attached hereto sets forth each Member's Capital Contributions immediately prior to the Effective Time. Exhibit A attached hereto sets forth the Capital Contributions and Membership Interests of MOP as of the Effective Time as a result of the consummation of the transactions contemplated by the Purchase Agreement.

2.Additional Capital Contributions.

(a)A Member shall not be required to make Additional Capital Contributions except as set forth in this Section 3.2. Except as set forth in Section 3.2(b) or (c), no Member of any Class has the right or is permitted to make any Additional Capital Contributions unless (i) the Manager and a Majority-in-Interest of each Class approves such Additional Capital Contribution after notice to all Members of each Class of (A) the amount of the Additional Capital Contribution to be made, (B) the Class that will make the Additional Capital Contribution, (C) the effect of the Additional Capital Contribution on each Member's Percentage Interest, and (D) other material information relevant to the proposed Additional Capital Contribution, and (ii) all Members of each Class that will be making the Additional Capital Contribution are afforded an opportunity to participate in the Additional Capital Contribution according to their relative Percentage Interests in the Class.

(b)If the Company receives a request from Cardinal under the terms of the Cardinal LLC Agreement for an additional capital contribution by the Company for Projects other than Monroe Gas Storage (a “Project Call”), the Manager shall provide prompt written notice thereof to the Class A Members, which notice shall include the date such Project Call was received, the amount of such Project Call, and any other relevant facts related thereto (a “Project Call Notice”). Upon receipt of a Project Call Notice the Class A Members may make, at their respective option, Additional Capital Contributions to fund Project Calls.

(c)If the Company receives a request from Cardinal under the terms of the Cardinal LLC Agreement for an additional capital contribution by the Company relating to Monroe Gas Storage (a “MGS Call”), the Manager shall provide prompt written notice thereof to the Class B Members, which notice shall set forth the date such MGS Call was received, the amount of such MGS Call, and any other relevant facts related thereto (a “MGS Call Notice”). Upon receipt of a MGS Call Notice, the Class B Members:

(i)shall make Additional Capital Contributions to fund such MGS Calls if and to the extent such MGS Calls relate to the Pad Gas Lease; and

(ii)may make, at its option, Additional Capital Contributions, if and to the extent such MGS Calls do not relate to the Pad Gas Lease.

(d)Effective as of the effective time of any Additional Capital Contribution under this Section 3.2, Exhibit A shall be amended by the Manager from time to time to reflect such Additional Capital Contributions under this Section 3.2 and the corresponding changes, if any, in the Percentage Interests of the Members.

3.Capital Accounts. The Company shall establish a separate Capital Account for each Member and Assignee. The Capital Accounts shall be maintained according to the provisions of Appendix A.

4.No Right to Return of or Interest on Capital Account. No Member may demand or receive the return of its Capital Contribution or any portion of its Capital Account, except as provided in this Agreement and the Act. The Manager does not have any personal liability for the repayment of any Capital Contributions of any Member. No interest will accrue or be paid with respect to the Capital Contributions or Capital Account of any Member.

5.Member Loans. The Company may borrow money from one or more Members to the extent the Manager deems appropriate to the conduct of the Company business on terms that comply with the requirements of Section 5.6(c) (relating to related party transactions). The amount of any loan made to the Company by a Member will not constitute a Capital Contribution or otherwise affect such Member's Capital Account or Membership Interest.

ARTICLE IV

ALLOCATIONS AND DISTRIBUTIONS

1.Allocation of Profit or Loss. Company profits and losses shall be allocated among the Members and Assignees in accordance with the provisions of Appendix A. The Members are aware of the income tax consequences of the allocations made by Appendix A and agree to be bound by the provisions of Appendix A in reporting their shares of Company income and loss for income tax purposes.

2.Distributions of Distributable Cash.

(a)Except as otherwise provided in Section 4.3 (relating to withholding), Section 4.4 (relating to limitations on distributions), or Section 14.4 (relating to liquidating distributions), any Distributable Cash shall be distributed not later than the 25^th day after the end of each fiscal quarter to the Members and Assignees as follows: (i) an amount equal to the Monroe Gas Distribution pursuant to Section 4.3(d) of the Cardinal LLC Agreement received by the Company with respect to the preceding quarter, less the Company's Overhead Expenses for the preceding quarter as reasonably determined by the Manager, shall be distributed to Class B Members in proportion to their ownership of Class B Interests, and (ii) all remaining Distributable Cash shall be distributed to the Class A Members in proportion to their ownership of Class A Interests. Overhead Expenses for purposes of Section 4.2(a)(i) shall not exceed $25,000 per calendar year, unless the Class A Interests and Class B Interests approve the excess Overhead Expense pursuant to Section 5.3(b). The Manager may provide for a record date with respect to distributions.

(b)To the extent it may lawfully do so, the Company shall make distributions to Members and Assignees in accordance with Section 4.2(a)and Section 14.4(a)(iii) at such times and in such amounts as the Manager determines is sufficient to enable the Members and Assignees to make payments of tax due (including estimated taxes and any applicable and interest and penalties) with respect to their allocable shares of the Company's taxable income. Unless the Manager determines otherwise, the taxes due for each Member and Assignee shall be calculated by assuming that the Member or Assignee is an individual taxed at the highest U.S. federal income tax rate applicable to the type of income involved.

3.Withholding. The Company shall withhold from distributions, or pay on behalf of a Member or Assignee, all amounts that the Manager determines the Company is required to withhold or pay on behalf of such person (including federal and state income tax withholding). All amounts so withheld from distributions are deemed to have been distributed to the person otherwise entitled to receive the amount so withheld. To the extent an amount is paid by the Company on behalf of a Member or Assignee but not withheld from a distribution, the amount paid constitutes a loan to such Member or Assignee. Such loan bears interest at the Index Rate and is repayable on demand or, at the election of the Manager, is repayable out of distributions to which such Member or Assignee would otherwise be entitled.

4.Limitation on Distributions.

(a)The Company may not make a distribution to a Member or Assignee if it would render the Company insolvent, determined in accordance with Section 18-607 of the Act. A Member or Assignee who receives a distribution in violation of Section 18‑607 of the Act is not required to return the distribution except as required in Section 18‑607 of the Act.

(b)The Members shall look solely to the assets of the Company for any distributions, including liquidating distributions. If the assets of the Company remaining after the payment or discharge, or the provision for payment or discharge, of the Company liabilities are insufficient to make any distributions, no Member has any recourse against the separate assets of any other Member.

5.No Right to Partition or Distributions in Kind. No Member has any right, and waives any right that it might otherwise have, to cause any Company property to be partitioned and/or distributed in kind. Except as provided in Section 14.4(d) (relating to liquidating distributions), the Company may not make any distributions in kind.

6.Recovery of Erroneous Distributions. If the Company has, pursuant to any clear and manifest accounting or similar error, distributed to any Member an amount in excess of the amount to which the Member is entitled pursuant to this Agreement, the Member shall reimburse the Company to the extent of such excess, without interest, within 30 days after demand by the Company.

ARTICLE V

MANAGEMENT

1.Management and Control of Company Business.

Subject to the limitations set forth in this Agreement, the Manager has exclusive authority to manage and conduct the Company's business. The Manager shall do all things appropriate to carry out the Company's purpose. The Manager shall comply with the terms of the Cardinal LLC Agreement to the extent applicable to the Company. Except as otherwise provided in this Agreement, all actions that the Manager may take and all determinations that the Manager may make pursuant to this Agreement may be taken and made in the absolute discretion of the Manager. There shall be only one Manager of the Company.

(a)Except as set forth in Section 5.7(d), the Members may not take part in the management or control of the Company business or bind the Company in their capacity as Members. The Members shall not have the right to vote or otherwise consent or withhold consent to any actions taken by the Manager except with respect to such matters as are expressly stated in this Agreement.

2.Delegation of Authority.

(a)The Manager may cause the Company to hire employees and agents, and may delegate to such persons any of its authority hereunder, as the Manager deems appropriate for the conduct of the Company's business.

(b)The Manager may establish offices and appoint officers of the Company, and may delegate to such officers any of its authority hereunder, as the Manager deems appropriate. The officers may be appointed for such terms and may exercise such powers and authority and perform such duties as determined by the Manager. An officer need not be a Member of the Company. Any two or more offices may be held by the same person. An officer may be removed, with or without cause, at any time by the Manager. Each officer will hold office until his successor is chosen and is qualified in his stead, or until his death, resignation, or removal from office. Any vacancy in an office because of death, resignation, removal, or otherwise may be filled by a person appointed by the Manager. An officer is subject to the same standards of conduct as apply to a Manager as described in Section 5.6.

3.Limitations on Manager Authority.

(a)The Manager may not do any of the following acts with respect to the Company without the approval of all Members:

(i)knowingly do any act in contravention of this Agreement or, when acting on behalf of the Company, engage in, or cause or permit the Company to engage in, any activity that is not consistent with the purposes of the Company;

(ii)except as otherwise provided in this Agreement, knowingly do any act that would make it impossible to carry on the Company business; or

(iii)cause the Company to (A) not be taxable as a partnership for federal income tax purposes, or (B) take a position inconsistent with such treatment.

(b)The Manager may not do any of the following acts without the approval of a Majority-in-Interest of each Class:

(i)cause the Company to (A) make a general assignment for the benefit of creditors, (B) file a voluntary bankruptcy petition, or (C) seek an order for relief or declaration of insolvency in a federal or state bankruptcy or insolvency proceeding;

(ii)file a pleading seeking for the Company, or admitting or failing to contest the material allegations of a petition filed by any other person seeking for the Company, a proceeding of the type described by paragraph (i);

(iii)except as provided in Article XIV, seek, consent to, or acquiesce in the appointment of a trustee, receiver, or liquidator of the Company or of all or a substantial part of the Company's properties; cause the Company to issue any Membership Interest or admit any Member other than pursuant to Section 2.8, Section 3.2, or Article XI;

(iv)cause the Company to acquire any Membership Interest;

(v)cause the Company to acquire any equity or debt securities of any Member or any Affiliate of a Member, or otherwise make loans to any Member or any Affiliate of a Member;

(vi)cause the Company to acquire from any person any equity or debt securities or assets of any corporation, limited liability company, partnership, association, business, or business division, whether by stock purchase, asset purchase, contribution, or other business combination (excluding investments in Cardinal and investments and asset acquisitions in the ordinary course of the Company's business);

(vii)cause the Company to participate in any merger, consolidation, transfer, continuance, or conversion of the Company with or into any other person;

(viii)cause the Company to participate in any reorganization in which Membership Interests are exchanged for or converted into cash, securities of any other person, or other property;

(ix)sell or otherwise dispose of all or substantially all of the Company property, except in connection with winding up the Company as permitted in this Agreement;

(x)incur any indebtedness for borrowed money in the name of the Company; create any lien on the assets or property of the Company; or guarantee or provide surety for the obligations of any third party;

(xi)appoint as MRMC Managers (as defined in the Cardinal LLC Agreement) individuals other than the current MRMC Managers on the Cardinal Board, Ruben Martin and Wes Martin; or

(xii)approve Overhead Expenses in excess of $25,000 per year to be deducted from the amount received as the Monroe Gas Distribution to calculate Distributable Cash under Section 4.2(a)(i).

(c)The Manager may not do any of the following acts without the approval of a Majority-in-Interest of the Class A Interests:

(i)consent to any action that requires the consent of the Category A Members of Cardinal under the terms of Section 5.8 of the Cardinal LLC Agreement except when such action relates exclusively to Monroe Gas Storage; or

(ii)cause the MRMC Managers on the Cardinal Board to consent to any action that requires the consent of the Board of Cardinal under the terms of Section 5.7 of the Cardinal LLC Agreement except when such action relates exclusively to Monroe Gas Storage.

(d)The Manager may not do any of the following acts without the approval of a Majority-in-Interest of the Class B Interests:

(i)consent to any action that requires the consent of the Category A Members of Cardinal under the terms of Section 5.8 of the Cardinal LLC Agreement when such action relates exclusively to Monroe Gas Storage; or

(ii)cause the MRMC Managers on the Cardinal Board to consent to any action that requires the consent of the Board of Cardinal under the terms of Section 5.7 of the Cardinal Agreement when such action relates exclusively to Monroe Gas Storage.

For the avoidance of any doubt, any action relating to Monroe Gas Storage that is taken by the MRMC Managers (as defined in the Cardinal LLC Agreement) on the Cardinal Board shall require the approval of a Majority-in-Interest of the Class B Members.

4.Reliance. Persons dealing with the Company may rely conclusively on the authority of the Manager as set forth in this Agreement. Every document executed by the Manager with respect to any business or property of the Company is conclusive evidence in favor of any person relying on the document that (a) at the time of the execution and delivery of the document this Agreement was effective, (b) the document was executed in accordance with this Agreement and is binding on the Company, and (c) the Manager was authorized to execute and deliver the document on behalf of the Company.

5.Compensation and Expenses of Members and Manager. Members and Managers are not entitled to any salary, fee, or other remuneration (other than distributions with respect to the Member's Membership Interest) for providing property or services or other consideration to or for the benefit of the Company in their capacity as a Member or Manager, except that the Manager is entitled to reimbursement from the Company for reasonable out-of-pocket expenses paid or incurred on behalf of the Company, including reasonable charges for services provided by employees of the Manager and overhead expenses. The Company shall pay all out-of-pocket costs incurred in organizing the Company. This Section does not limit or enlarge the Manager's or a Member's rights to liability protection or indemnification under Article VI, and does not limit the Company's ability to enter into transactions with Members in their capacities other than as Members in accordance with Section 5.6(c).

6.Standards of Manager and Member Conduct.

(a)In General. The Manager shall manage and conduct the Company's business in good faith and in a manner the Manager reasonably believes to be in the Company's best interest. The Manager does not violate this Section 5.6(a) unless the Manager engages in conduct described in Section 6.3(a) (relating to improper conduct).

(b)Outside Activities of Manager and Members. The Manager shall devote to the Company's affairs only such time and resources as the Manager deems necessary for the conduct and winding up of the Company business. The Manager and Members or its or their Assignees may engage in or have an interest in other business ventures of every nature and description, independently or with others, including the ownership and operation of businesses similar to or in competition with, directly or indirectly, the Company. Neither the Company nor any Member or Assignee has, solely as a result of such person's interest in the Company, any right to acquire any rights in or to any such other business venture or to the income or profits derived from any such other business venture. A Manager or Member or Assignee has no duty to disclose any such similar or competing business venture to the Company or any Member or Assignee, or to offer to the Company or any Member or Assignee any prior opportunity to acquire an interest in such other business venture.

(c)Related Party Transactions. Except as otherwise provided in this Agreement, the Manager, when acting on behalf of the Company, may purchase property from, sell property to, or otherwise deal with any Manager, Member, or Assignee, acting on its own behalf, or any Affiliate of any Manager, Member, or Assignee, but any such transaction shall be on terms that are no less favorable to the Company than if the transaction had been entered into with an independent third party. No provision of this Agreement requires disclosure of any transaction to, and approval of the transaction by, any disinterested governing persons of the Company or the Members.

7.Resignation, Removal, and Replacement of Manager.

(a)Resignation. The Manager may resign as manager of the Company only upon notice to all Members. If there is no resignation date specified in the notice, or if the specified date is earlier than 90 days following the date the notice is given to Members (“Notice Date”), the Manager's resignation is effective on the 90^th day following the Notice Date. If the specified resignation date is later than 180 days after the Notice Date, the Manager's resignation is effective on the 180^th day following the Notice Date. A Manager is deemed to have resigned as manager of the Company upon the following events:

(i)any event specified in Section 18-304 of the Act (relating to bankruptcy or insolvency proceedings with respect to a Member);

(ii)if the Manager is an individual, the Manager's death, the appointment of a guardian or general conservator for the Manager, or a judicial determination that the Manager is incapable of performing the Manager's duties under the Agreement; or

(iii)if the Manager is an entity, the termination of the Manager's existence or suspension of the Manager's right to do business.A resignation pursuant to paragraph (ii) is not a violation of this Section 5.7(a) provided the estate or personal representative other authorized person provides notice of the deemed resignation within 90 days after the event giving rise to the deemed resignation.

Removal.

(b)Removal for Cause. The Manager may be removed as manager of the Company upon the affirmative vote of a Majority-in-Interest of each Class if there is cause for removal as specified in Section 5.7(b)(ii) and the Company has received a written opinion of counsel that:

(A)cause for removal as specified in Section 5.7(b)(ii) exists; and

(B)the removal of the Manager is not prohibited under any loan agreements, contracts, or other applicable legal requirements.

(i)Definition of Cause. “Cause” for removal exists only if one or more of the following conditions has occurred:

(A)there has been a change in Control of the Manager;

(B)the Manager has engaged in wrongful conduct described in Section 6.3(a) that adversely and materially affected the Company business or the Members;

(C)the Manager or an Affiliate of the Manager has been convicted of a felony; or

(D)a final judgment of a court of competent jurisdiction has been entered that the Manager's removal is necessary to comply with any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute.

(ii)Removal Without Cause. The Manager may be removed for any reason (or for no reason) upon the affirmative vote of a Majority-in-Interest of each Class of the Members.

(c)Election of Replacement Manager. If the Manager resigns or is removed as the manager of the Company, within 90 days following such resignation or removal a Majority-in-Interest of each Class may elect a replacement Manager of the Company effective as of the date of the former Manager's resignation or removal. The replacement Manager shall file any required amendments to this Agreement or the Certificate of Formation to reflect the resignation or removal of the former Manager and the election of the replacement Manager. If the Members fail to elect a replacement Manager within 90 days following the resignation or removal of the former Manager, the Company shall be wound-up according to Article XIV.

(d)Interim Management. During the period that the Members may elect a replacement Manager as provided in Section 5.7(c) and prior to such election (or an election to wind up the Company), the Members may by vote of a Majority-in-Interest of each Class appoint an interim manager having authority to manage and conduct the Company's business as the Manager as provided herein. If an interim Manager is not appointed, the authority to manage and conduct the Company's business is vested in the Members who may act by vote of a Majority-in-Interest of each Class, and who may by vote of a Majority-in-Interest of each Class appoint a committee of one or more persons to exercise the authority of the Manager until such time as a replacement Manager is elected or the Company commences winding up. The Members shall file any required amendments to this Agreement or the Certificate of Formation to reflect the resignation or removal of the former Manager and the appointment of the interim Manager, and all Members hereby approve any such amendments.

ARTICLE VI

LIABILITY AND INDEMNIFICATION

1.Limitation of Liability. No Member or Manager is liable for any debts, obligations, or liabilities of the Company. SUBJECT TO SECTION 6.3, AN INDEMNIFIED PERSON IS NOT LIABLE TO THE COMPANY OR ANY OTHER INDEMNIFIED PERSON FOR ANY DAMAGES ARISING FROM ANY PROCEEDING RELATING TO THE CONDUCT OF THE COMPANY'S BUSINESS OR RELATING TO ANY ACT OR OMISSION BY THE INDEMNIFIED PERSON, INCLUDING ANY ACT OR OMISSION CONSTITUTING NEGLIGENCE, WITHIN THE SCOPE OF THE INDEMNIFIED PERSON'S AUTHORITY IN THE COURSE OF THE COMPANY'S BUSINESS, OR FOR ANY MISCONDUCT OR NEGLIGENCE ON THE PART OF ANY OTHER PERSON WHO IS AN EMPLOYEE OR AGENT OF THE COMPANY.

2.Indemnification by Company. TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW AND SUBJECT TO SECTION 6.3, THE COMPANY INDEMNIFIES AND HOLDS HARMLESS EACH INDEMNIFIED PERSON FROM AND AGAINST ANY DAMAGES ARISING FROM ANY PROCEEDING RELATING TO THE CONDUCT OF THE COMPANY'S BUSINESS OR TO ANY ACT OR OMISSION BY SUCH INDEMNIFIED PERSON, INCLUDING ANY ACT OR OMISSION CONSTITUTING NEGLIGENCE, WITHIN THE SCOPE OF THE INDEMNIFIED PERSON'S AUTHORITY IN THE COURSE OF THE COMPANY'S BUSINESS OR FOR ANY MISCONDUCT OR NEGLIGENCE ON THE PART OF ANY OTHER PERSON THAT IS AN EMPLOYEE OR AGENT OF THE COMPANY. An Indemnified Person's expenses paid or incurred in defending itself against any Proceeding shall be reimbursed as paid or incurred. The right to indemnification conferred in this Article is not exclusive of any other right that any person may have or hereafter acquire under any statute, agreement, vote of Members, or otherwise.

3.Conduct Not Protected.

(a)This Article does not operate to limit liability or to indemnify a person to the extent the person is found liable pursuant to a final judgment of a court of competent jurisdiction for:

(i)an act or omission that involves gross negligence, intentional misconduct, or a knowing violation of law;

(ii)a Transfer or attempted Transfer of all or a portion of a Membership Interest in a Prohibited Transfer, a Manager's resignation in violation of Section 5.7(a), or a Member ceasing to be a Member in violation of Section 13.1(a);

(iii)a willful or reckless material breach of this Agreement or any other agreement relating to the Company's business; or

(iv)an act or omission for which indemnification is prohibited by law.

(b)No provision of this Agreement requires the Company to pay or incur any amount for which indemnification is not permitted under this Article.

(c)Any payments made to or on behalf of a person who is later determined not to be entitled to such payments shall be repaid by the person to the Company. The Company may require, as a condition to the payment of any amounts pursuant to Section 6.2, that the Indemnified Person provide to the Company (i) a written affirmation by the Indemnified Person of the person's good faith belief that the person has met the standard of conduct necessary for indemnification under this Section; and (ii) a written undertaking by or on behalf of the Indemnified Person to repay the amount paid or reimbursed if the person has not met that standard or if indemnification is otherwise prohibited by applicable law.

4.Insurance. The Company may maintain insurance to protect any person against any expense, liability, or loss, whether or not the Company would have the power to indemnify such person against such expense, liability, or loss under the Act.

5.Survival. The indemnities provided for in this Agreement survive the Transfer of an Indemnified Person's Membership Interest, the termination of the person's status as a Member or other status giving rise to classification as an Indemnified Person, and the termination of this Agreement and the Company.

ARTICLE VII

BOOKS AND RECORDS; REPORTS

1.Maintenance of and Access to Books and Records. The Company shall maintain such books and records regarding the Company's business and properties as is reasonable, including all books and records required under the Act. Any Member and its representatives may from time to time at such Member's expense examine (and make copies and extracts of) the Company's books, records and documents of any kind at such reasonable times as such Member may request upon reasonable notice.

2.Fiscal Year. The Company shall adopt the calendar year as its fiscal year for financial and tax accounting purposes.

3.Financial, Operating Reports and Inspection Rights.

(a)Quarterly Report. As soon as practicable after the end of each of the first three quarters of each fiscal year, but in any event not later than 60 days after the end of each such quarter, the Manager shall deliver to each Member a quarterly report containing summary Company balance sheet as of the end of such quarter and summary Company statements of income, cash flows, and changes in Members' equity for such quarter and for the portion of the fiscal year through such date.

(b)Annual Report. As soon as practicable after the end of each fiscal year, but in any event not later than 90 days after the end of the fiscal year, the Manager shall deliver to each Member an annual report containing the following:

(i)a Company balance sheet as of the end of such fiscal year, and Company statements of income, cash flows, and changes in Members' equity for such fiscal year, each in reasonable detail and prepared according to United States generally accepted accounting principles; and

(ii)a statement of changes in the Member's Capital Account (showing the balance in the Member's Capital Account as of the beginning of the fiscal year, contributions or distributions during the year, allocations of profits and losses during the year, any other adjustments to the Capital Account balances during the year, and the balance in the Capital Account as of the end of the year).

(c)Inspection Rights Under Cardinal LLC Agreement. Upon notice to the Manager by any Member, such Member may request the Company to exercise its inspection rights as a Category A Member of Cardinal under the provisions of Section 7.4 of the Cardinal LLC Agreement.

4.Tax Reports.

(a)Not later than the date (including extensions) for filing the Company's tax return with the Internal Revenue Service (Form 1065), the Manager shall deliver to each person who was a Member or Assignee at any time during the period covered by the return all information necessary for the preparation of such person's United States federal income tax returns, including a Form 1065 Schedule K-1 (if applicable).

(b)Upon the written request of any Member or Assignee, the Manager shall deliver to such person information necessary for the preparation of any tax returns that must be filed by such person, including information necessary for estimating and paying estimated taxes.

5.Transmission of Communications. Each person who holds a Membership Interest on behalf of, or for the benefit of, another person or persons shall be responsible for conveying any report, notice, or other communication received concerning the Company's affairs to such other person or persons.

ARTICLE VIII

TAX MATTERS

1.Tax Classification. The Members intend that the Company be classified as a partnership for federal income tax purposes. The Manager shall take all actions reasonably necessary or appropriate to ensure the Company is so classified (including the filing of elections or tax returns). No Manager, officer, or Member shall take any action inconsistent with the classification of the Company as a partnership for federal income tax purposes.

2.Company Returns. The Manager shall cause the Company to file such tax returns as may be required by law.

3.Tax Elections.

(a)General. Except as otherwise provided in this Agreement, the Manager shall cause the Company to timely make or revoke all elections, and take all tax reporting positions, necessary or desirable for the Company as determined by the Manager. No election shall be made to have the Company excluded from the application of any provision of Subchapter K of the I.R.C. or any equivalent tax provision in any other tax jurisdiction. The Company shall make the election referred to in I.R.C. Section 754 upon the request of any Member in connection with a Transfer of the Member's Membership Interest.

(b)Safe Harbor Election for Compensatory Membership Interests. If Proposed Treasury Regulation 1.83-3(l) is adopted as a temporary or final regulation, the Company shall make the safe harbor election described in such regulations, and the Company and each Member (including any person to whom an interest in the Company is transferred in connection with the performance of services) shall comply with all requirements of the safe harbor with respect to all Membership Interests transferred in connection with the performance of services while the election remains effective. The Manager shall prepare, execute, and file any required documentation to cause the election to be effective. The Manager may terminate the safe harbor election at any time if it determines in good faith that it is in the best interests of the Company and the Members to do so.

4.Consistent Reporting. Each Member shall, on the Member's tax returns, treat each partnership item (as defined in I.R.C. Section 6231(a)(3)) in a manner consistent with the treatment of the item on the Company's return in all respects, including the amount, timing, and character of the item. No Member shall file a request for an administrative adjustment of partnership items under I.R.C. Section 6227(a) if such request would cause the Member's treatment of the item to be inconsistent with the treatment of the item on the Company's return.

5.Tax Proceedings.

(a)The Manager shall be the Company's tax matters partner as defined in I.R.C. Section 6231, and shall take such actions as are required to be designated the tax matters partner under applicable Treasury Regulations.

(b)The tax matters partner shall represent the Company in connection with all examinations of the Company's tax returns by tax authorities, including administrative and judicial proceedings to contest any proposed adjustments. Subject to Section 8.5(c), the tax matters partner has the exclusive right to conduct Proceedings relating to Company taxes and to determine whether the Company (either on its own behalf or on behalf of the Members) will contest or continue to contest any tax deficiencies assessed or proposed to be assessed by any taxing authority. The tax matters partner shall keep the Members informed on a timely basis of all material developments with respect to any such Proceeding. Each Member shall cooperate with the tax matters partner and do or refrain from doing all things reasonably requested by the tax matters partner with respect to the conduct of any Company tax Proceeding.

(c)The tax matters partner may not bind any other Member to a settlement agreement relating to taxes without obtaining the written concurrence of such Member.

(d)Any deficiency for taxes imposed on a Member (including penalties, additions to tax or interest imposed with respect to such taxes) shall be paid by such Member and, if paid or required to be paid by the Company, is recoverable from such Member pursuant to Section 4.3 or by other legal means.

6.Information and Documents to Company. Each Member shall timely provide to the Company all information and documents that such Member is required to provide by applicable tax requirements, and shall also provide to the Company upon request such additional information and documents as the Manager may reasonably request in connection with the Company's compliance with applicable tax requirements or filing of any permitted tax elections.

7.Survival. This Article shall survive the termination of the Company and the termination of any Member's interest in the Company and remain binding for a period of time necessary to resolve all tax matters with applicable taxing authorities.

ARTICLE IX

MEETINGS AND VOTING OF MEMBERS

1.Meetings.

(a)Meetings of the Members may be called at any time by the Manager, or by one or more Members holding at least 50% of the Percentage Interest of either Class held by the Members. Meetings shall be held at the Company's principal place of business or at such other reasonable place set forth in the notice of the meeting.

(b)Any action that may be taken at a Members' meeting may be taken without holding a meeting if Members having at least the minimum Percentage Interest of each Class that would be necessary to take the action at a meeting, in which each Member entitled to vote on the action is present and votes, sign a written consent or consents stating the action taken. Except as otherwise provided in this Agreement, meeting notices and procedures, including procedures for obtaining written consents in lieu of a meeting, shall be in conformity with Del. Code title 8, Sections 211 through 233 as applied to corporations that issue stock. Provisions relating to quorum and minimum voting requirements for corporations shall not apply to the extent such provisions are inconsistent with this Agreement. The Manager is solely responsible for conducting meetings of the Members, conducting the solicitation of consents, determining the validity and effect of responses to any solicitation of consents, and determining other matters regarding meetings, voting, and consents.

(c)Notice of the results of any vote taken at a meeting, or the results of any solicitation of consents in lieu of a meeting, shall be given to the Members not later than with the delivery of the next following report of financial information given pursuant to Section 7.3.

2.Voting. A Member entitled to vote on a matter may vote at a meeting in person, or by a proxy executed in writing by the Member and received by the Manager prior to the time when the votes of Members are to be counted. The provisions of the Del. Code title 8, Section 212 pertaining to the validity and use of proxies by shareholders of a corporation govern the validity and use of proxies given by Members. Only Members of record on the date of the meeting (or if the vote is conducted without a meeting then on the date of the notice soliciting the Member consents) may vote.

ARTICLE X

TRANSFER OF MEMBERSHIP INTERESTS

1.Limitation on Transfers.

(a)The term “Transfer,” when used in this Agreement in reference to a transfer of a Membership Interest, means an assignment (whether voluntarily, involuntarily, or by operation of law and whether or not effective under this Agreement) of all or any portion of a Member's or Assignee's Membership Interest, or any interest therein, to another person, and includes a sale, assignment, conveyance, gift, exchange, abandonment, or other disposition, a transfer by merger or other business combination, a transfer pursuant to bankruptcy, insolvency, incapacity, divorce, or death, and any pledge, hypothecation, or other encumbrance.

(b)No Member may Transfer all or any portion of its Membership Interest unless the Transfer is a Permitted Transfer. A Transfer of a Membership Interest that is not a Permitted Transfer is a Prohibited Transfer.

2.Permitted Transfer of Membership Interest.

(a)A Transfer of a Membership Interest is a Permitted Transfer only if the Transfer satisfies the conditions set forth in Section 10.3 and is described in one or more of the following paragraphs of this Section 10.2(a):

(i)any Transfer by MOP that satisfies the conditions set forth in Section 10.3 shall be deemed a Permitted Transfer for purposes of this Agreement; or

(ii)in the case of a Transfer by a third party assignee, a Majority-in-Interest of the Class A Interests and the Class B Interests must consent to such Transfer, such consent to be not unreasonably withheld.

(b)Upon a Permitted Transfer by a Member of all of its Membership Interest, the Member ceases to be a Member as of the effective date of the Transfer determined according to Section 10.4.

3.Conditions to Permitted Transfers of Membership Interests. A Transfer shall not be a Permitted Transfer unless the Manager determines that all of the following conditions are satisfied:

(a)The Transfer complies with all applicable laws, including any applicable securities laws.

(b)The Transfer will not cause the Company to be treated as other than a partnership for United States federal income tax purposes.

(c)The Transfer will not cause the Company to be subject to regulation under the Investment Company Act of 1940.

(d)The Transfer will not cause any assets of the Company to be deemed “plan assets” under the Employee Retirement Income Security Act of 1974.

(e)The Transfer will not result in a termination of the Company under I.R.C. Section 708, unless the Manager determines that such termination will not have an adverse impact on the Members.

(f)The Transfer will not cause the application of the tax-exempt use property rules of I.R.C. Sections 168(g)(1)(B) and 168(h) to the Company or its Members, unless the Manager determines that such rules will not have an adverse impact on the Members.

(g)The transferor and transferee have delivered to the Company any documents that the Manager requests to confirm that the Transfer satisfies the requirements of this Agreement, to give effect to the Transfer, and to confirm the transferee's agreement to be bound by this Agreement as an Assignee.

(h)If requested by the Manager, the Company has received a transfer fee in an amount determined by the Manager to be sufficient to reimburse the Company for the estimated expenses likely to be incurred by the Company in connection with such transfer.

4.Effective Date; Distributions.

(a)A Permitted Transfer of a Membership Interest is effective as of the first day of the calendar month following the calendar month during which the Manager receives notice of such Transfer (in such form and manner as the Manager may require) unless the Manager determines that the Transfer should be effective as of an earlier or later date (for example, on any date the Transfer is effective as a matter of state law, or where the notice of Transfer specifies that the Transfer is to be effective on a future date).

(b)Distributions with respect to a transferred Membership Interest that are made before the effective date of the Transfer shall be paid to the transferor, and distributions made after such date shall be paid to the Assignee.

(c)Effective as of the effective date of a Transfer of a Membership Interest, the Manager shall amend Exhibit A to reflect the reduction in the transferor's Percentage Interest, if any, and to reflect the Assignee's Percentage Interest.

(d)Neither the Company nor the Manager has any liability for making allocations and distributions to the Members determined in accordance with this Section 10.4, whether or not the Manager or the Company has knowledge of any Transfer of any Membership Interest.

5.Transferor's Obligations. The transferor of a Membership Interest who ceases to be a Member continues to be obligated with respect to its Membership Interest or its status as a former Member as provided in the Code and applicable law.

6.Assignee's Rights and Obligations. Unless an Assignee becomes a Member pursuant to Article XI, such Assignee shall not be entitled to any of the rights granted to a Member, other than the rights to receive allocations of profits and losses and distributions, to Transfer the Assignee's Membership Interest (subject to the conditions of this Article X), and to receive reports and information as specified in Article VII. An Assignee of a Membership Interest shall succeed to the Capital Account of the transferor to the extent of the Membership Interest transferred. An Assignee is bound by the limitations and obligations imposed on Members under this Agreement irrespective of whether the Assignee has signed or otherwise adopted this Agreement.

7.Effect and Consequences of Prohibited Transfer.

(a)Except as otherwise required by law, the Company and the Manager shall treat a Prohibited Transfer as void and shall recognize the transferor as continuing to be the owner of the Membership Interest purported to be transferred. If the Company is required by law to recognize a Prohibited Transfer, the transferee shall be treated as an Assignee with respect to the Membership Interest transferred and may not be treated as a Member with respect to the Membership Interest transferred unless admitted as a Member in accordance with Article XI.

(b)The Company may remove the transferor and Assignee with respect to a Prohibited Transfer as provided in Article XIII.

(c)The transferor and transferee with respect to a Prohibited Transfer shall be jointly and severally liable to the Company for, and shall indemnify and hold the Company harmless against, any expense, liability, or loss incurred by the Company (including reasonable legal fees and expenses) as a result of such Transfer, their removal and liquidation of their Membership Interests (if applicable), and the efforts to enforce the indemnity granted in this Section 10.7(c).

ARTICLE XI

ADMISSION OF NEW MEMBERS

1.Substituted Members. An Assignee of a Membership Interest shall be admitted as a Substituted Member with respect to such Membership Interest on the date on which all of the following conditions are satisfied:

(a)The Manager has approved in writing the admission of the Substituted Member.

(b)The Assignee has delivered to the Company any agreements and other documents that the Manager requests to confirm such Assignee as a Member in the Company and such Assignee's agreement to be bound by this Agreement as a Member.

(c)If requested by the Manager, the Company has received an admission fee in an amount determined by the Manager to be sufficient to reimburse the Company for the estimated expenses likely to be incurred by the Company in connection with the admission of the Assignee as a Substituted Member.

2.Additional Members. The Manager shall admit a person as an Additional Member upon satisfaction of all of the following conditions.

(a)A Majority-in-Interest of each Class has approved the admission of the Additional Member after notice to all Members of (i) the Initial Capital Contribution to be made by the proposed Additional Member, (ii) the effect of the admission on each Member's Percentage Interest, and (iii) other material information relevant to the proposed admission.

(b)The admission of the proposed Additional Member satisfies the applicable conditions of Section 10.3.

(c)The proposed Additional Member has delivered to the Company any agreements and other documents that the Manager requests to confirm the person as a Member in the Company and the person's agreement to be bound by this Agreement as a Member.

3.No Required Capital Contributions. A person may be admitted as a Member, including as the sole Member, and may acquire a Membership Interest without making a contribution to the Company or assuming an obligation to make a contribution to the Company.

4.Amendments to Exhibit A. Effective as of the effective date of the admission of a Substituted Member or an Additional Member, the Manager shall amend Exhibit A to reflect the changes in Percentage Interests of the Members.

ARTICLE XII

CONVERSION of Class B Interests

Upon a sale of the membership interests, a merger, an exchange of interests, an initial public offering of Cardinal or other similar transaction involving Cardinal, MOP and any MOP Affiliate that acquires Class B Interests from MOP (each, a “Converting Member”) shall have the right to convert all, but not less than all, Class B Interests held by the Converting Members into Class A Interests (a “Conversion”). In addition, and without limiting the foregoing, all but not less than all of the outstanding Class B Interests may be converted into Class A Interests upon the approval by all the Class A Members, with any such Conversion to be upon terms and conditions that are mutually satisfactory to the Class A Members and the Class B Members. Upon a Conversion, all Class B Interests held by each Converting Member will be converted into the number of Class A Interests having the same Fair Value on a fully diluted basis as the Class B Interests held by such Converting Member immediately prior to the Conversion. For purposes of this Article XII, Fair Value of Membership Interests shall be determined in accordance with, and any dispute regarding such valuation shall be resolved pursuant to, Section 15.2.

ARTICLE XIII

RESIGNATION OR REMOVAL OF MEMBERS

1.Resignation of Members.

(a)No Member may resign from the Company or otherwise cease to be a Member except upon the following events:

(i)receipt by the Company of a notice of such Member's resignation from the Company;

(ii)a Transfer of all of the Member's Membership Interest in a Permitted Transfer; or

(iii)removal of the Member as a Member as provided in this Agreement.

(b)A Member shall be deemed to have resigned from the Company upon the following events:

(i)an event specified in Section 13.1(a);

(ii)an event specified in Section 18-304 of the Act (relating to bankruptcy or insolvency proceedings with respect to a Member);

(iii)if a Member is an individual, the Member's death, the appointment of a guardian or general conservator for the Member, or a judicial determination that the Member is incapable of performing the Member's duties under this Agreement; or

(iv)if the Member is an entity, an event causing the termination of the Member's existence or suspension of the Member's right to do business.

A resignation pursuant to paragraph (iii) is not a violation of Section 13.1(a) provided the estate or personal representative other authorized person provides notice of the deemed resignation within 90 days after the event giving rise to the deemed resignation.

(c)If a Member ceases to be a Member in violation of Section 13.1(a), the Company may recover damages from the former Member for breach of this Agreement.

2.Removal of Members.

(a)A Member may be removed as a Member by the Manager under the following circumstances:

(i)the Member has transferred or attempted to Transfer all or any portion of its Membership Interest in a Prohibited Transfer;

(ii)in the case of any Member who is also the Manager or an Affiliate of the Manager, the Member or its Affiliate has ceased to be the Manager in violation of Section 5.7(a) or has been removed as the Manager in accordance with Section 5.7(b);

(iii)the Member has materially breached the terms of this Agreement or any other material agreement with the Company; or

(iv)the Manager determines that removal is necessary to comply with any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any United States federal or state agency or judicial authority or contained in any United States federal or state statute.

(b)If the Manager proposes to remove a Member pursuant to this Section, the Manager shall notify the Member in writing of the proposed removal, and if applicable shall provide such Member a reasonable opportunity to cure the event giving rise to removal. The removal of the Member is effective at such time as determined by the Manager in accordance with applicable law and taking into account the Member's opportunity to cure the event giving rise to removal.

3.Status of Former Member. A Member who has resigned or has been removed from the Company or otherwise ceases to be a Member has the status of an Assignee with respect to any Membership Interest held by such former Member. Except as provided in Article XIV (relating to winding up and termination), such former Member is not entitled to receive any payments under Section 18-604 of the Act.

ARTICLE XIV

DISSOLUTION

1.Events Requiring Dissolution or Winding Up. The Company is dissolved and shall be wound up in accordance with this Agreement and the Act upon the first to occur of the following events:

(a)a Majority-in-Interest of each Class votes to dissolve and wind up the Company;

(b)a decree by a court requiring the dissolution and winding up of the Company;

(c)the termination of membership of the last remaining Member; or

(d)the resignation or removal of the Manager if the Members fail to elect a replacement Manager as provided in Section 5.7(c).

2.Winding Up Procedures.

(a)On the occurrence of an event requiring winding up of the Company, unless there is an action to continue the Company without winding up in accordance with Section 14.3, the Manager (or other Liquidator as provided below) shall, as soon as reasonably practicable, wind up the Company's business and affairs (including disposing of the Company's assets and applying the proceeds as provided in Section 14.4) and terminate the Company in accordance with this Agreement and the Act. The Company shall cease to carry on its business (except to the extent necessary to wind up its business), collect and sell its property to the extent the property is not to be transferred or distributed in kind, and perform any other act required to wind up its business and affairs.

(b)If the Manager has wrongfully caused the winding up of the Company or if there is no Manager, (i) a Majority-in-Interest of each Class may vote to elect a person or persons to accomplish the winding up of the Company, or (ii) if the Members fail to elect a person to accomplish winding up the Company, then any Member or Assignee may petition a court to wind up the Company as provided in Section 18-803(a) of the Act. The person or persons winding up the Company, whether the Manager or an elected or court appointed person or persons, is referred to in this Agreement as the “Liquidator.”

(c)The Liquidator may determine the time, manner, and terms of any sale or sales of Company property pursuant to such winding up. The Liquidator (if not the Manager) is entitled to receive reasonable compensation for its services; may exercise all of the powers conferred upon the Manager under this Agreement to the extent necessary or desirable in the good faith judgment of the Liquidator to perform its duties; and, with respect to acts taken or omitted while acting in such capacity on behalf of the Company, is entitled to the limitation of liability and indemnification rights set forth in Article VI.

(d)The Liquidator shall provide quarterly reports to the Members and Assignees during the winding up procedure showing the assets and liabilities of the Company, providing information and documents required by the Members and Assignees to comply with their tax reporting obligations, and such other information as the Liquidator deems appropriate. Within a reasonable time after completing the winding up, the Liquidator shall give each Member and Assignee a final statement setting forth the assets, liabilities, and reserves of the Company as of the date of completion of winding up.

3.Continuation Without Winding Up.

(a)If there is a decision to dissolve and wind up the Company as described in Section 14.1(a), the Company may be continued as provided in Section 18-806 of the Act.

(b)If there is a termination of the continued membership of the last remaining Member as described in Section 14.1(c), then prior to completion of the winding up process but not later than 90 days after the event of termination, the Manager may continue the Company by admitting one or more Members effective as of the occurrence of the event of termination. Any Assignee whose Percentage Interest would be diminished by reason of the admission of an Additional Member under the circumstances described in this Section must approve the admission of the Additional Member.

4.Liquidation of Assets and Application and Distribution of Proceeds.

(a)In General. On winding up the Company, the Liquidator shall dispose of the Company's properties and apply and distribute the proceeds, or transfer the Company properties, in the following order of priority:

(i)to creditors (including Members who are creditors) in accordance with their relative rights and priorities to satisfy the liabilities of the Company, including expenses associated with the winding up and termination of the Company, but excluding any Company liability for any unpaid Mandatory Distributions;

(ii)to Members, Assignees, and former Members to satisfy the Company's liability for any unpaid Mandatory Distributions; and

(iii)to Members and Assignees in accordance with their positive capital account balances.

(b)No Member Deficit Restoration Obligation. No Member is liable to the Company or any other person for the repayment of any deficit in the Member's Capital Account, except as provided in Section 18-607 of the Act.

(c)Reserves. In the discretion of the Liquidator, a pro rata portion of the distributions that would otherwise be made pursuant to Section 14.4(a)(ii) and (iii) may be withheld to provide a reasonable reserve for Company liabilities (contingent or otherwise) and future expenses, including a reasonable reserve for any claims for indemnification under Article VI and for any future expenses associated with any tax audit or other Proceeding that is pending or may arise.

(d)Payments and Distributions to Members in Kind. The Liquidator may not make any payments or distributions to Members or Assignees pursuant to Section 14.4(a)(ii) or (iii) other than in cash unless all Members and Assignees receiving the property approve the transfer in kind. The Liquidator shall determine the Fair Value of any property transferred to Members or Assignees in kind according to the valuation procedures set forth in Article XV.

(e)Character of Liquidating Distributions. Except as otherwise required by the I.R.C., amounts paid to Members pursuant to this Section 14.4 shall be treated as made in exchange for the interest of the Member in Company property pursuant to I.R.C. Section 736(b)(1), including the interest of such Member in Company goodwill.

5.Certificate of Cancellation. The Liquidator shall file a Certificate of Cancellation under the Act on the completion of the dissolution and winding up of the Company.

ARTICLE XV

VALUATION

1.Fair Value of Company Property. The Fair Value of property contributed to the Company by a Member as part of such Member's Initial Capital Contribution is the amount of such Member's Initial Capital Contribution, as set forth on Exhibit A, minus the amount of any cash contributed to the Company as part of such Member's Initial Capital Contribution. In all other cases, the Fair Value of an asset, other than a Membership Interest, as of any date is its fair market value as determined by the Manager in good faith using any reasonable valuation method. If any affected Member does not agree with the valuation set by the Manager, the Fair Value shall be determined using procedures similar to those set forth in Section 15.2, and the cost of any such determination shall be borne entirely by the affected Member unless the Manager or a Majority-in-Interest of each Class of Members other than the affected Member approves an alternative allocation of such costs.

2.Fair Value of Membership Interests.

(a)For purposes of Article XII, the Fair Value of a Membership Interest is its fair market value as determined by the Manager (or, if there is no Manager, by the Liquidator) in good faith based on the net proceeds that would be received with respect to such Membership Interest in a winding up of the Company. In connection with the Conversion of a Membership Interest, the Manager or Liquidator shall provide written notice to each Converting Member setting forth the Fair Value of the Membership Interests, which notice shall include all information relevant to the determination of such Fair Value (a “Valuation Notice”).

(b)If a Converting Member does not agree with the Fair Value of the Membership Interests as determined by the Manager or Liquidator, such Converting Member may submit to the Company a notice of objection within 30 days after such Converting Member's receipt of the Valuation Notice. Within 15 days following receipt of a Converting Member's notice of objection, the Company shall appoint a qualified appraiser and deliver a written notice to each Converting Member setting forth the name and business address of such appraiser (an “Appraiser Notice”). The appraiser shall determine the Fair Value of the Membership Interests in accordance with the principles set forth in Section 15.2(a). Except as provided in Section 15.2(c), the appraiser's determination of the Fair Value of the Membership Interests shall be made within 30 days of his appointment (or such longer period as is reasonably required to complete the appraisal), and will be final and binding on all concerned, absent manifest error.

(c)If a Converting Member does not approve the appraiser selected by the Company pursuant to Section 15.2(b) and identified in the Appraiser Notice, within 15 days following such Converting Member's receipt of the Appraiser Notice the Converting Member may appoint a qualified appraiser of the Converting Member's choice, and inform the Company in writing of the name and business address of the appraiser. In such event, the appraisers appointed by the Company and the Converting Member shall appoint a third qualified appraiser. Each of the three appraisers shall determine the Fair Value of the Membership Interests in accordance with the principles set forth in Section 15.2(a). With respect to each Class, the average of the two valuations of such Class of Membership Interests that are closest to each other shall be deemed to be the Fair Value of such Class of Membership Interests and such determination shall be final and binding on all concerned, absent manifest error.

(d)The cost of each appraisal shall be shared 50% by the Company and 50% by the Converting Members.

ARTICLE XVI

GENERAL PROVISIONS

1.Amendments.

(a)In General. Subject to the following exceptions and limitations, this Agreement may be amended only with the approval of a Majority-in-Interest of each Class.

(b)Exceptions and Limitations. The Manager shall amend Exhibit A from time to time to reflect the admission and withdrawal of Members, Additional Capital Contributions and changes to any Member's Percentage Interest, in accordance with this Agreement. The Manager may use the power of attorney granted in Section 16.12 to make non-substantive amendments that do not adversely impact the rights or obligations of any Manager or Member. No amendment of this Agreement may adversely affect any Member's rights or obligations under this Agreement (determined without taking into account the right of other Members to amend this Agreement) without the adversely affected Member's approval. No amendment of Article VI (relating to liability and indemnification) may adversely affect the rights or obligations of any Indemnified Person without the Indemnified Person's approval. No amendment of this Agreement may change the requirements under this Agreement for approving any action without the approval of the Members holding an aggregate Percentage Interest required to approve the action.

2.Notice. Any notice, report, or other communication required or permitted to be made to any person by this Agreement shall be in writing and is deemed given when (a) delivered to the person by hand, (b) the third business day after delivery to the United States Postal Service (or other designated delivery service as defined in I.R.C. Section 7502(f)), postage prepaid, in an envelope properly addressed to the person at the person's address set forth in the Company's records as of the date of delivery, or (c) successfully transmitted by facsimile or electronic message to the person's facsimile phone number or e-mail address (as applicable) set forth in the Company's records as of the date of transmission. Any communication to the Manager or the Company may be delivered to the Company's registered office designated pursuant to Section 2.3.

3.Governing Law; Consent to Jurisdiction. This Agreement is governed by and shall be construed under the laws of the State of Delaware without regard to legal requirements that would require the application of the law of any other jurisdiction. Any Proceeding arising out of or relating to this Agreement or the Company's activities or properties may be brought in the state courts of the County where the Company's principal office is located, or, if it has or can acquire jurisdiction, in the United States District Court for the District in which the Company's principal office is located. Each Member and Assignee irrevocably submits to the exclusive jurisdiction of each such court in any such Proceeding, waives any objection it may now or hereafter have to venue or to convenience of forum, agrees that all claims in respect of the Proceeding shall be heard and determined only in any such court and agrees not to bring any such Proceeding in any other court. The Company or any Member or Assignee may file a copy of this Agreement with any court as written evidence of the agreement between the parties irrevocably to waive any objections to venue or to convenience of forum. Process in any Proceeding referred to in the second sentence of this Section may be served on any party anywhere in the world.

4.Waiver. Any failure by a party to insist upon the strict performance of any covenant or condition of this Agreement, or to exercise any right or remedy upon a breach of any such covenant or condition, does not constitute waiver of any such covenant or condition or any breach thereof. A party will not be deemed to have waived any right or remedy under this Agreement unless that party has signed a written document to that effect, and any such waiver is applicable only with respect to the specific provision and instance for which it is given.

5.Entire Agreement. This Agreement supersedes all prior agreements, whether written or oral, between the parties with respect to its subject matter and constitutes a complete and exclusive statement of the agreement between the parties with respect to its subject matter.

6.Successors and Assigns. No Member or Assignee may assign any of its rights or delegate any of its obligations under this Agreement except as expressly permitted in this Agreement.

7.Third-Parties. Other than as provided in Section 5.4 (relating to reliance on authority of the Manager) and Article VI (relating to rights of Indemnified Persons), none of the provisions of this Agreement are for the benefit of or enforceable by any creditors of the Company or other persons not a party to this Agreement, except such benefits as inure to a successor or permitted assign in accordance with Section 16.6.

8.Severability. If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement will remain in full force and effect. Any provision of this Agreement held invalid or unenforceable only in part or degree will remain in full force and effect to the extent not held invalid or unenforceable.

9.Construction. The language in this Agreement is to be construed according to its fair meaning and is not to be strictly construed for or against any party. Nothing in this Agreement is to be construed as authorizing or requiring any action that is prohibited by the Act or other applicable law, or as prohibiting any action that is required by the Act or other applicable law.

10.Execution of Agreement. This Agreement may be executed in counterparts, each of which will be deemed to be an original copy of this Agreement, and all of which together constitute one agreement. Any signature to this Agreement evidenced by a facsimile or other electronic transmission of such signature shall be binding on the parties to the same extent as if such signature were an original.

11.Further Assurances. The parties shall execute and deliver all documents, provide all information, and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

12.Power of Attorney.

(a)Each Member appoints the Manager and the Liquidator severally with full power of substitution, as the true and lawful attorney-in-fact for such Member, and in the name, place, and stead of such Member, to execute, certify, acknowledge, swear to, file, publish, and record:

(i)any certificate or other document that may be required to be filed by the Company or the Members in order to qualify the Company to do business in any jurisdiction, except that no such filing shall include a consent by any Member to service of process in any jurisdiction without the Member's approval;

(ii)any amendment to the Certificate of Formation, to this Agreement, or to any other agreement or document as required or permitted by this Agreement;

(iii)any Certificate of Cancellation and other documents that may be required to effectuate the termination of the Company pursuant to the provisions of this Agreement; and

(iv)any document required of the Company to carry out the actions that the Manager is authorized to take under this Agreement.

(b)The foregoing appointment of the Manager and Liquidator as a Member's attorney-in-fact does not grant such attorney-in-fact any power or authority to approve, consent, or agree to the substantive terms of any agreement or other document on behalf of such Member.

(c)The power of attorney granted pursuant to this Section 16.12 (i) is a special power of attorney coupled with an interest and is irrevocable, and (ii) survives the resignation or removal of a Member or the assignment of its Membership Interest.

13.Legal Representation. This Agreement has been prepared by Strasburger & Price, LLP in its role as counsel to the Company. Strasburger & Price, LLP does not represent any Member (other than MUS), and the Members should consult their own counsel to advise them regarding this Agreement and the transactions contemplated by the Company.

[SIGNATURES BEGIN ON THE FOLLOWING PAGE]

Executed as of the Effective Date set forth above, by and among the persons signing below.

MANAGER:	Ruben S. Martin
MEMBERS:	MARTIN OPERATING PARTNERSHIP L.P. By:Martin Operating GP LLC, its general partner By:Martin Midstream Partners L.P., its sole member By:Martin Midstream GP LLC, its general partner By: /s/Robert D. Bondurant Name:Robert D. Bondurant Title:Executive Vice President
EXHIBITS A‑1 AND A‑2 ACKNOWLEDGED BY FORMER MEMBER:	MARTIN UNDERGROUND STORAGE, INC. By: /s/ Robert D. Bondurant Name:Robert D. Bondurant Title:Executive Vice President

Exhibit A-1

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

REDBIRD GAS STORAGE LLC

EXHIBIT A-1

INITIAL CAPITAL CONTRIBUTIONS AND PERCENTAGE INTERESTS

AS OF SEPTEMBER 11, 2011

Member Name and Address		Initial Capital Contribution			Initial Percentage Interest
									Total
Class A Member		Class A	Class B	Total	Class A		Class B		(Fully Diluted)
Martin Underground Storage, Inc. 4200B Stone Rd. Kilgore, TX 75662		All membership interests owned in Cardinal valued at $150,000,000	—	$150,000,000	100	%	—		71.46139	%
Class B Member
Martin Operating Partnership L.P. 4200B Stone Rd. Kilgore, TX 75662		—	$59,903,568(1)	$ 59,903,568(1)	—		100	%	28.53861	%
Total		$150,000,000	$59,903,568	$209,903,568	100	%	100	%	100%
Notes:
(1) The Initial Capital Contribution of $59,903,568 by the Class B Member consists of:
(i)	$59,318,400 initial cash capital contribution to Cardinal to fund the Monroe Gas Storage acquisition
(ii)	$585,168 in additional cash capital contribution to Cardinal for MSG Calls to fund Monroe Gas Storage capital expenditures

Exhibit A-2 - Page 1

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

REDBIRD GAS STORAGE LLC

EXHIBIT A-2

CAPITAL CONTRIBUTIONS AND PERCENTAGE INTERESTS

IMMEDIATELY PRIOR TO THE EFFECTIVE TIME

Member Name and Address		Total Capital Contribution			Percentage Interest
									Total
Class A Member		Class A	Class B	Total	Class A		Class B		(Fully Diluted)
Martin Underground Storage, Inc. 4200B Stone Rd. Kilgore, TX 75662		All membership interests owned in Cardinal valued at $150,000,000	—	$150,000,000	89.2552	%	—		63.2802	%
Martin Operating Partnership L.P. 4200B Stone Rd. Kilgore, TX 75662		$18,057,452(2)	—	$18,057,452(2)	10.7448	%	—		7.6179	%
Class B Member
Martin Operating Partnership L.P. 4200B Stone Rd. Kilgore, TX 75662		—	$68,983,612(1)	$ 68,983,612(1)	—		100	%	29.102	%
Total		$168,057,452	$68,983,612	$237,041,064	100%		100	%	100%
Notes:
(1) The Total Capital Contribution of $68,983,612 by the Class B Member consists of:
(i)	$59,318,400 initial cash capital contribution to Cardinal to fund the Monroe Gas Storage acquisition
(ii)	$9,080,036 in additional cash capital contribution to Cardinal for a MSG Call to fund Monroe Gas Storage capital expenditures
(2) $18,057,452 in additional cash capital contributions to Cardinal to fund Arcadia, Perryville and Cadeville Gas Storage capital expenditures.

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

REDBIRD GAS STORAGE LLC

EXHIBIT A

CAPITAL CONTRIBUTIONS AND PERCENTAGE INTERESTS

AS OF THE EFFECTIVE TIME

Member Name and Address		Total Capital Contribution			Percentage Interest
									Total
Class A Member		Class A	Class B	Total	Class A		Class B		(Fully Diluted)
Martin Operating Partnership L.P. 4200B Stone Rd. Kilgore, TX 75662		All membership interests owned in Cardinal valued at $150,000,000 and an additional $18,057,452(2)	—	$168,057,452	100	%	—		70.898	%
Class B Member
Martin Operating Partnership L.P. 4200B Stone Rd. Kilgore, TX 75662		—	$68,983,612(1)	$ 68,983,612(1)	—		100	%	29.102	%
Total		$168,057,452	$68,983,612	$237,041,064	100	%	100	%	100	%
Notes:
(1) The Total Capital Contribution of $68,983,612 by the Class B Member consists of:
(i)	$59,318,400 initial cash capital contribution to Cardinal to fund the Monroe Gas Storage acquisition
(ii)	$9,080,036 in additional cash capital contribution to Cardinal for a MSG Call to fund Monroe Gas Storage capital expenditures
(2) $18,057,452 in additional cash capital contributions to Cardinal to fund Arcadia, Perryville and Cadeville Gas Storage capital expenditures.

2

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

REDBIRD GAS STORAGE LLC

APPENDIX A

PRINCIPLES OF ALLOCATION

A.1Introduction. This Appendix sets forth principles under which items of income, gain, loss, deduction and credit shall be allocated among the Members. This Appendix also provides for the determination and maintenance of Capital Accounts, generally in accordance with Treasury Regulations promulgated under I.R.C. Section 704(b), for purposes of determining such allocations. For purposes of this Appendix, an Assignee shall be treated in the same manner as a Member.

A.2Definitions. Capitalized terms used in this Appendix have the meanings set forth below or in the Agreement.

“Adjusted Capital Account Deficit” means any deficit balance in a Member's Capital Account as of the end of a taxable year, after giving effect to the following adjustments:

(i)Credit to the Capital Account any amounts the Member is obligated to restore pursuant to the Agreement or is deemed to be obligated to restore pursuant to (a) Treasury Regulations Section 1.704-1(b)(2)(ii)(c) (relating to obligations to pay partner promissory notes and other obligations to make contributions to the Company), or (b) the penultimate sentences of Treasury Regulations Sections 1.704-2(g)(1) (relating to partnership minimum gain) and 1.704-2(i)(5) (relating to partner nonrecourse debt minimum gain); and

(ii)Debit to such Capital Account the items described in Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), and 1.704-1(b)(2)(ii)(d)(6).

The foregoing definition is intended to comply with Treasury Regulations Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith.

“Capital Account” has the meaning set forth in Section A.3.

“Depreciation” means, for each taxable year, an amount equal to the depreciation, amortization, or other cost recovery deduction allowable with respect to an asset for such taxable year, except that if the Gross Asset Value of an asset differs from its adjusted basis for federal income tax purposes at the beginning of such taxable year, Depreciation is an amount which bears the same ratio to such beginning Gross Asset Value as the federal income tax depreciation, amortization, or other cost recovery deduction for such taxable year bears to such beginning adjusted tax basis. If the adjusted basis for federal income tax purposes of an asset at the beginning of such taxable year is zero, Depreciation shall be determined with reference to such beginning Gross Asset Value using any reasonable method selected by the Manager.

“Gross Asset Value” means an asset's adjusted basis for federal income tax purposes, except as follows:

(i)The initial Gross Asset Value of an asset contributed by a Member to the Company is the gross Fair Value of such asset, as determined by the contributing Member and the Manager and as set forth on Exhibit A. If the contributing Member is the Manager, the determination of the Fair Value of a contributed asset requires the approval of a Majority-in-Interest of each Class.

(ii)The Gross Asset Values of Company assets shall be adjusted to equal their respective gross Fair Values (taking I.R.C. § 7701(g) into account), as determined by the Manager, as of the following times: (A) the acquisition of an additional interest in the Company by any new or existing Member in exchange for more than a de minimis Capital Contribution; (B) the distribution by the Company to a Member of more than a de minimis amount of property as consideration for an interest in the Company; (C) the liquidation of the Company within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(g); (D) the Conversion of Class B Interests into Class A Interests pursuant to Article XII of the Agreement; and (E) in connection with the grant of an interest in the Company (other than a de minimis interest) as consideration for the provision of services to or for the benefit of the Company by a Member acting in a member capacity or in anticipation of being a Member. Adjustments pursuant to clauses (A), (B), (C) and (D) above are required only if the Manager determines that such adjustments are necessary to accurately reflect the relative economic interests of the Members in the Company.

(iii)The Gross Asset Value of a Company asset distributed to a Member shall be adjusted to equal the gross Fair Value (taking I.R.C. § 7701(g) into account) of such asset on the date of distribution as determined by the distributee and the Manager. If the distributee is the Manager, the determination of the Fair Value of the distributed asset requires the approval of a Majority-in-Interest of each Class.

(iv)The Gross Asset Values of Company assets shall be increased (or decreased) to reflect any adjustments to the adjusted basis of such assets pursuant to I.R.C. Section 734(b) or I.R.C. Section 743(b), but only to the extent that such adjustments are taken into account in determining Capital Accounts pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(m). Gross Asset Values shall not be adjusted pursuant to this paragraph (iv) to the extent that an adjustment is required pursuant to paragraph (ii).

If the Gross Asset Value of an asset has been determined or adjusted pursuant to subparagraphs (i), (ii) or (iv) of this definition, the asset's Gross Asset Value shall thereafter be adjusted by the Depreciation taken into account with respect to such asset for purposes of computing gain and loss.

“Income”, “Gain”, “Loss” or “Deduction”, and other items mean, for each taxable year or other relevant period, an amount equal to the Company's items of income, gain, loss or deduction, and other items for such taxable year or other relevant period, determined in accordance with I.R.C. Section 703(a) (for this purpose, all items of income, gain, loss, or deduction required to be stated separately pursuant to I.R.C. Section 703(a)(1) shall be included in taxable income or loss), with the following adjustments:

(i)Any income of the Company that is exempt from federal income tax and not otherwise taken into account in computing income or gain shall be added to such taxable income or gain.

(ii)Any expenditures of the Company described in I.R.C. Section 705(a)(2)(B) or treated as I.R.C. Section 705(a)(2)(B) expenditures pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(i), and not otherwise taken into account in computing items of loss or deduction shall be added to such items of loss or deduction.

(iii)If the Gross Asset Value of any Company asset is adjusted pursuant to subparagraph (ii) or (iii) of the Section A.2 definition of Gross Asset Value, the amount of such adjustment shall be taken into account as gain or loss from disposition of the asset for purposes of computing income, gain, loss or deduction.

(iv)Gain or loss resulting from any disposition of Company property with respect to which gain or loss is recognized for federal income tax purposes shall be computed by reference to the Gross Asset Value of the property disposed of (unreduced by any liabilities attributable thereto), notwithstanding that the adjusted tax basis of such property differs from its Gross Asset Value.

(v)In lieu of the depreciation, amortization, and other cost recovery deductions taken into account in computing such taxable income or loss, there shall be taken into account Depreciation computed in accordance with the definition of Depreciation in Section A.2.

(vi)To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to I.R.C. Section 734(b) is required pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(4) to be taken into account in determining Capital Accounts as a result of a distribution other than in liquidation of a Member's Membership Interest, the amount of such adjustment shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases the basis of the asset) from the disposition of the asset and shall be taken into account for purposes of computing income, gain, loss or deduction.

“Nonrecourse Deductions” has the meaning set forth in Treasury Regulations Section 1.704-2(b)(1) and shall be determined according to the provisions of Treasury Regulations Section 1.704-2(c).

“Nonrecourse Liability” has the meaning set forth in Treasury Regulations Section 1.704-2(b)(3).

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulations Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulations Section 1.704-2(i)(2) and shall be determined in accordance with Treasury Regulations Section 1.704-2(i)(3).

“Partner Nonrecourse Deductions” has the meaning set forth in Treasury Regulations Section 1.704-2(i)(1) and shall be determined in accordance with Treasury Regulations Section 1.704-2(i)(2).

“Partnership Minimum Gain” has the meaning set forth in Treasury Regulations Section 1.704-2(b)(2) and shall be determined in accordance with Treasury Regulations Section 1.704-2(d).

A.3Capital Accounts. The Company shall determine and maintain Capital Accounts. “Capital Account” means an account of each Member determined and maintained throughout the full term of the Company in accordance with the capital accounting rules of Treasury Regulations Section 1.704-1(b)(2)(iv). Without limiting the generality of the foregoing, the following rules apply:

(a)The Capital Account of each Member shall be credited with (i) an amount equal to such Member's Capital Contributions and the Fair Value of property contributed (if permitted hereunder) to the Company by such Member, (ii) such Member's share of the Company's items of income or gain, and (iii) the amount of any Company liabilities assumed by such Member or that are secured by property distributed to such Member.

(b)The Capital Account of each Member shall be debited by (i) the amount of cash and the Fair Value of property distributed to such Member, (ii) such Member's share of the Company's items of loss or deduction, and (iii) the amount of any liabilities of such Member assumed by the Company or that are secured by any property contributed by such Member to the Company.

(c)Upon the Transfer by a Member of all or part of an interest in the Company after the Effective Date, the Capital Account of the transferor that is attributable to the transferred interest carries over to the transferee and the Capital Accounts of the Members shall be adjusted to the extent provided in Treasury Regulations Section 1.704-1(b)(2)(iv)(m).

(d)In determining the amount of any liability for purposes of Sections A.3(a) and A.3(b), I.R.C. Section 752(c) and any other applicable provisions of the I.R.C. and the Treasury Regulations shall be taken into account.

(e)Except as otherwise required by Treasury Regulations Section 1.704-1(b)(2)(iv), adjustment to Capital Accounts in respect of Company income, gain, loss, deduction, and I.R.C. Section 705(a)(2)(B) expenditures (or items thereof) shall be made with reference to the federal tax treatment of such items (and, in the case of book items, with reference to the federal tax treatment of the corresponding tax items) at the Company level, without regard to any mandatory or elective tax treatment of such items at the Member level.

(f)The provisions of this Appendix and of the Agreement relating to the maintenance of Capital Accounts are intended to comply with Treasury Regulations Section 1.704-1(b)(2)(iv), and shall be interpreted and applied in a manner consistent with such Treasury Regulations. If the Manager determines that it is prudent to modify the manner in which the Capital Accounts, or any debits or credits thereto (including debits or credits relating to liabilities that are secured by contributions or distributed property or that are assumed by the Company or any Member), are computed in order to comply with such Treasury Regulations, the Manager may make such modification if it is not likely to have a material effect on the amounts distributed or to be distributed to any Member pursuant to the Agreement. The Manager shall make any adjustments that are necessary or appropriate (i) to maintain equality between the Capital Accounts of the Members and the amount of Company capital reflected on the Company's balance sheet, as computed for book purposes, in accordance with Treasury Regulations Section 1.704-1(b)(2)(iv)(g), and (ii) if unanticipated events (for example, the acquisition by the Company of oil or gas properties) might otherwise cause this Agreement not to comply with Treasury Regulations Section 1.704-1(b).

(g)The provisions of the proposed Treasury Regulations published on January 22, 2003 (68 Fed. Reg. 2930), as they may subsequently be modified or adopted as temporary or final Treasury Regulations, shall apply with respect to any noncompensatory options issued by the Company.

A.4Allocations of Net Profit and Net Loss

A.4.1In General

(a)Subject to the limitation in Section 4.1(d) below, items of income, gain, loss and deduction equal in amount to the Company's proportionate share of the items of income, gain, loss and deduction attributable to Cardinal's interest in Monroe Gas Storage shall be allocated to Class B Members in proportion to their ownership of Class B Interests.

(b)Subject to the limitation in Section 4.1(d) below, a deduction equal to twenty percent (20%) of Overhead Expenses shall be allocated to Class B Members in proportion to their ownership of Class B Interests.

(c)Subject to the limitation in Section 4.1(d) below, all remaining items of income, gain, loss and deduction of the Company shall be allocated to Class A Members in proportion to their ownership of Class A Interests.

(d)No Member may receive an allocation of loss or deduction that would cause the Member to have an Adjusted Capital Account Deficit at the end of the taxable year. Loss or deduction not allocated to a Member pursuant to this subparagraph (ii) shall be allocated to other Members according to their relative positive Capital Account balances (calculated taking into account the adjustments described in the definition of Adjusted Capital Account Deficit).

A.4.2Regulatory Allocations. The following special allocations shall be applied in the order in which they are listed. Such ordering is intended to comply with the ordering rules in Treasury Regulations Section 1.704-2(j) and shall be applied consistently therewith.

(a)Minimum Gain Chargeback. Except as otherwise provided in Treasury Regulations Section 1.704-2(f), anything to the contrary in this Section A.4 notwithstanding, if there is a net decrease in Partnership Minimum Gain during any taxable year, each Member shall be allocated items of income and gain for that taxable year (and, if necessary, subsequent taxable years) equal to that Member's share of the net decrease in Partnership Minimum Gain determined in accordance with Treasury Regulations Section 1.704-2(g)(2). This Section A.4.2(a) is intended to comply with the minimum gain chargeback requirement in Treasury Regulations Section 1.704-2(f) and shall be interpreted consistently therewith, including that no chargeback shall be required to the extent the requirements for requesting a waiver described in Treasury Regulations Section 1.704-2(f)(4) are met or the requirements for any other exception prescribed by or pursuant to Treasury Regulations Section 1.704-2(f) are met.

(b)Partner Nonrecourse Debt Minimum Gain Chargeback. Except as otherwise provided in Treasury Regulations Section 1.704-2(i)(4), anything to the contrary in this Section notwithstanding, if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during a taxable year, then, in addition to the amounts, if any, allocated pursuant to paragraph 4.2(a), any Member with a share of that Partner Nonrecourse Debt Minimum Gain (determined in accordance with Treasury Regulations Section 1.704-2(i)(5)) as of the beginning of the taxable year shall be allocated items of Company income and gain for that taxable year (and, if necessary, for subsequent taxable years) equal to that Member's share of the net decrease in the Partner Nonrecourse Debt Minimum Gain, determined in accordance with Treasury Regulations Section 1.704-2(i)(4). This Section A.4.2(b) is intended to comply with the chargeback of partner nonrecourse debt minimum gain required by Treasury Regulations Section 1.704-2(i)(4) and shall be interpreted consistently therewith, including that no chargeback shall be required to the extent the requirements for any exceptions provided in Treasury Regulation Section 1.704-2(i)(4) are met.

(c)Qualified Income Offset. If any Member unexpectedly receives any adjustment, allocation, or distribution described in Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), (5), or (6), items of Company income and gain shall be specially allocated to such Member in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations, the Adjusted Capital Account Deficit of such Member as quickly as possible. An allocation pursuant to the foregoing sentence shall be made only to the extent that such Member would have an Adjusted Capital Account Deficit after all other allocations provided for in Section A.4 have been tentatively made as if this Section A.4.2(c) were not in this Appendix. This allocation is intended to constitute a “qualified income offset” within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(d)(3) and shall be construed in accordance with the requirements thereof.

(d)Gross Income Allocation. In the event a Member has an Adjusted Capital Account Deficit at the end of any taxable year, each such Member shall be specially allocated items of Company income and gain in the amount of such Adjusted Capital Account Deficit as quickly as possible; provided that an allocation pursuant to this clause shall be made only if and to the extent that the Member would have an Adjusted Capital Account Deficit after all other allocations provided for in this Section A.4 have been made as if this Section A.4.2(d) were not in this Appendix.

(e)Nonrecourse Deductions. Nonrecourse Deductions for any taxable year shall be allocated among the Members in accordance with their relative Capital Account balances.

(f)Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable year shall be specially allocated to the Member who bears the economic risk of loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulations Section 1.704-2(i)(1).

(g)Basis Adjustments. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to I.R.C. Section 734(b) or I.R.C. Section 743(b) is required under Treasury Regulations Section 1.704-1(b)(2)(iv)(m) to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis) and such gain or loss shall be specially allocated to the Members in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

A.4.3Curative Allocations. The allocations set forth in Section A.4.2 hereof (the “Regulatory Allocations”) are intended to comply with certain requirements of the Treasury Regulations. The Members intend that, to the extent possible, all Regulatory Allocations shall be offset either with other Regulatory Allocations or with special allocations of other items of Company income, gain, loss, or deduction pursuant to this Section A.4.3. Therefore, any other provisions of this Section A.4 (other than the Regulatory Allocations) notwithstanding, the Manager shall make such offsetting special allocations of Company income, gain, loss, or deduction in whatever manner the Manager determines appropriate so that, after such offsetting allocations are made, each Member's Capital Account balance is, to the extent possible, equal to the Capital Account balance such Member would have had if the Regulatory Allocations were not part of the Agreement and all Company items were allocated pursuant to Section A.4.1. In exercising its discretion under this Section A.4.3, the Manager shall take into account future Regulatory Allocations under Sections A.4.2(a) and A.4.2(b) that, although not yet made, are likely to offset other Regulatory Allocations previously made under Sections A.4.2(e) and A.4.2(f).

A.4.4Other Allocation Rules

(a)Items of income, gain, loss or deduction, and other items shall be allocated to the Members pursuant to this Appendix A as of the last day of each taxable year, and at such times as the Gross Asset Values of Company Property are adjusted pursuant to subparagraph (ii) of the definition of Gross Asset Value.

(b)If during any taxable year any Member's Percentage Interest changes, each Member's share of Items of income, gain, loss or deduction, and other items for such taxable year shall be determined according to their varying interests and I.R.C. Section 706(d), using any conventions permitted by law and selected by the Manager.

(c)All allocations pursuant to this Appendix A shall, except as otherwise provided in this Agreement, be divided among the Members in proportion to the relative Capital Account balances held by each Member.

(d)For purposes of determining a Member's share of Company “excess nonrecourse liabilities” within the meaning of Treasury Regulations Section 1.752-3(a)(3), the Members' shares of Company profits shall be deemed to be in proportion to their respective Capital Contributions.

(e)To the extent permitted by Treasury Regulations Section 1.704-2(h)(3), the Manager may treat any distribution of the proceeds of a Nonrecourse Liability or a Partner Nonrecourse Debt (that would otherwise be allocable to an increase in Partnership Minimum Gain) as a distribution that is not allocable to an increase in Partnership Minimum Gain to the extent the distribution does not cause or increase an Adjusted Capital Account Deficit for any Member.

A.5Tax Allocations

(a)In General. Except as otherwise provided in this Section A.5, each item of income, gain, loss, and deduction of the Company for federal income tax purposes shall be allocated among the Members in the same manner as such items are allocated for book purposes under the Agreement and this Appendix A.

(b)Contributed or Revalued Property. In accordance with I.R.C. Section 704(c) and the related Treasury Regulations, income, gain, loss, and deduction with respect to any property contributed to the capital of the Company shall, solely for tax purposes, be allocated among the Members so as to take account of any variation between the adjusted basis of such property to the Company for federal income tax purposes and its Gross Asset Value. If the Gross Asset Value of any Company asset is adjusted pursuant to subparagraph (ii) of the definition of Gross Asset Value in Section A.2 hereof, subsequent allocations of income, gain, loss, and deductions with respect to such asset shall take account of any variation between the adjusted basis of such asset for federal income tax purposes and its Gross Asset Value in the same manner as under I.R.C. Section 704(c) and the related Treasury Regulations. Any elections or other decisions relating to allocations pursuant to this Section A.5 shall be made by the Manager in any manner that reasonably reflects the purpose and intention of this Appendix A and the Agreement.

(c)Credits. Except as otherwise required by Treasury Regulations Section 1.704-1(b)(4)(ii), items of tax credit and tax credit recapture shall be allocated among the Members in accordance with their relative Capital Account balances.

(d)Effect of Tax Allocations. Allocations pursuant to this Section A.5 are solely for purposes of U.S. federal, state, and local taxes and shall not affect any Member's Capital Account or share of Net Profit, Net Loss, or other items or distributions pursuant to any provision of this Appendix and the Agreement.

EX-10.7

EXHIBIT 10.7

SUPPLY AGREEMENT

THIS SUPPLY AGREEMENT (this “Agreement”), dated as of October 2, 2012, is entered into by and between Martin Operating Partnership L.P., a Delaware limited partnership (“Buyer”), and Cross Oil Refining & Marketing, Inc., a Delaware corporation (“Seller”), to be effective as of 12:01 AM Central Time on October 1, 2012 (the “Effective Time”).

The following provisions set forth the general terms and conditions under which Buyer will purchase from Seller, and Seller will supply to Buyer, the bulk base oils or lubricants specified in Exhibit A (each a “Product” and collectively “Products”).

1. PRODUCTS AND QUANTITY:During the term of this Agreement, Seller agrees to sell, and Buyer agrees to buy, Products from Seller in the minimum quantities set forth in Exhibit B (“Volume Commitment”). The Volume Commitment shall be broken down into commitments for each Contract Quarter (defined below) as specified in Exhibit B (“Quarterly Commitment”). In the event that Buyer fails to order 75% of the Quarterly Commitment in two successive Contract Quarters, the Volume Commitment and Quarterly Commitment will be reduced to the average amount purchased for each Product during such two Contract Quarters. The reduced commitments shall then become the Volume Commitment and Quarterly Commitment and shall replace the amounts shown in Exhibit B. Buyer may purchase additional gallons of Products as may be mutually agreed to by the parties in writing based on availability of the Products and pricing in Section 4. Additional volume in any Contract Quarter, however, shall not be applied to Quarterly Commitments in any other Contract Quarter.

2. TERM:This Agreement shall commence as of October 1, 2012 and continue until September 30, 2015, and thereafter shall automatically renew on a year-to-year basis unless either party provides ninety (90) days prior written notice of termination. Each twelve month period from the commencement of this Agreement shall be referred to as a “Contract Year,” and each three month period shall be referred to as a “Contract Quarter.”

3. SPECIFICATIONS: The Products shall meet the specifications set forth on Exhibit A or Seller's then current specifications for the Product as such specifications may be changed or altered pursuant to Section 13 (“Specifications”). If the Products do not meet the Specifications, Buyer shall have the right to reject or revoke its acceptance of the Products.

4. PRICE:The prices at which Seller shall invoice Buyer for the Products sold and delivered and the mechanisms for adjusting those prices are detailed in Exhibit C.

5. TAXES:Any tax, excise or other government charge imposed upon the production, sale or transportation of any Products sold hereunder which Seller may be required to pay, shall be paid by Buyer to Seller in addition to the price of the Products.

6. PAYMENT; CREDIT:Buyer shall remit payment to Seller in U.S. currency in accordance with the payment terms designated in each invoice. Payment shall be due within thirty (30) days from the date of the invoice. Seller shall have the right where permitted by law to assess a delinquency charge on each invoice not timely paid. Any credit Seller may elect to extend to Buyer shall be upon Seller's credit terms in effect at the time of Seller's acceptance of order. If, in Seller's judgment, Buyer's credit

is impaired or unsatisfactory, or if Buyer fails to make any payment due Seller, Seller may suspend deliveries until such time as Buyer has satisfactory credit arrangements with Seller or require Buyer to pay cash in advance.

7. TITLE:Title to the Products sold hereunder shall pass to Buyer upon delivery of such Product into the mode of transportation as follows: for tank trucks when the Product has actually been delivered into Buyer's tank; for railcars when the Product is delivered to Buyer's facility; and for pipelines upon metering of the Product at Buyer's facility.

8.DELIVERIES:Seller shall arrange transport of the Products, the selection of carrier and routing of shipments. Shipment of goods by Seller shall be made within a reasonable period of time after confirmation of Buyer's order. Seller reserves the right to ship, and Buyer agrees to accept and pay for the actual quantity delivered, within 5% plus or minus of the quantity ordered. Seller's weights and/or measurements taken at the shipping point shall control. Product measurement shall be determined by weighing, metering, or other recognized gauging method selected by Seller. Buyer assumes full responsibility for use and condition of tank trucks and railcars while in Buyer's possession and agrees to (a) compensate Seller for loss or damage to Seller's property, and (b) indemnify and save Seller harmless from any loss or damage to property other than Seller's and any injuries to persons relating in any way to the use of such tank trucks and railcars while such are in Buyer's possession. Buyer further agrees to report to Seller promptly any damage which may be sustained by the tank trucks and railcars in Buyer's possession.

9. CLAIMS:Claims as to shortage in quantity when compared to the billed amount, defects in quality, or any others, except for demurrage, shall be made by written notice to Seller within thirty (30) days after the delivery in question or such claim shall be deemed waived. Upon verification, Seller shall resolve such shortages or replace such defective Products without additional charges or, in lieu thereof, at Seller's option, Seller may refund the purchase price upon return of the Products at Seller's expense.

10. LIMITATION OF LIABILITY:NOTWITHSTANDING ANY OTHER PROVISION HEREIN AND REGARDLESS OF THE CIRCUMSTANCES, SELLER'S TOTAL LIABILITY TO BUYER FOR ANY AND ALL CLAIMS, LOSSES OR DAMAGES ARISING OUT OF ANY CAUSE WHATSOEVER, WHETHER BASED IN CONTRACT, NEGLIGENCE OR OTHER TORT, STRICT LIABILITY, BREACH OF WARRANTY OR OTHERWISE, SHALL IN NO EVENT EXCEED THE PURCHASE PRICE OF THE PRODUCTS IN RESPECT TO WHICH SUCH CLAIMS, LOSSES ARE DAMAGES AROSE. IN NO EVENT SHALL SELLER BE LIABLE FOR INCIDENTAL OR CONSEQUENTIAL DAMAGES. Any cause of action that Buyer may have against Seller arising from the sale of the Products hereunder must be commenced within one (1) year after the cause of action has accrued.

11. LIMITED WARRANTY:Seller warrants that the Products sold hereunder shall meet the Specifications for such Product at the time of delivery. OTHER THAN THE FOREGOING, SELLER MAKES NO WARRANTY, EXPRESS OR IMPLIED, INCLUDING BUT NOT LIMITED TO THOSE OF MERCHANTABILITY OR FITNESS OF THE PRODUCT FOR ANY PARTICULAR USE OR OTHERWISE, WHETHER USED SINGLY OR IN COMBINATION WITH OTHER SUBSTANCES OR IN ANY PROCESS.

12. TECHNICAL INFORMATION:Upon Buyer's request, Seller shall furnish to Buyer Material Safety Data Sheets and Certificates of Analysis for the Products hereunder. Any technical advice or assistance furnished by Seller to Buyer with respect to the selection or use of the Products sold to Buyer hereunder shall be given and accepted at Buyer's sole risk, and Seller shall have no liability whatsoever for the use of, or results obtained from, such advice or assistance whether or not based on negligence.

13. PRODUCT DISCONTINUANCE; SPECIFICATION CHANGES:Seller may at its discretion: (a) change or alter the quality or specifications of any Products sold hereunder; (b) discontinue the manufacture of any such Products; or (c) discontinue the manufacture of any such Products at a particular manufacturing or blending facility.

14. FORCE MAJEURE:Neither party shall be liable to the other for failure or delay in performance hereunder to the extent that such failure or delay is due to war, fire, flood, strike, lockout or other labor trouble, accident, breakdown of equipment or machinery, riot, act or request of governmental authority, act of God, or other contingencies beyond the control of the affected party which interfere with the production, throughput, or transportation of the Products sold hereunder or with the supply of any raw material, provided that in no event shall Buyer be relieved of the obligation to pay in full for Products received. The affected party shall use reasonable efforts to remedy the force majeure; provided, however, the settlement of strikes, lockouts, industrial disputes, or disturbances shall be entirely within the discretion of the party settling. The party affected by an event of force majeure shall give prompt written notice to the other party of the occurrence of such event.

15. ALLOCATION:Seller shall have the right to allocate goods or raw material in a fair and reasonable manner among its customers and own requirements.

16. ASSIGNMENT:Neither party shall assign its rights and obligations hereunder directly or indirectly without prior written consent of the other party, which shall not be withheld unreasonably. Notwithstanding the foregoing, either party may assign its rights and obligations hereunder to an affiliate of such party provided that the credit worthiness of such affiliate is not materially weaker than the credit worthiness of the assignor.

17. AMENDMENT:No amendment to, or modification, waiver or discharge of, any provision of this Agreement shall be binding on Seller or Buyer unless in writing and signed by authorized representatives of both parties.

18. TERMINATION:Either party may terminate this Agreement if the other party fails to perform in accordance with this Agreement and the defaulting party fails to correct such default within thirty (30) days of written notice of default by the non-defaulting party; provided, however, Seller may terminate this Agreement at its sole option immediately if (i) Buyer is liquidated, dissolved, or has a change of ownership or control; (ii) Buyer fails to pay Seller when due any amounts hereunder and such failure continues for ten (10) days after written notice of such failure from Seller; or (iii) Buyer voluntarily files a petition for bankruptcy for reorganization or to effect a plan or other arrangements with creditors or is adjudicated bankrupt or insolvent. Seller may also terminate this Agreement in its sole option if Buyer fails to order or refuses to accept delivery in any Contract Year of the Contract Year Volume; provided, however, Buyer shall have 30 days to cure by ordering Product equal to the

deficit in meeting the Volume Commitment for the Contract Year, which ordered amount of Product shall be excluded from calculating whether Buyer has met its Volume Commitment for the year in which such make-up purchase was made.

19. NOTICES:All notices and communications required or permitted to be given hereunder shall be considered to be given and received in all respects when personally delivered or sent by facsimile or sent by reputable overnight courier service or three (3) days after being deposited in the United States mail, certified, postage prepaid and return receipt requested to the following addresses:

Cross Oil Refining & Marketing, Inc.:Martin Operating Partnership L.P.:

484 E. 6th St.484 E. 6th St.

Smackover, AR 71762Smackover, AR 71762

Attn: Walter TysonAttn: Robert D. Bondurant

20. GOVERNING LAW:This contract shall be governed by and construed in accordance with Texas law without regard to conflicts of law rules. The parties hereto consent to the exclusive jurisdiction of the state and federal courts located in the State of Texas with regard to all disputes hereunder.

21. WAIVER: Any waiver by either party of any provision or condition of this Agreement shall not be construed or deemed to be a waiver of any other provisions or conditions.

22. SEVERABILITY:If any section of this Agreement shall be found to be unenforceable, such finding shall not affect the enforceability of any other section or the Agreement as a whole.

23. ENTIRE AGREEMENT:This Agreement and the attachments hereto, constitute the entire agreement between Buyer and Seller related to the purchase of the Products. Should any discrepancy exist between this Agreement and any supporting documents, such as Buyer's request for Products and Product receipts, the terms and conditions of this Agreement shall control. The parties agree that preprinted terms and conditions on a purchase or work order shall be of no force and effect, even if signed by both parties.

MARTIN OPERATING PARTNERSHIP L.P.

By: Martin Operating GP LLC, its general partner

By: Martin Midstream Partners L.P., its sole member

By: Martin Midstream GP LLC, its general partner

By: /s/ Robert D. Bondurant

Robert D. Bondurant, Executive Vice President

CROSS OIL REFINING & MARKETING, INC.

By: /s/ Donald R. Neumeyer

Donald R. Neumeyer, President

1

EXHIBIT A

Product Specifications

Cross B-60

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	9.06	11.09	9.65
Viscosity, cSt @ 100º C	D-445			2.39
Viscosity, SUS @ 100º F	D-2161	58	66	60.2
Viscosity, SUS @ 210º F	D-2161			34.3
Viscosity Index	D-2270			45
Gravity, API, 60º F	D-4052	24.3	29.3	25.5
Specific Gravity, 60/60º F	D-1250			0.9013
Pounds per Gallon @ 60º F	D-1250			7.505
Flash, COC, ºC (ºF)	D-92	118 (245)		138 (280)
Pour Point, ºC (ºF)	D-97		-48 (-55)	-57 (-70)
Color	D-1500		1.5	L 1.0
Aniline Point, C/F	D-611			69 (156)
Sulfur, Mass %	D-4294			0.06
Aromatic Carbon Atoms, %Ca	D-2140			16
Naphthenic Carbon Atoms, %Cn	D-2140			41
Paraffinic Carbon Atoms, %Cp	D-2140			43
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.58
Aromatics, Mass %	D-2007			29.13
Saturates, Mass %	D-2007			70.29
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-100

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	18.76	20.81	19.75
Viscosity, cSt @ 100º C	D-445			3.64
Viscosity, SUS @ 100º F	D-2161	100	110	104.9
Viscosity, SUS @ 210º F	D-2161			38.6
Viscosity Index	D-2270			36
Gravity, API, 60º F	D-4052	22.5	27.5	24.0
Specific Gravity, 60/60º F	D-1250			0.9100
Pounds per Gallon @ 60º F	D-1250			7.577
Flash, COC, ºC (ºF)	D-92	143 (290)		150 (300)
Pour Point, ºC (ºF)	D-97		-37 (-35)	-43 (-45)
Color	D-1500		L 2.0	L 1.5
Aniline Point, C/F	D-611			77 (171)
Sulfur, Mass %	D-4294			0.07
Aromatic Carbon Atoms, %Ca	D-2140			21
Naphthenic Carbon Atoms, %Cn	D-2140			32
Paraffinic Carbon Atoms, %Cp	D-2140			47
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.78
Aromatics, Mass %	D-2007			32.80
Saturates, Mass %	D-2007			66.42
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-150

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	28.77	31.64	29.5
Viscosity, cSt @ 100º C	D-445			4.5
Viscosity, SUS @ 100º F	D-2161	150	165	154
Viscosity, SUS @ 210º F	D-2161			41.4
Viscosity Index	D-2270			32
Gravity, API, 60º F	D-4052	21.5	26.5	23.5
Specific Gravity, 60/60º F	D-1250			0.9129
Pounds per Gallon @ 60º F	D-1250			7.602
Flash, COC, ºC (ºF)	D-92	149 (300)		154 (310)
Pour Point, ºC (ºF)	D-97		-32 (-25)	-37 (-35)
Color	D-1500		2.0	L 1.5
Aniline Point, C/F	D-611			78 (172)
Sulfur, Mass %	D-4294			0.06
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-200

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	38.4	43.3	41.08
Viscosity, cSt @ 100º C	D-445			5.39
Viscosity, SUS @ 100º F	D-2161	200	225	218
Viscosity, SUS @ 210º F	D-2161			44.4
Viscosity Index	D-2270			31
Gravity, API, 60º F	D-4052	21.0	26.0	22.1
Specific Gravity, 60/60º F	D-1250			0.9212
Pounds per Gallon @ 60º F	D-1250			7.671
Flash, COC, ºC (ºF)	D-92	145 (295)		150 (300)
Pour Point, ºC (ºF)	D-97		-29 (-20)	-37 (-35)
Color	D-1500		2.5	L 1.0
Aniline Point, C/F	D-611			81 (178)
Sulfur, Mass %	D-4294			0.10
Aromatic Carbon Atoms, %Ca	D-2140			18
Naphthenic Carbon Atoms, %Cn	D-2140			37
Paraffinic Carbon Atoms, %Cp	D-2140			45
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			1.67
Aromatics, Mass %	D-2007			34.51
Saturates, Mass %	D-2007			63.82
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-300

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	57.17	62.76	60
Viscosity, cSt @ 100º C	D-445			6.4
Viscosity, SUS @ 100º F	D-2161	300	330	316
Viscosity, SUS @ 210º F	D-2161			47.7
Viscosity Index	D-2270			23
Gravity, API, 60º F	D-4052	18.9	25.5	21
Specific Gravity, 60/60º F	D-1250			0.9279
Pounds per Gallon @ 60º F	D-1250			7.727
Flash, COC, ºC (ºF)	D-92	163 (325)		173 (340)
Pour Point, ºC (ºF)	D-97		-23 (-10)	-32 (-25)
Color	D-1500		L 3.0	L 1.5
Aniline Point, C/F	D-611			83 (181)
Sulfur, Mass %	D-4294		0.10	0.03
Aromatic Carbon Atoms, %Ca	D-2140			20
Naphthenic Carbon Atoms, %Cn	D-2140			34
Paraffinic Carbon Atoms, %Cp	D-2140			46
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			1.80
Aromatics, Mass %	D-2007			34.61
Saturates, Mass %	D-2007			63.59
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-550

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	96.9	108.1	103
Viscosity, cSt @ 100º C	D-445			9.04
Viscosity, SUS @ 100º F	D-2161	525	575	550
Viscosity, SUS @ 210º F	D-2161			57.0
Viscosity Index	D-2161			40
Gravity, API, 60º F	D-4052	20.0	24.4	22.2
Specific Gravity, 60/60º F	D-1250			0.9206
Pounds per Gallon @ 60º F	D-1250			7.666
Flash, COC, ºC (ºF)	D-92	180 (355)		195 (380)
Pour Point, ºC (ºF)	D-97		\-15 (+5)	-21 (-5)
Color	D-1500		3.0	L 2.0
Aniline Point, C/F	D-611			81 / 171
Sulfur, Mass %	D-4294			0.12
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			31
Paraffinic Carbon Atoms, %Cp	D-2140			50
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			2.39
Aromatics, Mass %	D-2007			34.81
Saturates, Mass %	D-2007			62.8
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-750

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	139.9	149.9	145.6
Viscosity, cSt @ 100º C	D-445			11.15
Viscosity, SUS @ 100º F	D-2161	750	800	780
Viscosity, SUS @ 210º F	D-2161			64.6
Viscosity Index	D-2161			40
Gravity, API, 60º F	D-4052	18.8	23.8	21.7
Specific Gravity, 60/60º F	D-1250			0.9236
Pounds per Gallon @ 60º F	D-1250			7.691
Flash, COC, ºC (ºF)	D-92	193 (380)		202 (395)
Pour Point, ºC (ºF)	D-97		-9 (+15)	-21 (-5)
Color	D-1500		3.5	L 2.0
Aniline Point, C/F	D-611			91 (196)
Sulfur, Mass %	D-4294			0.10
Aromatic Carbon Atoms, %Ca	D-2140			20
Naphthenic Carbon Atoms, %Cn	D-2140			28
Paraffinic Carbon Atoms, %Cp	D-2140			52
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			2.41
Aromatics, Mass %	D-2007			35.69
Saturates, Mass %	D-2007			61.90
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-1200

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445			192
Viscosity, cSt @ 100º C	D-445	13.4	14.5	14.07
Viscosity, SUS @ 100º F	D-2161			1,102
Viscosity, SUS @ 210º F	D-2161	74	78	74.4
Viscosity Index	D-2161			57
Gravity, API, 60º F	D-4052	18	23	20.5
Specific Gravity, 60/60º F	D-1250			0.9309
Pounds per Gallon @ 60º F	D-1250			7.752
Flash, COC, ºC (ºF)	D-92	199 (390)		227 (440)
Pour Point, ºC (ºF)	D-97		-9 (+15)	-15 (+5)
Color	D-1500		3.5	L2.0
Aniline Point, C/F	D-611			93 (200)
Sulfur, Mass %	D-4294			0.15
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			28
Paraffinic Carbon Atoms, %Cp	D-2140			53
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			2.55
Aromatics, Mass %	D-2007			35.80
Saturates, Mass %	D-2007			61.65
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross B-2400

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	439.0	494.0	472.0
Viscosity, cSt @ 100º C	D-445			23.69
Viscosity, SUS @ 100º F	D-2161	2,400	2,700	2,579
Viscosity, SUS @ 210º F	D-2161			117.5
Gravity, API, 60º F	D-4052	18.0	23.0	20.9
Specific Gravity, 60/60º F	D-1250			0.9285
Pounds per Gallon @ 60º F	D-1250			7.732
Flash, COC, Cº (Fº)	D-92	215 (420)		227 (440)
Pour Point, Cº (ºF)	D-97		-7 (+20)	-12 (+10)
Color	D-1500		3.5	L3.0
Aniline Point, Cº (ºF)	D-611			102 (216)
Viscosity-Gravity Constant	D-2501			0.853
Molecular Weight	D-2502			540
Refractive Index @ 20º C	D-1747			1.511
Refractivity Intercept	D-2159			1.047
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			28
Paraffinic Carbon Atoms, %CP	D-2140			53
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			3.2
Aromatics, Mass %	D-2007			40.4
Saturates, Mass %	D-2007			56.4
Sulfur, Mass %	D-4294			0.10
UV Absorptivity, 260 NM	D-2008			7.2
Volatility, 22 hr/225º F, % Mass	D-972			0.3
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-40

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	3.45	4.9	4.70
Viscosity, cSt @ 100º C	D-445			1.55
Viscosity, SUS @ 100º F	D-2161	38	44	42.3
Viscosity, SUS @ 210º F	D-2161			31.3
Gravity, API, 60º F	D-4052	27.6	30.6	27.7
Specific Gravity, 60/60º F	D-1250			0.8888
Pounds per Gallon @ 60º F	D-1250			7.401
Flash, COC, C (F)	D-92	118 (245)		124 (255)
Pour Point, C (ºF)	D-97		-57 (-70)	-68 (-90)
Color	D-1500		L 0.5	L 0.5
Aniline Point, C (ºF)	D-611			61 (142)
Viscosity-Gravity Constant	D-2501			0.876
Molecular Weight	D-2502			NA
Refractive Index @ 20º C	D-1747			1.483
Refractivity Intercept	D-2159			1.041
Kauri-Butanol Value	D-1133			38
Aromatic Carbon Atoms, %Ca	D-2140			9
Naphthenic Carbon Atoms, %Cn	D-2140			57
Paraffinic Carbon Atoms, %Cp	D-2140			34
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.05
Aromatics, Mass %	D-2007			27.6
Saturates, Mass %	D-2007			72.35
Sulfur, Mass %	D-4294		0.05	0.01
UV Absorptivity, 260 NM	D-2008			0.06
Volatility, 22 hr/225º F, % Mass	D-972			46.0
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-60

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	9.06	11.09	9.89
Viscosity, cSt @ 100º C	D-445			2.40
Viscosity, SUS @ 100º F	D-2161	58	66	61.2
Viscosity, SUS @ 210º F	D-2161			34.3
Gravity, API, 60º F	D-4052	22.6	27.6	25.6
Specific Gravity, 60/60º F	D-1250			0.9007
Pounds per Gallon @ 60º F	D-1250			7.500
Flash, COC, C (F)	D-92	143 (290)		154 (310)
Pour Point, C (ºF)	D-97		-51 (-60)	-57 (-70)
Color	D-1500		L 1.5	L 0.5
Aniline Point, C (ºF)	D-611			67 (153)
Viscosity-Gravity Constant	D-2501			0.877
Molecular Weight	D-2502			240
Refractive Index @ 20º C	D-1747			1.496
Refractivity Intercept	D-2159			1.047
Aromatic Carbon Atoms, %Ca	D-2140			16
Naphthenic Carbon Atoms, %Cn	D-2140			42
Paraffinic Carbon Atoms, %Cp	D-2140			42
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.10
Aromatics, Mass %	D-2007			29.9
Saturates, Mass %	D-2007			70.0
Sulfur, Mass %	D-4294		0.10	0.01
UV Absorptivity, 260 NM	D-2008			0.40
Volatility, 22 hr/225º F, % Mass	D-972			15.0
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-100

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	18.76	20.81	19.64
Viscosity, cSt @ 100º C	D-445			3.54
Viscosity, SUS @ 100º F	D-2161	100	110	104.6
Viscosity, SUS @ 210º F	D-2161			38.3
Gravity, API, 60º F	D-4052	21.6	26.4	24.4
Specific Gravity, 60/60º F	D-1250			0.9076
Pounds per Gallon @ 60º F	D-1250			7.558
Flash, COC, C (F)	D-92	154 (310)		163 (325)
Pour Point, C (ºF)	D-97		-37 (-35)	-46 (-51)
Color	D-1500		1.5	L 1.0
Aniline Point, C (ºF)	D-611			74 (165)
Viscosity-Gravity Constant	D-2501			0.870
Molecular Weight	D-2502			340
Refractive Index @ 20º C	D-1747			1.494
Refractivity Intercept	D-2159			1.040
Aromatic Carbon Atoms, %Ca	D-2140			17
Naphthenic Carbon Atoms, %Cn	D-2140			41
Paraffinic Carbon Atoms, %Cp	D-2140			42
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.35
Aromatics, Mass %	D-2007			30.2
Saturates, Mass %	D-2007			69.45
Sulfur, Mass %	D-4294		0.10	0.04
UV Absorptivity, 260 NM	D-2008			2.5
Volatility, 22 hr/225º F, % Mass	D-972			8.0
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-150

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	28.79	30.71	29.64
Viscosity, cSt @ 100º C	D-445			4.42
Viscosity, SUS @ 100º F	D-2161	150	160	154.8
Viscosity, SUS @ 210º F	D-2161			41.2
Gravity, API, 60º F	D-4052	20.8	25.4	23.6
Specific Gravity, 60/60º F	D-1250			0.9123
Pounds per Gallon @ 60º F	D-1250			7.597
Flash, COC, C (F)	D-92	166 (330)		172 (340)
Pour Point, C (ºF)	D-97		-32 (-25)	-43 (-45)
Color	D-1500		1.5	L 1.0
Aniline Point, C (ºF)	D-611			77 (171)
Viscosity-Gravity Constant	D-2501			0.874
Molecular Weight	D-2502			345
Refractive Index @ 20º C	D-1747			1.498
Refractivity Intercept	D-2159			1.040
Aromatic Carbon Atoms, %Ca	D-2140			17
Naphthenic Carbon Atoms, %Cn	D-2140			37
Paraffinic Carbon Atoms, %Cp	D-2140			46
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.5
Aromatics, Mass %	D-2007			32.0
Saturates, Mass %	D-2007			67.5
Sulfur, Mass %	D-4294		0.10	0.04
UV Absorptivity, 260 NM	D-2008			3.0
Volatility, 22 hr/225º F, % Mass	D-972			6.1
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-200

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	39.32	43.1	41.8
Viscosity, cSt @ 100º C	D-445			5.25
Viscosity, SUS @ 100º F	D-2161	205	225	218
Viscosity, SUS @ 210º F	D-2161			43.9
Gravity, API, 60º F	D-4052	20.4	25.4	23.3
Specific Gravity, 60/60º F	D-1250			0.9141
Pounds per Gallon @ 60º F	D-1250			7.612
Flash, COC, C (F)	D-92	177 (350)		181 (360)
Pour Point, C (ºF)	D-97		-29 (-20)	-34 (-30)
Color	D-1500		2.0	L1.5
Aniline Point, C (ºF)	D-611			79 (174)
Viscosity-Gravity Constant	D-2501			0.874
Molecular Weight	D-2502			340
Refractive Index @ 20º C	D-1747			1.508
Refractivity Intercept	D-2159			1.051
Aromatic Carbon Atoms, %Ca	D-2140			17
Naphthenic Carbon Atoms, %Cn	D-2140			36
Paraffinic Carbon Atoms, %Cp	D-2140			47
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.6
Aromatics, Mass %	D-2007			32.4
Saturates, Mass %	D-2007			67.0
Sulfur, Mass %	D-4294		0.10	0.05
UV Absorptivity, 260 NM	D-2008			3.6
Volatility, 22 hr/225º F, % Mass	D-972			5.0
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-300

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	57.17	62.76	59.85
Viscosity, cSt @ 100º C	D-445			6.44
Viscosity, SUS @ 100º F	D-2161	300	330	315.5
Viscosity, SUS @ 210º F	D-2161			47.9
Gravity, API, 60º F	D-4052	19.9	24.3	22.1
Specific Gravity, 60/60º F	D-1250			0.9212
Pounds per Gallon @ 60º F	D-1250			7.671
Flash, COC, C (F)	D-92	182 (360)		188 (370)
Pour Point, C (ºF)	D-97		-26 (-15)	-32 (-25)
Color	D-1500			L 1.5
Aniline Point, C (ºF)	D-611			82 (180)
Viscosity-Gravity Constant	D-2501			0.871
Molecular Weight	D-2502			370
Refractive Index @ 20º C	D-1747			1.508
Refractivity Intercept	D-2159			1.047
Aromatic Carbon Atoms, %Ca	D-2140			18
Naphthenic Carbon Atoms, %Cn	D-2140			35
Paraffinic Carbon Atoms, %Cp	D-2140			47
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.6
Aromatics, Mass %	D-2007			34.8
Saturates, Mass %	D-2007			64.6
Sulfur, Mass %	D-4294		0.10	0.06
UV Absorptivity, 260 NM	D-2008			3.9
Volatility, 22 hr/225º F, % Mass	D-972			3.0
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-500

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	94.4	103.3	97.8
Viscosity, cSt @ 100º C	D-445			8.29
Viscosity, SUS @ 100º F	D-2161	500	550	522
Viscosity, SUS @ 210º F	D-2161			54.3
Gravity, API, 60º F	D-4052	19.3	23.5	21.4
Specific Gravity, 60/60º F	D-1250			0.9254
Pounds per Gallon @ 60º F	D-1250			7.707
Flash, COC, C (F)	D-92	195 (380)		200 (390)
Pour Point, C (ºF)	D-97		-15 (+5)	-25 / (-13)
Color	D-1500		2.0	L 1.5
Aniline Point, C (ºF)	D-611			84 (183)
Viscosity-Gravity Constant	D-2501			0.870
Molecular Weight	D-2502			490
Refractive Index @ 20º C	D-1747			1.510
Refractivity Intercept	D-2159			1.047
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			35
Paraffinic Carbon Atoms, %Cp	D-2140			46
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.90
Aromatics, Mass %	D-2007			40.5
Saturates, Mass %	D-2007			58.6
Sulfur, Mass %	D-4294		0.10	0.08
UV Absorptivity, 260 NM	D-2008			5.3
Volatility, 22 hr/225º F, % Mass	D-972			1.8
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-750

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	139.9	149.0	143.47
Viscosity, cSt @ 100º C	D-445			10.35
Viscosity, SUS @ 100º F	D-2161	750	800	772
Viscosity, SUS @ 210º F	D-2161			61.6
Viscosity Index	D-2270			19
Gravity, API, 60º F	D-4052	18.7	22.8	20.7
Specific Gravity, 60/60º F	D-1250			0.9297
Pounds per Gallon @ 60º F	D-1250			7.742
Flash, COC, C (F)	D-92	204 (400)		215 (420)
Pour Point, C (ºF)	D-97		-12 (+10)	-18 (0)
Color	D-1500		2.5	L 1.5
Aniline Point, C (ºF)	D-611			86 (187)
Viscosity-Gravity Constant	D-2501			0.871
Molecular Weight	D-2502			420
Refractive Index @ 20º C	D-1747			1.514
Refractivity Intercept	D-2159			1.052
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			34
Paraffinic Carbon Atoms, %Cp	D-2140			47
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			0.85
Aromatics, Mass %	D-2007			40.55
Saturates, Mass %	D-2007			58.6
Sulfur, Mass %	D-4294		0.10	0.08
UV Absorptivity, 260 NM	D-2008			5.8
Volatility, 22 hr/225º F, % Mass	D-972			1.0
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-1200

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	203.3	239.4	234.9
Viscosity, cSt @ 100º C	D-445			13.47
Viscosity, SUS @ 100º F	D-2161	1,100	1,300	1,281
Viscosity, SUS @ 210º F	D-2161	70		73.8
Gravity, API, 60º F	D-4052	19.4	22.8	21.1
Specific Gravity, 60/60º F	D-1250			0.9273
Pounds per Gallon @ 60º F	D-1250			7.722
Flash, COC, Cº (Fº)	D-92	221 (430)		235 (455)
Pour Point, Cº (ºF)	D-97		-7 (+20)	-12 (+10)
Color	D-1500		3.5	L 2.0
Aniline Point, Cº (ºF)	D-611	90 (194)	98 (208)	90 (194)
Viscosity-Gravity Constant	D-2501			0.861
Molecular Weight	D-2502			460
Refractive Index @ 20º C	D-1747			1.510
Refractivity Intercept	D-2159			1.046
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			33
Paraffinic Carbon Atoms, %Cp	D-2140			48
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			2.0
Aromatics, Mass %	D-2007			39.4
Saturates, Mass %	D-2007			58.6
Sulfur, Mass %	D-4294			0.08
UV Absorptivity, 260 NM	D-2008			6.7
Volatility, 22 hr/225º F, % Mass	D-972			0.4
DMSO Extract, wt.%	IP-346		< 3.0	< 3.0

Cross L-1500

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	277.6	313.6	295
Viscosity, cSt @ 100º C	D-445	16.1	17.26	17.6
Viscosity, SUS @ 100º F	D-2161	1,500	1,700	1,575
Viscosity, SUS @ 210º F	D-2161	84.5	89.2	86.2
Gravity, API, 60º F	D-4052	19.5	22.5	21.1
Specific Gravity, 60/60º F	D-1250			0.9273
Pounds per Gallon @ 60º F	D-1250			7.722
Flash, COC, Cº (Fº)	D-92	226 (440)		238 (460)
Pour Point, Cº (ºF)	D-97		-4 (+40)	-9 (+15)
Color	D-1500		3.5	L2.5
Aniline Point, Cº (ºF)	D-611			94 (201)
Viscosity-Gravity Constant	D-2501			.858
Molecular Weight	D-2502			480
Refractive Index @ 20º C	D-1747			1.510
Refractivity Intercept	D-2159			1.046
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			33
Paraffinic Carbon Atoms, %Cp	D-2140			48
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			2.5
Aromatics, Mass %	D-2007			39.8
Saturates, Mass %	D-2007			57.7
Sulfur, Mass %	D-4294			0.09
UV Absorptivity, 260 NM	D-2008			7.0
Volatility, 22 hr/225º F, % Mass	D-972			0.3
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-2000

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	350.6	387.5	369.33
Viscosity, cSt @ 100º C	D-445			18.06
Viscosity, SUS @ 100º F	D-2161	1,900	2,100	2,031
Viscosity, SUS @ 210º F	D-2161			93.1
Gravity, API, 60º F	D-4052	19.5	22.5	21.0
Specific Gravity, 60/60º F	D-1250			0.9279
Pounds per Gallon @ 60º F	D-1250			7.727
Flash, COC, Cº (Fº)	D-92	233 (450)		246 (475)
Pour Point, Cº (ºF)	D-97		+1 (+34)	-15 (+5)
Color	D-1500		4.0	L 2.0
Aniline Point, Cº (ºF)	D-611			98 (208)
Viscosity-Gravity Constant	D-2501			0.854
Molecular Weight	D-2502			500
Refractive Index @ 20º C	D-1747			1.510
Refractivity Intercept	D-2159			1.046
Aromatic Carbon Atoms, %Ca	D-2140			17
Naphthenic Carbon Atoms, %Cn	D-2140			35
Paraffinic Carbon Atoms, %CP	D-2140			48
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			2.9
Aromatics, Mass %	D-2007			40.2
Saturates, Mass %	D-2007			56.9
Sulfur, Mass %	D-4294			0.10
UV Absorptivity, 260 NM	D-2008			6.8
Volatility, 22 hr/225º F, % Mass	D-972			0.3
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-2400

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445	402.2	470.5	441.70
Viscosity, cSt @ 100º C	D-445			21.92
Viscosity, SUS @ 100º F	D-2161	2,200	2,600	2,421
Viscosity, SUS @ 210º F	D-2161			110.2
Gravity, API, 60º F	D-4052	19.0	22.0	21.0
Specific Gravity, 60/60º F	D-1250			0.9279
Pounds per Gallon @ 60º F	D-1250			7.727
Flash, COC, Cº (Fº)	D-92	240 (465)		248 (480)
Pour Point, Cº (ºF)	D-97		0 (+32)	-10 (+15)
Color	D-1500		4.0	2.5
Aniline Point, Cº (ºF)	D-611			98 (208)
Viscosity-Gravity Constant	D-2501			0.853
Molecular Weight	D-2502			540
Refractive Index @ 20º C	D-1747			1.511
Refractivity Intercept	D-2159			1.047
Aromatic Carbon Atoms, %Ca	D-2140			19
Naphthenic Carbon Atoms, %Cn	D-2140			28
Paraffinic Carbon Atoms, %CP	D-2140			53
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			3.2
Aromatics, Mass %	D-2007			40.4
Saturates, Mass %	D-2007			56.4
Sulfur, Mass %	D-4294			0.15
UV Absorptivity, 260 NM	D-2008			7.2
Volatility, 22 hr/225º F, % Mass	D-972			0.3
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross L-3500

TEST NAME	TEST METHOD	SPECIFICATIONS
		Minimum	Maximum	Typical
Viscosity, cSt @ 40º C	D-445			737.85
Viscosity, cSt @ 100º C	D-445	26	36	30.59
Viscosity, SUS @ 100º F	D-2161			4,081
Viscosity, SUS @ 210º F	D-2161	135	170	150.7
Gravity, API, 60º F	D-4052	19.2	22.2	20.1
Specific Gravity, 60/60º F	D-1250			0.9334
Pounds per Gallon @ 60º F	D-1250			7.773
Flash, COC, Cº (Fº)	D-92	250 (480)		258 (495)
Pour Point, Cº (ºF)	D-97		+4 (+40)	-1 (+30)
Color	D-1500		5.5	4.0
Aniline Point, Cº (ºF)	D-611			101(214)
Viscosity-Gravity Constant	D-2501			0.8479
Molecular Weight	D-2502			560
Refractive Index @ 20º C	D-1747			1.517
Refractivity Intercept	D-2159			1.054
Aromatic Carbon Atoms, %Ca	D-2140			20
Naphthenic Carbon Atoms, %Cn	D-2140			24
Paraffinic Carbon Atoms, %Cp	D-2140			56
Asphaltenes, Mass %	D-2007			—
Polar Compounds, Mass %	D-2007			7.2
Aromatics, Mass %	D-2007			38.7
Saturates, Mass %	D-2007			54.1
Sulfur, Mass %	D-4294			0.22
UV Absorptivity, 260 nm	D-2008			8.94
Volatility, 22 hr/225º F, % Mass	D-972			0.1
DMSO Extract, wt.%	IP-346		3.0	< 3.0

Cross CrossTrans 206

	ASTM
Property	Method	Specifications	Typical
Aniline Point, C	D-611	63/84	68
Color	D-1500	0.5 Maximum	L0.5
Flash Point, C	D-92	146 Minimum	150
Interfacial Tension @ 25C, dynes/cm	D-971	40 Minimum	50
Pour Point, C	D-97	-46 Maximum	(54)
Specific Gravity, 15C/15C	D-1298	0.906 Maximum	0.894
Viscosity, cSt (SUS):	D-445
@ 100 C		3.0 (36) Maximum	2.34
@ 40 C		12.0 (66) Maximum	9.54
@ 0 C		76.0 (350) Maximum	61.9
Visual Examination	D-1524	Clear and Bright	Clear and Bright
Dielectric breakdown voltage,	D-877
60 Hz: Disc electrodes, KV		30 Minimum	50
Dielectric breakdown voltage,	D-1816
60 Hz: VDE Electrode, KV		28 Minimum	36
Dielectric breakdown voltage,	D-3300
Impulse Cond. 25C, 25.4 mm gap		145 Minimum	160
Gassing Tendency, uL/min	D-2300B	#VALUE!	(10)
Power Factor @ 60 Hz, %, max	D-924
@ 25 C		0.05 Maximum	<0.001
@ 100 C		0.30 Maximum	0.05
Oxidation Stability @ 72 Hours	D-2440
% Sludge, by Mass		0.10 Maximum	<0.01
Total Acid Number mg KOH/g		0.30 Maximum	<0.01
Oxidation Stability @ 164 Hours	D-2440
% Sludge, by Mass		0.20 Maximum	<0.01
Total Acid Number mg KOH/g		0.40 Maximum	<0.01
Rotating Bomb, minutes	D-2112	195 Minutes	350
Oxidation Inhibitor, % Mass	D-2668	0.30 Maximum	0.25
Water, ppm	D-1533	30 Maximum	12
Neutralization Number, mg KOH/g	D-974	0.03 Maximum	<0.01
Corrosive Sulfur	D-1275	Non-corrosive	Non-corrosive
PCB Content, ppm	D-4059	None detected	None detected
CrossTrans 206 complies fully with the following Specifications:
ASTM D-3487, Type II (High Inhibitor)
Doble TOPS-884, Inhibited Type II
BS 148:1984, Class IIA (Inhibited)
IEC 296:1982, Class IIA (Inhibited)
CAN/CSA-C50-97, Type II (Class B)

EXHIBIT B

Volume Commitment

Seller's total Volume Commitment to Buyer through September 30, 2015 is 40,500,000 gallons.

Seller shall supply and Buyer shall purchase from Seller no less than the volume of Products specified below in each Contract Quarter and Contract Year:

Contract Quarterly

Time Period:Year Volume:Minimum Requirement:

• Contract Year One (1): 13,000,000 gals3,250,000 gals

• Contract Year Two (2): 13,500,000 gals 3,375,000 gals

• Contract Year Three (3): 14,000,000 gals 3,500,000 gals

Contract Year One Example: Minimum order/delivery volumes for any given Contract Quarter will not be less than 2,437,500 gallons (“Quarterly Minimum Requirement”). In the event the Buyer fails to order 75% of the Contract Quarterly Minimum Requirement in a Contract Quarter, Seller's obligations hereunder may be reduced proportionately with any such reductions if Seller so desires.  If Seller reduces the volume Buyer can buy for a Contract Year, the committed gallons per Contract Quarter and Volume Commitment for the next Contract Year will be adjusted to reflect the lower purchase volumes. 

The delivered volume mix for any given Contract Quarter shall be as follows:

• Light grade product (40 to 200 SUS) shall be approximately 30% of the quarterly delivered volume

• Medium grade product (300 to 750 SUS) shall be approximately 60% of the delivered quarterly volume

• Heavy grade product (800 to 3500 SUS) shall be approximately 10% of the quarterly delivered volume

EXHIBIT C

Pricing

Pricing shall be the Posted Price (as defined below) for the first day of the month if the bill of lading is dated the first day through the fourteenth day of the month.  Pricing shall be the Posted Price for the fifteenth day of the month if the bill of lading is dated the fifteenth day through the last day of the month.  “Posted Price” means the spot low posting for Naphthenic base oils in U.S. Dollars per gallon, as listed in the ICIS Pricing Base Oils (USA) Naphthenic published posted prices table.  Pricing for all grade 40-500 SUS will be priced at the lowest Posted Price for any grade in the 40-500 range.  Pricing for all grades greater than or equal to 750 SUS will be priced at the Posted Price specific to the grade.

All Product pricing is delivered pricing.

EX-10.8

EXHIBIT 10.8

NONCOMPETITION AGREEMENT

This Noncompetition Agreement (“Agreement”), dated as of October 2, 2012 (the “Closing Date”), but effective as of 12:01 A.M. Central Time, October 1, 2012 (the “Effective Time”), is by and among Martin Operating Partnership L.P., a Delaware limited partnership (the “Buyer”), Cross Oil Refining & Marketing, Inc., a Delaware corporation (the “Seller”), and Martin Resource Management Corporation, a Texas corporation (the “Guarantor”, and together with the Seller, the “Selling Parties”). Capitalized terms used herein, but not otherwise defined shall have the meaning ascribed to such terms in the Asset Purchase Agreement, dated of even date herewith (the “Asset Purchase Agreement”), by and among the Buyer, the Seller, the Guarantor and Martin Midstream Partners L.P.

WHEREAS, pursuant to the terms of the Asset Purchase Agreement, the Buyer is acquiring the Purchased Assets (the “Sale”) from the Seller;

WHEREAS, the Selling Parties will receive substantial economic benefit upon the Closing of the Sale;

WHEREAS, the Buyer's willingness to enter into the Asset Purchase Agreement and to consummate the Sale is explicitly conditioned upon the Selling Parties entering into this Agreement in order to protect the value of the Purchased Assets to be acquired by the Buyer;

WHEREAS, the Buyer desires to be assured that the confidential information of the Seller relating to the Purchased Assets acquired by the Buyer will be preserved for the exclusive benefit of the Buyer following the Sale; and

NOW, THEREFORE, in consideration of the foregoing recitals and the mutual covenants and promises herein contained, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties agree as follows:

Section 1. Acknowledgments and Agreements by the Selling Parties. Each of the Selling Parties hereby acknowledges and agrees that:

(a)The Buyer would not consummate the transactions contemplated in the Asset Purchase Agreement if the Selling Parties did not execute and deliver this Agreement to the Buyer at Closing;

(b)Each of the Selling Parties has had access to information that is confidential to the Seller and that relates to the Purchased Assets and that constitutes a valuable, special and unique asset of the Seller, and that will, after the Closing, constitute a valuable, special and unique asset of the Buyer, and with respect to which the Buyer is entitled to the protections afforded by this Agreement and to the remedies for enforcement of this Agreement provided by Law or in equity (including, without limitation, those remedies the availability of which may be within the discretion of the court in which any action for enforcement of this Agreement is brought); and

(c)In consideration of the purchase by the Buyer of the Purchased Assets, the Selling Parties will receive substantial economic benefit.

Section 2. Confidentiality/Non-Disclosure. In consideration of the purchase by Buyer of the Purchased Assets, each of the Selling Parties agrees that it will not at any time after the Effective Time reveal or use in any unauthorized manner or for any unauthorized purpose (or facilitate any of the foregoing) any

business methods that are confidential or proprietary, lists of customers, business secrets, business relationships, product and sales information that is confidential or proprietary, financial information, future plans, operating procedures that are confidential or proprietary, trade secrets or other confidential or proprietary information that relate to the Purchased Assets (including any of the same acquired from the Seller in the Sale) except for any such information which (a) at the time it was received by the Selling Parties was in the public knowledge, (b) after being received by the Selling Parties became part of the public knowledge through no fault of the Selling Parties, or (c) is required to be disclosed by the Selling Parties pursuant to any applicable Law or in any Actions or Proceedings.

Section 3. Non-Competition. For the period commencing after the Effective Time and ending on the last to occur of (a) the third anniversary of the Closing Date or (b) the termination of the Supply Agreement, the Selling Parties will not, and will cause each of their Affiliates not to, directly or indirectly own, manage, operate, join, control or participate in the ownership, management, operation or control of, any Person, which is the same as, substantially the same as, or substantially similar to the Business or the Purchased Assets being transferred, under the Asset Purchase Agreement. Further, the Selling Parties will not, and will cause each of their Affiliates not to, solicit directly or indirectly any current customers of the Seller or the Buyer for any business related to the Purchased Assets or the Business being transferred in competition with the Buyer, other than in connection with the Seller's solicitation of customers in connection with the Seller's marketing of products produced by the Business after Closing as contemplated by the Asset Purchase Agreement. For the purposes of this Agreement, a Person shall be deemed to be in competition with the Business or the Purchased Assets only if the products or services of such Person are substantially similar in function or capability to the products or services being offered, developed, manufactured or sold by the Business being sold to the Buyer. The mere passive ownership, direct or indirect, of not more than 5% of the outstanding stock of any publicly traded company shall not be a violation of this paragraph. The restriction in this Section 3 shall apply only to the reasonable and limited geographic area consisting of all locations within the States of Arkansas, Kansas, Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and Texas (the “Restricted Area”). In addition, in the event that the Buyer is presented with the opportunity to participate, through ownership or otherwise, in a lubricants blending and packaging business within the Restricted Area and determines (based on a decision by the Parent's Board of Directors with the concurrence of the Conflicts Committee of such Board of Directors) not to participate in such opportunity, the Buyer shall provide written notice of such determination to the Selling Parties. Thereafter, nothing in this Agreement shall prohibit the Selling Parties from pursuing such opportunity, and participating in such lubricants blending and packing business, if such transaction is successful.

Section 4. Remedies. Each of the Selling Parties agree that the remedies at Law for any breach or threatened breach by it of the provisions of Section 2 or Section 3 will be inadequate, and that the Buyer or its Affiliates shall be entitled to a temporary restraining order, preliminary injunction and/or injunction, without the need to post any bond therefor, to prevent breaches of such paragraphs and to enforce specifically the terms and conditions thereof, in addition to any other remedy to which the Buyer or its Affiliates may be entitled by Law or in equity.

Section 5. Severable Provisions. The provisions of this Agreement are severable and the invalidity of any one or more provisions shall not affect the validity of any other provision. Each of the Selling Parties acknowledges and agrees that the scope of this Agreement is reasonable and no greater than required for the protection of the legitimate business interests of the Buyer in the Purchased Assets, it imposes no undue hardship on the Selling Parties, and in the event that a court of competent jurisdiction shall determine that any provision of this Agreement or the application thereof is unenforceable in whole or in part because of the duration or scope thereof, the parties hereto agree that said court in making such determination shall have

the power to reduce the duration and scope of such provision to the extent necessary to make it enforceable, and that the Agreement in its reduced form shall be valid and enforceable to the full extent permitted by Law.

Section 6. Miscellaneous.

Section 6.01. Modification. This Agreement, the Asset Purchase Agreement and the Related Agreements constitute the entire agreement between the parties hereto with regard to the Selling Parties' obligations hereunder, superseding all prior understandings and agreements, whether written or oral. This Agreement may not be amended or revised except by a writing signed by the parties hereto.

Section 6.02. Assignment and Transfer. This Agreement shall not be terminated by the merger or consolidation of the Buyer or the Seller or any of their respective Affiliates with any corporate or other entity or by the transfer of all or substantially all of the assets of the Buyer or any of its Affiliates to any other person, corporation, firm or entity. The provisions of this Agreement shall be binding on and shall inure to the benefit of any such successor in interest to the Buyer or the Seller or any of their respective Affiliates.

Section 6.03. Captions. Captions herein have been inserted solely for convenience of reference and in no way define, limit or describe the scope or substance of any provision of this Agreement.

Section 6.04. Governing Law. This Agreement is entered into under, and shall be governed for all purposes by, the laws of the State of Texas, without regard to its conflicts of law rules. Any suit by the Buyer or the Selling Parties to enforce any right hereunder or to obtain a declaration of any right or obligation hereunder must be brought in a federal or state court located in Gregg County, Texas. The Selling Parties and the Buyer hereby each expressly consent to the jurisdiction of any federal or state court located in Gregg County, Texas and consent to the service of process on such party at the address set forth in Section 6.05 below.

Section 6.05. Notices. All notices and other communications hereunder shall be in writing and shall be deemed to have been duly given when (a) delivered personally, (b) sent by telecopier (with receipt confirmed), provided that a copy is mailed by registered or certified mail, return receipt requested, or (c) received by the addressee, if sent by Express Mail, Federal Express or other express delivery service (receipt requested) or by registered or certified mail, return receipt requested, in each case to the other party at the following addresses and telecopier numbers (or to such other address or telecopier number for a party as shall be specified by like notice; provided that notices of a change of address or telecopier number shall be effective only upon receipt thereof):

To the Selling Parties: Martin Resource Management Corporation

4200 Stone Road

Kilgore, Texas

Attn: Chris Booth

Telephone:(903) 983-6200

Telecopy:(903) 983-6262

To the Buyer: Martin Operating Partnership L.P.

4200 Stone Road

Kilgore, Texas 75662

Attention: Chris Booth

Telephone:(903) 983-6200

Telecopy:(903) 983-6262

IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written to be effective as of the Effective Time.

BUYER:

MARTIN OPERATING PARTNERSHIP L.P.

By: Martin Operating GP LLC, its general partner

By: Martin Midstream Partners L.P., its sole member

By: Martin Midstream GP LLC, its general partner

By: /s/ Robert D. Bondurant

Name:Robert D. Bondurant

Title:Executive Vice President

SELLER:

CROSS OIL REFINING & MARKETING, INC.

By: /s/ Donald R. Neumeyer

Name:Donald R. Neumeyer

Title:President

GUARANTOR:

MARTIN RESOURCE MANAGEMENT CORPORATION

By: /s/ Robert D. Bondurant

Name:Robert D. Bondurant

Title:Executive Vice President

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

Pursuant to 15 U.S.C. 78m(a) or 78o(d)

(Section 302 of the Sarbanes-Oxley Act of 2002)

I, Ruben S. Martin, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Martin Midstream Partners L.P.;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.  Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.  Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.  Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.  Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.  All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:     November 5, 2012

/s/ Ruben S. Martin

Ruben S. Martin, President and

Chief Executive Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

Pursuant to 15 U.S.C. 78m(a) or 78o(d)

(Section 302 of the Sarbanes-Oxley Act of 2002)

I, Robert D. Bondurant, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Martin Midstream Partners L.P.;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.  Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.  Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.  Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.  Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.  All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.  Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:      November 5, 2012

/s/ Robert D. Bondurant

Robert D. Bondurant, Executive Vice President and

Chief Financial Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C.  SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002*

In connection with the Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ended September 30, 2012, as filed with the Securities and Exchange Commission (the “Report”), I, Ruben S. Martin, Chief Executive Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

(1)          the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Ruben S. Martin

Ruben S. Martin,

Chief Executive Officer of Martin Midstream GP LLC,

General Partner of Martin Midstream Partners L.P.

November 5, 2012

*A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C.  SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002*

In connection with the Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ended September 30, 2012, as filed with the Securities and Exchange Commission (the “Report”), I, Robert D. Bondurant, Chief Financial Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Robert D. Bondurant

Robert D. Bondurant,

Chief Financial Officer

of Martin Midstream GP LLC,

General Partner of Martin Midstream Partners L.P.

November 5, 2012

*A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Discontinued operations and divestitures (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended		3 Months Ended				9 Months Ended
	Sep. 30, 2012	Jul. 31, 2012	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Discontinued Operation, Intercompany Amounts with Discontinued Operation before Disposal Transaction, Revenue			$ 3,285		$ 17,741		$ 26,431		$ 49,444
Proceeds from Divestiture of Businesses	1,530	273,269
Unconsolidated interest ownership	50.00%		50.00%				50.00%
Assets [Abstract]
Investment in unconsolidated entities	0		0				0				107,549
Assets held for sale	0		0				0				212,787
Liabilities [Abstract]
Liabilities held for sale	0		0				0				501
Operations [Abstract]
Total costs and expenses, excluding depreciation and amortization			(303,026)		(281,637)		(872,917)		(771,149)
Depreciation and amortization			(9,966)		(10,025)		(29,457)		(29,523)
Equity in earnings of Waskom, Matagorda, and PIPE			377		1,839		4,611		6,854
Income from discontinued operations, net of income taxes			63,603		2,265		67,312		7,728
Transaction costs related to the disposition			62,251		61,411		62,251		61,411
Prism Gas [Member]
Assets [Abstract]
Inventories											486
Property, plant and equipment											78,324
Accumulated depreciation											(18,438)
Goodwill											28,931
Investment in unconsolidated entities											107,549
Other assets, net											15,935
Assets held for sale											212,787
Liabilities [Abstract]
Other long-term obligations											501
Liabilities held for sale											501
Operations [Abstract]
Total revenues from third parties			9,269	[1]	28,714	[1]	66,842	[1]	90,917	[1]
Total costs and expenses, excluding depreciation and amortization			(9,296)		(26,892)		(64,556)		(85,888)
Depreciation and amortization			0		(1,375)		(2,320)		(4,128)
Other operating income			62,251	[2]	0	[2]	61,421	[2]	3	[2]
Equity in earnings of Waskom, Matagorda, and PIPE			377		1,839		4,611		6,854
Income from discontinued operations before income taxes			62,601		2,286		65,998		7,758
Income tax expense (benefit)			(1,002)		21		(1,314)		30
Income from discontinued operations, net of income taxes			$ 63,603		$ 2,265		$ 67,312		$ 7,728
Waskom [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Unconsolidated interest ownership	50.00%		50.00%				50.00%

[1] Total revenues from third parties excludes intercompany revenues of $3,285, $17,741, $26,431, and $49,444 for the three months ended September 30, 2012 and 2011, and nine months ended September 30, 2012 and 2011, respectively.

[2] The Partnership recognized a gain on the sale of its Prism Gas Business of $62,251 and $61,411 in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011, respectively.

XML

Long-Term Debt and Capital Leases (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended							9 Months Ended				9 Months Ended						9 Months Ended
	Aug. 31, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2012 Redemption of Notes [Member]	May 24, 2012 Redemption of Notes [Member]	May 10, 2012 Maximum [Member]	May 10, 2012 Minimum [Member]	Sep. 30, 2012 Senior Notes [Member]		Dec. 31, 2011 Senior Notes [Member]		Sep. 30, 2012 Revolving Loan Facility [Member]		Dec. 31, 2011 Revolving Loan Facility [Member]		Sep. 30, 2012 Revolving Loan Facility [Member] Interest Rate Swap 1 [Member]	Sep. 30, 2012 Revolving Loan Facility [Member] Interest Rate Swap 2 [Member]	Sep. 30, 2012 Note Payable to Banks [Member]	Dec. 31, 2011 Note Payable to Banks [Member]	Sep. 30, 2012 Capital Lease Obligations [Member]	Dec. 31, 2011 Capital Lease Obligations [Member]	Sep. 30, 2012 LIBOR [Member]	Sep. 30, 2012 LIBOR [Member] Maximum [Member]	Sep. 30, 2012 LIBOR [Member] Minimum [Member]	Sep. 30, 2012 Prime Rate [Member] Maximum [Member]	Sep. 30, 2012 Prime Rate [Member] Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms				The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%.  The applicable margin for existing LIBOR borrowings is 3.00%.  Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%.  Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.
Total long-term debt and capital lease obligations		$ 256,183,000		$ 256,183,000		$ 460,202,000					$ 173,312,000	[1],[2],[3]	$ 197,808,000	[1],[2],[3]	$ 77,000,000	[4]	$ 250,000,000	[4]			$ 0	$ 6,363,000	$ 5,871,000	$ 6,031,000
Less current installments		217,000		217,000		1,261,000
Long-term debt and capital lease obligations, net of current installments		255,966,000		255,966,000		458,941,000
Applicable margins																									3.00%	3.25%	2.00%	2.25%	1.00%
Applicable margin for next three months																									3.00%
Applicable margin thereafter																									2.25%
Notional Amount of Interest Rate Derivatives																			40,000,000	60,000,000
Face amount											200,000,000				400,000,000						7,354,000
Unamortized discount											1,688,000		2,192,000
Weighted average interest rate															3.72%
Stated interest rate											8.875%										7.50%
Maturity date											Apr. 30, 2018				Apr. 30, 2016						Jan. 31, 2017
Partnership redemption option maximum							35.00%
Partnership senior note redemption option price							108.875%
Partnership redemption of the senior notes								25,000,000
Payments of Debt Extinguishment Costs				2,219
Notional value of derivatives canceled	100,000,000
Early extinguishment termination fees received	2,800,000
Maximum amount of borrowings and letters of credit available under Credit Facility									400,000,000	375,000,000
Cash paid for interest		4,696,000	2,813,000	19,039,000	6,662,000
Capitalized interest		$ 175,000	$ 127,000	$ 799,000	$ 373,000

[1] Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

[2] Pursuant to the Indenture under which the Senior Notes were issued, the Partnership has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings. On April 24, 2012, the Partnership notified the Trustee of its intention to exercise a partial redemption of the Partnership’s Senior Notes pursuant to the Indenture. On May 24, 2012, the Partnership redeemed $25,000 of the Senior Notes from various holders using proceeds of the Partnership’s January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under the Partnership’s revolving credit facility. In conjunction with the redemption, the Partnership incurred a debt prepayment premium in the amount of $2,219, which is included in the consolidated and condensed statements of operations for the nine months ended September 30, 2012.

[3] Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

[4] Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%. The applicable margin for existing LIBOR borrowings is 3.00%. Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%. Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.

XML

Related Party Transactions (Details) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended		1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 25, 2012	Feb. 09, 2011	Feb. 28, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Related Party Transaction [Line Items]
Ownership percentage				50.00%		50.00%
General partner interest percentage	2.00%	2.00%	2.00%
Revenues:
Terminalling and storage				$ 18,531	$ 14,210	$ 48,611	$ 40,045
Marine transportation				3,979	6,352	13,282	19,223
Product sales:
Product Sales Related Party				1,636	1,628	5,783	7,197
Revenue from Related Parties				24,146	22,190	67,676	66,465
Costs of products sold:
Natural gas services				6,761	9,257	18,783	13,679
Sulfur services				4,111	4,762	12,512	13,407
Cost of products sold				10,999	14,064	31,587	27,269
Operating expenses:
Operating expenses				14,100	16,905	42,308	42,170
Selling, general and administrative:
Selling, general and administrative				2,764	2,373	8,258	6,344
Martin Resource Management [Member]
Related Party Transaction [Line Items]
Number of shares owned (in units)				6,593,267		6,593,267
Ownership percentage				28.50%		28.50%
General partner interest percentage						2.00%
Initial term of agreement				22 years		22 years
Martin Resource Management [Member] | Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Noncompete restriction threshold				5,000		5,000
Noncompete restriction ownership option opportunity threshold minimum				5,000		5,000
Noncompete restriction ownership option opportunity threshold minimum with equity limitation				5,000		5,000
Equity limitation on ownership restriction (in hundredths)				20.00%		20.00%
Approved annual reimbursements for indirect expenses						6,582
Indirect expenses reimbursed				1,646	1,042	4,937	3,126
Martin Resource Management [Member] | Motor Carrier Agreement [Member]
Related Party Transaction [Line Items]
Automatic consecutive term renewal period						1 year
Termination written notice, minimum				30 days		30 days
Partnership notice period to terminate agreement				90 days		90 days
Martin Resource Management [Member] | Marine Transportation Agreement [Member]
Related Party Transaction [Line Items]
Termination written notice, minimum				60 days		60 days
Martin Resource Management [Member] | Cross Marine Charter Agreements [Member]
Related Party Transaction [Line Items]
Termination written notice, minimum				30 days		30 days
Number of Agreements				2		2
Initial term of agreement				5 years		5 years
Martin Resource Management [Member] | Cross Tolling Agreement [Member]
Related Party Transaction [Line Items]
Production minimum per day (in bbl)				6,500		6,500
Annual escalation benchmark (in hundredths)				3.00%		3.00%
Martin Resource Management [Member] | Sulfuric Acid Sales Agency Agreement [Member]
Related Party Transaction [Line Items]
Partnership notice period to terminate agreement				180 days		180 days
Martin Resource Management [Member] | Marine Agreements [Member]
Related Party Transaction [Line Items]
Automatic consecutive term renewal period						1 year
Martin Resource Management [Member] | Terminal Services Agreements [Member]
Related Party Transaction [Line Items]
Termination written notice, minimum				60 days		60 days
Related Party [Member] | Marine transportation [Member]
Operating expenses:
Operating expenses				7,236	8,631	21,217	21,412
Selling, general and administrative:
Selling, general and administrative				15	19	47	49
Related Party [Member] | Natural gas services [Member]
Product sales:
Product Sales Related Party				(1)	29	104	663
Operating expenses:
Operating expenses				453	480	1,368	1,176
Selling, general and administrative:
Selling, general and administrative				366	308	1,052	884
Related Party [Member] | Sulfur services [Member]
Product sales:
Product Sales Related Party				1,469	1,537	4,829	6,358
Operating expenses:
Operating expenses				1,494	1,901	4,796	4,803
Selling, general and administrative:
Selling, general and administrative				737	1,004	2,183	2,285
Related Party [Member] | Terminalling and storage [Member]
Product sales:
Product Sales Related Party				168	62	850	176
Costs of products sold:
Cost of products sold				127	45	292	183
Operating expenses:
Operating expenses				4,917	5,893	14,927	14,779
Selling, general and administrative:
Selling, general and administrative				0	0	39	0
Related Party [Member] | Indirect overhead allocation, net of reimbursement [Member]
Selling, general and administrative:
Selling, general and administrative				$ 1,646	$ 1,042	$ 4,937	$ 3,126

XML

Business Segments (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (loss) after eliminations			Capital Expenditures
Three Months Ended September 30, 2012
Terminalling and storage	$	45,667	$	(1,191	)	$	44,476	$	5,503	$	5,493		$	7,990
Natural gas services	190,738		—			190,738		149		3,270			143
Sulfur services	60,596		—			60,596		1,750		7,273			7,549
Marine transportation	22,879		(777		)	22,102		2,564		811			1,711
Indirect selling, general and administrative	—		—			—		—		(1,966		)	—
Total	$	319,880	$	(1,968	)	$	317,912	$	9,966	$	14,881		$	17,393
Three Months Ended September 30, 2011
Terminalling and storage	$	38,080	$	(1,174	)	$	36,906	$	4,829	$	3,457		$	14,360
Natural gas services	159,748		—			159,748		148		2,164			277
Sulfur services	70,169		—			70,169		1,676		5,921			2,598
Marine transportation	22,411		(1,638		)	20,773		3,372		(896		)	2,061
Indirect selling, general and administrative	—		—			—		—		(2,967		)	—
Total	$	290,408	$	(2,812	)	$	287,596	$	10,025	$	7,679		$	19,296
Nine Months Ended September 30, 2012
Terminalling and storage	$	130,131	$	(3,542	)	$	126,589	$	15,170	$	12,919		$	45,768
Natural gas services	527,666		—			527,666		436		6,457			410
Sulfur services	202,241		—			202,241		5,325		34,320			9,204
Marine transportation	65,912		(2,234		)	63,678		8,526		662			7,627
Indirect selling, general and administrative	—		—			—		—		(6,733		)	—
Total	$	925,950	$	(5,776	)	$	920,174	$	29,457	$	47,625		$	63,009
Nine Months Ended September 30, 2011
Terminalling and storage	$	115,492	$	(3,220	)	$	112,272	$	14,114	$	9,576		$	24,270
Natural gas services	423,953		—			423,953		435		5,598			581
Sulfur services	206,860		—			206,860		4,998		27,818			14,826
Marine transportation	63,201		(5,653		)	57,548		9,976		(5,143		)	9,092
Indirect selling, general and administrative	—		—			—		—		(6,547		)	—
Total	$	809,506	$	(8,873	)	$	800,633	$	29,523	$	31,302		$	48,769

Assets by segment

The Partnership's assets by reportable segment, which exclude assets held for sale of $0 and $212,787, respectively, as of September 30, 2012 and December 31, 2011, are as follows:

	September 30, 2012		December 31, 2011
Total assets:
Terminalling and storage	$	161,544	$	231,764
Natural gas services	288,003		198,845
Sulfur services	258,712		162,289
Marine transportation	115,537		143,424
Total assets	$	823,796	$	736,322

XML

General (Policies)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

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 financial statements in conformity with accounting principles generally accepted in the United States.  Actual results could differ from those estimates.

Unit Grants

Unit Grants

In May 2012, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 6,250 treasury units purchased by the Partnership in the open market for $221.  These units vest in 25% increments beginning in January 2013 and will be fully vested in January 2016.

In May 2011, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 5,750 treasury units purchased by the Partnership in the open market for $235 and 500 treasury units from forfeitures.  These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.

In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for $347.  On July 31, 2012, 6,850 of these units were fully vested to certain employees in connection with the sale of the Prism Assets. The remaining 2,250 units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015.

The cost resulting from share-based payment transactions was $261 and $36 for the three months ended September 30, 2012 and 2011, respectively, and $379 and $131 for the nine months ended September 30, 2012 and 2011, respectively.

Incentive Distribution Rights

Incentive Distribution Rights

The Partnership’s general partner, Martin Midstream GP LLC, 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 of the Partnership (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. As discussed further in Note 16, on October 2, 2012, the Partnership Agreement was amended to provide that the General Partner shall not receive the next $18,000 in incentive distributions that it would otherwise be entitled to receive. Therefore, no incentive distributions were allocated to the general partner for the three months ended September 30, 2012, which would have been payable to the general partner on November 14, 2012.

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

For the three months ended September 30, 2012 and 2011, the general partner received $0 and $1,265, respectively, in incentive distributions.  For the nine months ended September 30, 2012 and 2011, the general partner received $2,857 and $3,635, respectively, in incentive distributions.

Net Income per Unit

Net Income per Unit

The Partnership follows the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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 IDR would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement.

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 beneficial conversion feature is added back to net income available to common limited partners, 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 from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	8,798		$	3,134		$	22,810	$	13,763
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	(1,536		)	763			723		2,328
Distributions payable on behalf of general partner interest	(320		)	207			295		640
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	526			(159		)	147		(411		)
Less beneficial conversion feature	—			166			—		532
Limited partners’ interest in net income	$	10,128		$	2,157		$	21,645	$	10,674

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	63,603	$	2,265		$	67,312	$	7,728
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	1,536		502			2,134		1,307
Distributions payable on behalf of general partner interest	709		138			872		360
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	533		(103		)	432		(232		)
Less beneficial conversion feature	—		111			—		299
Limited partners’ interest in net income	$	60,825	$	1,617		$	63,874	$	5,994

The Partnership allocates the General Partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income. The allocation is done at each period end on an annual basis, resulting in each quarter representing the difference between year to date of the current quarter and year to date as of the previous quarter.

The weighted average units outstanding for basic net income per unit were 23,101,233 and 22,929,172 for the three and nine months ended September 30, 2012, respectively, and 19,158,334 and 19,161,403 for the three and nine months ended September 30, 2011, respectively.  For diluted net income per unit, the weighted average units outstanding were increased by 3,596 and 3,164 for the three and nine months ended September 30, 2012, respectively, and 4,794 and 1,663 for the three and nine months ended September 30, 2011, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

Income Taxes

Income Taxes

With respect to the Partnership’s taxable subsidiary, Woodlawn Pipeline Co., Inc. (“Woodlawn”), income taxes are accounted for under the asset and liability method.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

XML

Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Current state income tax expense	$ 568	$ 6	$ 574	$ 17
Deferred tax liability	(38)		(38)		7,657
Current [Abstract]
Federal	5,803	(17)	5,807	11
State	806	223	1,384	679
Current income tax expense (benefit)	6,609	206	7,191	690
Deferred [Abstract]
Federal	(7,373)	33	(7,695)	2
Total Income tax expense (benefit)	(764)	239	(504)	692
Current [Abstract]
State	238	218	810	662
Total income tax expense from continuing operations	238	218	810	662
Current [Abstract]
Federal	5,803	(17)	5,807	11
State	568	6	574	17
Current income tax expense (benefit), Discontinued operation	6,371	(11)	6,381	28
Deferred [Abstract]
Federal	(7,373)	32	(7,695)	2
Total income tax expense (benefit) from discontinued operations	$ (1,002)	$ 21	$ (1,314)	$ 30

XML

Derivative Instruments and Hedging Activities (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Aug. 31, 2011	Sep. 30, 2012 Interest Rate Contract [Member]	Sep. 30, 2011 Interest Rate Contract [Member]	Sep. 30, 2012 Interest Rate Contract [Member]	Sep. 30, 2011 Interest Rate Contract [Member]	Sep. 30, 2012 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Crude Oil Swaps [Member]	Sep. 30, 2011 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Crude Oil Swaps [Member]	Sep. 30, 2012 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Crude Oil Swaps [Member]	Sep. 30, 2011 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Crude Oil Swaps [Member]	Sep. 30, 2012 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Swaps [Member]	Sep. 30, 2011 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Swaps [Member]	Sep. 30, 2012 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Swaps [Member]	Sep. 30, 2011 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Swaps [Member]	Sep. 30, 2012 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Liquids [Member]	Sep. 30, 2011 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Liquids [Member]	Sep. 30, 2012 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Liquids [Member]	Sep. 30, 2011 Designated as Hedging Instrument [Member] Commodity Contract [Member] Cash Flow Hedging [Member] Natural Gas Liquids [Member]
Impact of Commodity Cash Flow Hedges [Abstract]
Effect of derivative instrument on revenue increase (decrease)						$ 36	$ 361	$ 496	$ 658	$ 77	$ 72	$ 813	$ 215	$ 5	$ 236	$ 1,066	$ 458
Impact of Interest Rate Derivative Instruments [Abstract]
Notional value of derivatives canceled	100,000
Early extinguishment termination fees received	2,800
Recognized increases in interest expenses		$ 0	$ 3,244	$ 0	$ 5,779

XML

General Reconciliation of Net Income (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Oct. 02, 2012	Sep. 30, 2011
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income attributable to Martin Midstream Partners L.P.	$ 72,401	$ 5,399	$ 90,122		$ 21,491
Less general partner's interest in net income:
Distributions payable on behalf of IDRs	0	1,265	2,857	18,000	3,635
Net Income (Loss) Allocated to Limited Partners	70,953	3,774	85,519		16,668
Weighted average limited partner units outstanding basic (in units)	23,101,233	19,158,334	22,929,172		19,161,403
Increase in units outstanding due to the dilutive effect of restricted units granted (in units)	3,596	4,794	3,164		1,663
Continuing operations [Member]
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income attributable to Martin Midstream Partners L.P.	8,798	3,134	22,810		13,763
Less general partner's interest in net income:
Distributions payable on behalf of IDRs	(1,536)	763	723		2,328
Distributions payable on behalf of general partner interest	(320)	207	295		640
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	526	(159)	147		(411)
Less beneficial conversion feature	0	166	0		532
Net Income (Loss) Allocated to Limited Partners	10,128	2,157	21,645		10,674
Discontinued operations [Member]
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income attributable to Martin Midstream Partners L.P.	63,603	2,265	67,312		7,728
Less general partner's interest in net income:
Distributions payable on behalf of IDRs	1,536	502	2,134		1,307
Distributions payable on behalf of general partner interest	709	138	872		360
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	533	(103)	432		(232)
Less beneficial conversion feature	0	111	0		299
Net Income (Loss) Allocated to Limited Partners	$ 60,825	$ 1,617	$ 63,874		$ 5,994

XML

Subsequent Events (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Oct. 02, 2012	Sep. 30, 2011
Subsequent Event [Line Items]
Ownership percentage	50.00%		50.00%
Incentive distributions	$ 0	$ 1,265	$ 2,857	$ 18,000	$ 3,635
Subsequent Event [Member]
Subsequent Event [Line Items]
Incentive distributions				18,000
Management [Member]
Subsequent Event [Line Items]
Number of shares owned (in units)	6,593,267		6,593,267
Ownership percentage	28.50%		28.50%
Management [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
partnerscapitalaccount,units,transferred				1,500,000
Number of shares owned (in units)	5,093,267		5,093,267
Redbird Gas Storage [Member] | Common Class A [Member]
Subsequent Event [Line Items]
Ownership percentage	10.74%		10.74%
Redbird Gas Storage [Member] | Common Class A [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Cost of acquired entity				150,000
Ownership percentage	10.74%		10.74%
Redbird Gas Storage [Member] | Common Class B [Member]
Subsequent Event [Line Items]
Ownership percentage	40.95%		40.95%
Redbird Gas Storage [Member] | Common Class B [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Ownership percentage	100.00%		100.00%
Cash [Member] | Cross Oil and Refining Marketing Inc [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Cost of acquired entity				121,800
working capital [Member] | Cross Oil and Refining Marketing Inc [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Cost of acquired entity				$ 36,800

XML

Business Segments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 segment	Sep. 30, 2011	Dec. 31, 2011
Segment Reporting [Abstract]
Number of Reportable Segments			4
Segment Reporting Information [Line Items]
Assets held for sale	$ 0		$ 0		$ 212,787
Operating Revenues	319,880	290,408	925,950	809,506
Intersegment Revenues Eliminations	(1,968)	(2,812)	(5,776)	(8,873)
Total revenues	317,912	287,596	920,174	800,633
Depreciation and amortization	9,966	10,025	29,457	29,523
Operating Income (loss) after eliminations	14,881	7,679	47,625	31,302
Capital Expenditures	17,393	19,296	63,009	48,769
Total Assets [Abstract]
Assets Excluding Held for Sale	823,796		823,796		736,322
Terminalling and storage [Member]
Segment Reporting Information [Line Items]
Operating Revenues	45,667	38,080	130,131	115,492
Intersegment Revenues Eliminations	(1,191)	(1,174)	(3,542)	(3,220)
Total revenues	44,476	36,906	126,589	112,272
Depreciation and amortization	5,503	4,829	15,170	14,114
Operating Income (loss) after eliminations	5,493	3,457	12,919	9,576
Capital Expenditures	7,990	14,360	45,768	24,270
Total Assets [Abstract]
Assets Excluding Held for Sale	161,544		161,544		231,764
Natural gas services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	190,738	159,748	527,666	423,953
Intersegment Revenues Eliminations	0	0	0	0
Total revenues	190,738	159,748	527,666	423,953
Depreciation and amortization	149	148	436	435
Operating Income (loss) after eliminations	3,270	2,164	6,457	5,598
Capital Expenditures	143	277	410	581
Total Assets [Abstract]
Assets Excluding Held for Sale	288,003		288,003		198,845
Sulfur services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	60,596	70,169	202,241	206,860
Intersegment Revenues Eliminations	0	0	0	0
Total revenues	60,596	70,169	202,241	206,860
Depreciation and amortization	1,750	1,676	5,325	4,998
Operating Income (loss) after eliminations	7,273	5,921	34,320	27,818
Capital Expenditures	7,549	2,598	9,204	14,826
Total Assets [Abstract]
Assets Excluding Held for Sale	258,712		258,712		162,289
Marine transportation [Member]
Segment Reporting Information [Line Items]
Operating Revenues	22,879	22,411	65,912	63,201
Intersegment Revenues Eliminations	(777)	(1,638)	(2,234)	(5,653)
Total revenues	22,102	20,773	63,678	57,548
Depreciation and amortization	2,564	3,372	8,526	9,976
Operating Income (loss) after eliminations	811	(896)	662	(5,143)
Capital Expenditures	1,711	2,061	7,627	9,092
Total Assets [Abstract]
Assets Excluding Held for Sale	115,537		115,537		143,424
Indirect selling, general and administrative [Member]
Segment Reporting Information [Line Items]
Operating Revenues	0	0	0	0
Intersegment Revenues Eliminations	0	0	0	0
Total revenues	0	0	0	0
Depreciation and amortization	0	0	0	0
Operating Income (loss) after eliminations	(1,966)	(2,967)	(6,733)	(6,547)
Capital Expenditures	$ 0	$ 0	$ 0	$ 0

XML

General

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

General

General

Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products, natural gas services, sulfur and sulfur-based products processing, manufacturing, marketing and distribution, and marine transportation services for petroleum products and by-products.

The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and United States generally accepted accounting principles for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by generally accepted accounting principles 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 results of operations, financial position 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, 2011, filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2012. On August 21, 2012, Part II, Items 6, 7, and 8 of the Partnership's Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012, was updated on Form 8-K to reflect the operations related to the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets as discontinued operations

As discussed in Note 4, on July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets.  These assets, along with additional gathering and processing assets discussed in Note 4 are collectively referred to as the "Prism Assets".  The Partnership classified the Prism Assets, including related liabilities as held for sale at December 31, 2011, and has presented the results of operations and cash flows as discontinued operations for the periods ended September 30, 2012 and 2011, respectively. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the net assets and operations and cash flows of the Prism Assets as assets held for sale and discontinued operations, respectively.

(a) Use of Estimates

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 financial statements in conformity with accounting principles generally accepted in the United States.  Actual results could differ from those estimates.

(b) Unit Grants

In May 2012, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 6,250 treasury units purchased by the Partnership in the open market for $221.  These units vest in 25% increments beginning in January 2013 and will be fully vested in January 2016.

In May 2011, the Partnership issued 6,250 restricted common units to certain non-employee directors under its long-term incentive plan from 5,750 treasury units purchased by the Partnership in the open market for $235 and 500 treasury units from forfeitures.  These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015.

In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for $347.  On July 31, 2012, 6,850 of these units were fully vested to certain employees in connection with the sale of the Prism Assets. The remaining 2,250 units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015.

The cost resulting from share-based payment transactions was $261 and $36 for the three months ended September 30, 2012 and 2011, respectively, and $379 and $131 for the nine months ended September 30, 2012 and 2011, respectively.

(c) Incentive Distribution Rights

The Partnership’s general partner, Martin Midstream GP LLC, 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 of the Partnership (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. As discussed further in Note 16, on October 2, 2012, the Partnership Agreement was amended to provide that the General Partner shall not receive the next $18,000 in incentive distributions that it would otherwise be entitled to receive. Therefore, no incentive distributions were allocated to the general partner for the three months ended September 30, 2012, which would have been payable to the general partner on November 14, 2012.

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

For the three months ended September 30, 2012 and 2011, the general partner received $0 and $1,265, respectively, in incentive distributions.  For the nine months ended September 30, 2012 and 2011, the general partner received $2,857 and $3,635, respectively, in incentive distributions.

(d) Net Income per Unit

The Partnership follows the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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 IDR would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement.

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 beneficial conversion feature is added back to net income available to common limited partners, 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 from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	8,798		$	3,134		$	22,810	$	13,763
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	(1,536		)	763			723		2,328
Distributions payable on behalf of general partner interest	(320		)	207			295		640
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	526			(159		)	147		(411		)
Less beneficial conversion feature	—			166			—		532
Limited partners’ interest in net income	$	10,128		$	2,157		$	21,645	$	10,674

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	63,603	$	2,265		$	67,312	$	7,728
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	1,536		502			2,134		1,307
Distributions payable on behalf of general partner interest	709		138			872		360
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	533		(103		)	432		(232		)
Less beneficial conversion feature	—		111			—		299
Limited partners’ interest in net income	$	60,825	$	1,617		$	63,874	$	5,994

The Partnership allocates the General Partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income. The allocation is done at each period end on an annual basis, resulting in each quarter representing the difference between year to date of the current quarter and year to date as of the previous quarter.

The weighted average units outstanding for basic net income per unit were 23,101,233 and 22,929,172 for the three and nine months ended September 30, 2012, respectively, and 19,158,334 and 19,161,403 for the three and nine months ended September 30, 2011, respectively.  For diluted net income per unit, the weighted average units outstanding were increased by 3,596 and 3,164 for the three and nine months ended September 30, 2012, respectively, and 4,794 and 1,663 for the three and nine months ended September 30, 2011, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(e) Income Taxes

With respect to the Partnership’s taxable subsidiary, Woodlawn Pipeline Co., Inc. (“Woodlawn”), income taxes are accounted for under the asset and liability method.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

XML

Derivative Instruments and Hedging Activities, Part 2 (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Fair Values of Derivative Instruments in the Consolidated Balance Sheet [Abstract]
Derivative Assets, Current	$ 0	$ 622
Derivative Liabilities, Current	0	362
Designated as Hedging Instrument [Member]
Fair Values of Derivative Instruments in the Consolidated Balance Sheet [Abstract]
Derivative Liabilities, Total	0	245
Derivative Assets, Total	0	622
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fair value of derivatives, asset, current [Member]
Fair Values of Derivative Instruments in the Consolidated Balance Sheet [Abstract]
Derivative Assets, Current	0	622
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fair value of derivatives, liability, current [Member]
Fair Values of Derivative Instruments in the Consolidated Balance Sheet [Abstract]
Derivative Liabilities, Current	0	245
Not Designated as Hedging Instrument [Member]
Fair Values of Derivative Instruments in the Consolidated Balance Sheet [Abstract]
Derivative Liabilities, Total	0	117
Derivative Assets, Total	0	0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fair value of derivatives, asset, current [Member]
Fair Values of Derivative Instruments in the Consolidated Balance Sheet [Abstract]
Derivative Assets, Current	0	0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fair value of derivatives, liability, current [Member]
Fair Values of Derivative Instruments in the Consolidated Balance Sheet [Abstract]
Derivative Liabilities, Current	$ 0	$ 117

XML

Investments in Unconsolidated Entities and Joint Ventures (Tables)

9 Months Ended

Sep. 30, 2012

Equity Method Investments and Joint Ventures [Abstract]

Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities

The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s consolidated and condensed balance sheets and the components of equity in earnings of unconsolidated entities included in the Partnership’s consolidated and condensed statements of operations:

	September 30, 2012		December 31, 2011
Investment in Waskom1	$	—	$	102,896
Investment in PIPE1	—		1,291
Investment in Matagorda1	—		3,362
Investment in unconsolidated entities classified as assets held for sale	—		107,549
Investment in Redbird	80,168		62,948
Investment in Caliber	631		—
Investment in unconsolidated entities	80,799		62,948
Total Investment in unconsolidated entities	$	80,799	$	170,497

¹ As of December 31, 2011, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed balance sheet as assets held for sale.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Equity in earnings of Waskom1	$	287		$	1,767		$	4,172		$	6,779
Equity in earnings of PIPE1	10			(15		)	(60		)	(45		)
Equity in earnings of Matagorda1	80			87			499			120
Equity in earnings of discontinued operations	377			1,839			4,611			6,854
Equity in earnings of Redbird	(103		)	(54		)	(433		)	100
Equity in earnings of Caliber	(98		)	—			(119		)	—
Equity in earnings of Pecos Valley	32			—			20			—
Equity in earnings of unconsolidated entities	(169		)	(54		)	(532		)	100
Total equity in earnings of unconsolidated entities	$	208		$	1,785		$	4,079		$	6,954

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Equity in earnings of Waskom1	$	287		$	1,767		$	4,172		$	6,779
Equity in earnings of PIPE1	10			(15		)	(60		)	(45		)
Equity in earnings of Matagorda1	80			87			499			120
Equity in earnings of discontinued operations	377			1,839			4,611			6,854
Equity in earnings of Redbird	(103		)	(54		)	(433		)	100
Equity in earnings of Caliber	(98		)	—			(119		)	—
Equity in earnings of Pecos Valley	32			—			20			—
Equity in earnings of unconsolidated entities	(169		)	(54		)	(532		)	100
Total equity in earnings of unconsolidated entities	$	208		$	1,785		$	4,079		$	6,954

¹ For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed statement of operations and cash flows as discontinued operations.

Select financial information for significant unconsolidated equity-method investees

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

	As of September 30				Three Months Ended September 30				Nine Months Ended September 30
	Total Assets		Partner’s Capital		Revenues1		Net Income1		Revenues1		Net Income1
2012
Waskom	$	—	$	—	$	8,171	$	668	$	66,662	$	8,986
	As of December 31
2011
Waskom	$	146,655	$	126,863	$	29,508	$	3,808	$	95,086	$	14,382

¹ Revenues and Net Income for Waskom include financial information only for the periods owned. Three months ended September 30, 2012 only includes financial information for the one month ended July 31, 2012. Nine months ended September 30, 2012 only includes financial information for the seven months ended July 31, 2012.

XML

Inventories (Tables)

9 Months Ended

Sep. 30, 2012

Inventory Disclosure [Abstract]

Components of inventory

Components of inventories at September 30, 2012 and December 31, 2011 were as follows: 

	September 30, 2012		December 31, 2011
Natural gas liquids	$	64,783	$	25,178
Sulfur	26,460		24,335
Sulfur based products	14,115		14,857
Lubricants	8,471		11,012
Other	2,431		2,295
	$	116,260	$	77,677

XML

Derivative Instruments and Hedging Activities, Part 3 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Designated as Hedging Instrument [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) recognized in OCI on derivatives	$ 0	$ 1,295	$ 126	$ 1,231
Amount of gain or (loss) reclassified from accumulated OCI into income	63	500	748	1,246
Amount of gain (loss) recognized in income on derivatives	0	38	4	27
Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) recognized in OCI on derivatives	0	1,295	126	1,231
Subsequent time period for transfer of commodity cash flow hedges to earnings			12 months
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Natural Gas Services Revenues [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) reclassified from accumulated OCI into income	63	500	748	1,264
Amount of gain (loss) recognized in income on derivatives	0	38	4	27
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) recognized in OCI on derivatives	0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) reclassified from accumulated OCI into income			0	(18)
Amount of gain (loss) recognized in income on derivatives			0	0
Not Designated as Hedging Instrument [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) recognized in income on derivatives	(18)	3,375	1,623	5,838
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Natural Gas Services Revenues [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) recognized in income on derivatives	(18)	131	1,623	41
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Effect of Derivative Instruments on the Consolidated Statement of Operations [Abstract]
Amount of gain or (loss) recognized in income on derivatives	$ 0	$ 3,244	$ 0	$ 5,797

XML

Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the fair value and classification of the Partnership's derivative instruments

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

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	September 30, 2012		December 31, 2011		Balance Sheet Location	September 30, 2012		December 31, 2011
Derivatives designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	622	Fair value of derivatives	$	—	$	245
Total derivatives designated as hedging instruments		$	—	$	622		$	—	$	245
Derivatives not designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	117
Total derivatives not designated as hedging instruments		$	—	$	—		$	—	$	117

	Effect of Derivative Instruments on the Consolidated Statement of Operations For the Three Months Ended September 30, 2012 and 2011
	Effective Portion									Ineffective Portion and Amount  Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives				Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income				Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011			2012		2011			2012		2011
Derivatives designated as hedging instruments:
Commodity contracts	$	—	$	1,295	Income from discontinued operations	$	63	$	500	Income from discontinued operations	$	—	$	38
Total derivatives designated as hedging instruments	$	—	$	1,295		$	63	$	500		$	—	$	38

Effect of derivative instruments on the Consolidated Statement of Operations

	Location of Gain or (Loss) Recognized in Income on  Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012			2011
Derivatives not designated as hedging instruments:
Interest rate contracts	Interest expense	$	—		$	3,244
Commodity contracts	Income from discontinued operations	(18		)	131
Total derivatives not designated as hedging instruments		$	(18	)	$	3,375

Effect of Derivative Instruments on the Consolidated Statement of Operations

For the Nine Months Ended September 30, 2012 and 2011

	Effective Portion										Ineffective Portion and Amount  Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives				Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income					Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011			2012		2011				2012		2011
Derivatives designated as hedging instruments
Interest rate contracts	$	—	$	—	Interest expense	$	—	$	(18	)	Interest expense	$	—	$	—
Commodity contracts	126		1,231		Income from discontinued operations	748		1,264			Income from discontinued operations	4		$	27
Total derivatives designated as hedging instruments	$	126	$	1,231		$	748	$	1,246			$	4	$	27

	Effect of Derivative Instruments on the Consolidated Statement of Operations For the Three Months Ended September 30, 2012 and 2011
	Effective Portion									Ineffective Portion and Amount  Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives				Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income				Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011			2012		2011			2012		2011
Derivatives designated as hedging instruments:
Commodity contracts	$	—	$	1,295	Income from discontinued operations	$	63	$	500	Income from discontinued operations	$	—	$	38
Total derivatives designated as hedging instruments	$	—	$	1,295		$	63	$	500		$	—	$	38

	Location of Gain or (Loss) Recognized in Income on  Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012		2011
Derivatives not designated as hedging instruments
Interest rate contracts	Interest Expense	$	—	$	5,797
Commodity contracts	Income from discontinued operations	1,623		41
Total derivatives not designated as hedging instruments		$	1,623	$	5,838

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at December 31, 2011:

	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	December 31, 2011		(Level 1)		(Level 2)		(Level 3)
Assets
Natural gas derivatives	$	622	$	—	$	622	$	—
Total assets	$	622	$	—	$	622	$	—
Liabilities
Crude oil derivatives	245		—		245		—
Natural gas liquids derivatives	117		—		117		—
Total liabilities	$	362	$	—	$	362	$	—

XML

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash flows from operating activities:
Net Income	$ 90,122,000	$ 21,491,000
Less: Income from discontinued operations	(67,312,000)	(7,728,000)
Net income from continuing operations	22,810,000	13,763,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	29,457,000	29,523,000
Amortization of deferred debt issuance costs	2,611,000	3,071,000
Amortization of debt discount	504,000	262,000
Loss on sale of property, plant and equipment	7,000	405,000
Gain on sale of equity method investment	(486,000)	0
Equity in earnings (loss) of unconsolidated entities	532,000	(100,000)
Other	379,000	131,000
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(6,328,000)	(4,788,000)
Product exchange receivables	12,190,000	(16,552,000)
Inventories	(38,583,000)	(28,057,000)
Due from affiliates	(27,795,000)	221,000
Other current assets	431,000	1,874,000
Trade and other accounts payable	(8,533,000)	11,733,000
Product exchange payables	(9,405,000)	27,350,000
Due to affiliates	4,469,000	3,430,000
Income taxes payable	(96,000)	(799,000)
Other accrued liabilities	840,000	4,218,000
Change in other non-current assets and liabilities	(1,126,000)	(123,000)
Net cash provided by (used in) continuing operating activities	(18,122,000)	45,562,000
Net cash provided by discontinued operating activities	120,000	12,272,000
Net cash provided by (used in) operating activities	(18,002,000)	57,834,000
Cash flows from investing activities:
Payments for property, plant, and equipment	(63,009,000)	(48,769,000)
Acquisitions	0	(16,815,000)
Payments for plant turnaround costs	(2,578,000)	(2,103,000)
Proceeds from sale of property, plant, and equipment	33,000	530,000
Proceeds from sale of equity method investment	531,000	0
Investment in unconsolidated subsidiaries	(775,000)	(59,319,000)
Return of investments from unconsolidated entities	5,133,000	383,000
Distributions from (contributions to) unconsolidated entities for operations	(22,786,000)	(929,000)
Net cash used in continuing investing activities	(83,451,000)	(127,022,000)
Net cash provided by (used in) discontinued investing activities	271,181,000	(8,253,000)
Net cash provided by (used in) investing activities	187,730,000	(135,275,000)
Cash flows from financing activities:
Payments of long-term debt	(547,000,000)	(389,000,000)
Payments of notes payable and capital lease obligations	(6,522,000)	(831,000)
Proceeds from long-term debt	349,000,000	456,000,000
Net proceeds from follow on offering	91,361,000	70,330,000
General partner contribution	1,951,000	1,505,000
Treasury units purchased	(221,000)	(582,000)
Payment of debt issuance costs	(204,000)	(3,424,000)
Excess purchase price over carrying value of acquired assets	0	(19,685,000)
Cash distributions paid	(58,332,000)	(47,956,000)
Net cash provided by (used in) financing activities	(169,967,000)	66,357,000
Net decrease in cash	(239,000)	(11,084,000)
Cash at beginning of period	266,000	11,380,000
Cash at end of period	$ 27,000	$ 296,000

XML

Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

The impact of Related Party Transactions

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Revenues:
Terminalling and storage	$	18,531		$	14,210	$	48,611	$	40,045
Marine transportation	3,979			6,352		13,282		19,223
Product sales:
Natural gas services	(1		)	29		104		663
Sulfur services	1,469			1,537		4,829		6,358
Terminalling and storage	168			62		850		176
	1,636			1,628		5,783		7,197
	$	24,146		$	22,190	$	67,676	$	66,465

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

Cost of products sold:
Natural gas services	$	6,761	$	9,257	$	18,783	$	13,679
Sulfur services	4,111		4,762		12,512		13,407
Terminalling and storage	127		45		292		183
	$	10,999	$	14,064	$	31,587	$	27,269

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

Expenses:
Operating expenses
Marine transportation	$	7,236	$	8,631	$	21,217	$	21,412
Natural gas services	453		480		1,368		1,176
Sulfur services	1,494		1,901		4,796		4,803
Terminalling and storage	4,917		5,893		14,927		14,779
	$	14,100	$	16,905	$	42,308	$	42,170

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

Selling, general and administrative:
Marine transportation	$	15	$	19	$	47	$	49
Natural gas services	366		308		1,052		884
Sulfur services	737		1,004		2,183		2,285
Terminalling and storage	—		—		39		—
Indirect overhead allocation, net of reimbursement	1,646		1,042		4,937		3,126
	$	2,764	$	2,373	$	8,258	$	6,344

XML

Inventories (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Inventory Disclosure [Abstract]
Natural gas liquids	$ 64,783	$ 25,178
Sulfur	26,460	24,335
Sulfur based products	14,115	14,857
Lubricants	8,471	11,012
Other	2,431	2,295
Inventories	$ 116,260	$ 77,677

XML

CONSOLIDATED AND CONDENSED BALANCE SHEETS (Unaudited) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Assets
Cash	$ 27	$ 266
Accounts and other receivables, less allowance for doubtful accounts of $3,264 and $3,021, respectively	121,020	126,461
Product exchange receivables	5,455	17,646
Inventories	116,260	77,677
Due from affiliates	21,139	5,968
Fair value of derivatives	0	622
Other current assets	1,511	1,978
Assets held for sale	0	212,787
Total current assets	265,412	443,405
Property, plant and equipment, at cost	695,662	632,728
Accumulated depreciation	(243,780)	(215,272)
Property, plant and equipment, net	451,882	417,456
Goodwill	8,337	8,337
Investment in unconsolidated entities	80,799	62,948
Debt issuance costs, net	10,924	13,330
Other assets, net	6,442	3,633
Total Assets	823,796	949,109
Liabilities and Partners' Capital
Current installments of long-term debt and capital lease obligations	217	1,261
Trade and other accounts payable	104,779	125,970
Product exchange payables	27,908	37,313
Due to affiliates	4,669	18,485
Income taxes payable	7,174	893
Fair value of derivatives	0	362
Other accrued liabilities	11,764	11,022
Liabilities held for sale	0	501
Total current liabilities	156,511	195,807
Long-term debt and capital leases, less current maturities	255,966	458,941
Deferred income taxes	0	7,657
Other long-term obligations	1,069	1,088
Total liabilities	413,546	663,493
Partners' capital	410,250	284,990
Accumulated other comprehensive income	0	626
Total partners' capital	410,250	285,616
Commitments and contingencies
Total Liabilities and Partners' Capital	$ 823,796	$ 949,109

XML

Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas derivative assets		$ 622
Total assets		622
Crude oil derivative liability		245
Natural gas derivative liabilities		117
Total liabilities		362
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas derivative assets		0
Total assets		0
Crude oil derivative liability		0
Natural gas derivative liabilities		0
Total liabilities		0
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas derivative assets		622
Total assets		622
Crude oil derivative liability		245
Natural gas derivative liabilities		117
Total liabilities		362
Estimated fair value of Senior Notes	189,557
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Natural gas derivative assets		0
Total assets		0
Crude oil derivative liability		0
Natural gas derivative liabilities		0
Total liabilities		$ 0

XML

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Statement of Other Comprehensive Income [Abstract]
Net Income	$ 72,401	$ 5,399	$ 90,122	$ 21,491
Other comprehensive income adjustments:
Changes in fair values of commodity cash flow hedges	0	1,295	126	1,231
Commodity cash flow hedging gains (losses) reclassified to earnings	(63)	(538)	(752)	(1,291)
Interest rate cash flow hedging losses reclassified to earnings	0	0	0	18
Other Comprehensive Income	(63)	757	(626)	(42)
Comprehensive income	$ 72,338	$ 6,156	$ 89,496	$ 21,449

XML

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Components of income tax expense (benefit) from operations

The components of income tax expense (benefit) from operations recorded for the three and nine months ended September 30, 2012 and 2011 are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	806			223			1,384			679
	6,609			206			7,191			690
Deferred:
Federal	(7,373		)	33			(7,695		)	2
Total income tax expense (benefit)	$	(764	)	$	239		$	(504	)	$	692

Total income tax expense was allocated to continuing and discontinued operations as follows:

Income tax expense (benefit) from continuing operations:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Current:
State	$	238	$	218	$	810	$	662
Total income tax expense from continuing operations	$	238	$	218	$	810	$	662

Income tax expense (benefit) from discontinued operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	568			6			574			17
	6,371			(11		)	6,381			28
Deferred:
Federal	(7,373		)	32			(7,695		)	2
Total income tax expense (benefit) from discontinued operations	$	(1,002	)	$	21		$	(1,314	)	$	30

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

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

On October 2, 2012, the Partnership announced that the ongoing litigation and disputes involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all the lawsuits and disputes referenced in this section. Accordingly, none of the following matters are currently pending and such information is being provided for reference only.

On May 2, 2008, the Partnership received a copy of a petition filed in the District Court of Gregg County, Texas by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management.  In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment adverse to the Defendant which contained monetary damages and specific performance components (the “Judgment”).   The Defendant appealed the Judgment.  On November 3, 2010, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment.  The Appellate Court’s opinion rendered a take-nothing judgment against the Plaintiff and found in favor of the Defendant.  The Supreme Court of Texas denied the Plaintiff’s petition for review and therefore the opinion of the Sixth Appellate District of Texas at Texarkana has become final.

On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court (the “Harris County Litigation”) against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of the Partnership’s general partner. The Partnership is not a party to this lawsuit, and it does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations, or (iii) against the MRMC Director Defendants or other MRMC Defendants with respect to their service to the Partnership.

The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley M. Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Trust (the “ESOT”), and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares.  The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The case was abated in July 2009 during the pendency of a mandamus proceeding in the Texas Supreme Court. The Supreme Court denied mandamus relief on November 20, 2009.  This lawsuit was amended to add the ESOT as a party and was subsequently removed to Federal Court by the ESOT.  This lawsuit was remanded from Federal Court to the State District Court. The trial was previously set for August of 2012 but has been removed from the trial docket.  The trial is nonetheless stayed pending the outcome of procedural matters pending in the appellate courts.

The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against Scott Martin, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that he has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached fiduciary duties owed to Angela Jones Alexander, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, the Partnership has been informed that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above, Angela Jones Alexander amended her claims to include her grandmother, Margaret Martin, as a defendant, but subsequently dropped her claims against Mrs. Martin.  Additionally, all claims pertaining to Karen Yost have been resolved.  All claims pertaining to Defendant have been preliminarily resolved, as the court, on February 9, 2011, issued an order that granted the parties’ Joint Motion for Administrative Closure.  With respect to the lawsuit referenced in (i) above, the case was tried in October 2009 and the jury returned a verdict in favor of the Defendant’s daughters against Scott Martin in the amount of $4,900.  On December 22, 2009, the court entered a judgment, reflecting an amount consistent with the verdict and additionally awarded attorneys’ fees and interest. On January 7, 2010, the court modified its original judgment and awarded the Defendant’s daughters approximately $2,700 in damages and attorneys’ fees, plus interest. Scott Martin has appealed the judgment.  On March 20, 2012, the Court of Appeals, Sixth Appellate District of Texas at Texarkana, issued an opinion on the appeal overturning the Judgment.  While the Appellate Court found that there was sufficient evidence to support the jury’s finding that a breach of fiduciary duty occurred, it found insufficient evidence to support any damages and therefore rendered a take-nothing judgment against the daughters of the Defendant.  A motion for rehearing at the Appellate Court was overruled on April 26, 2012.  The Defendant’s daughters have indicated they will appeal the Appellate Court’s ruling.

On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which the board of directors of Martin Resource Management determined was detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of the Partnership’s general partner. This position on the board of directors was filled on July 26, 2010, by Charles Henry “Hank” Still.

On February 22, 2010, as a result of the Harris County Litigation being derivative in nature, Martin Resource Management formed a special committee of its board of directors and designated such committee as the Martin Resource Management authority for the purpose of assessing, analyzing and monitoring the Harris County Litigation and any other related litigation and making any and all determinations in respect of such litigation on behalf of Martin Resource Management.  Such authorization includes, but is not limited to, reviewing the merits of the litigation, assessing whether to pursue claims or counterclaims against various persons or entities, assess whether to appoint or retain experts or disinterested persons to make determinations in respect of such litigation, and advising and directing Martin Resource Management’s general counsel and outside legal counsel with respect to such litigation.  The special committee consists of Robert Bondurant, Donald R. Neumeyer and Wesley M. Skelton.

On May 4, 2010, the Partnership received a copy of a petition filed in a new case with the District Clerk of Gregg County, Texas by Martin Resource Management against the Plaintiff and others with respect to certain matters relating to Martin Resource Management (“the Gregg County Matter”). As noted above, the Plaintiff was a former director of Martin Resource Management.  The lawsuit alleges that the Plaintiff with help from others breached the fiduciary duties the Plaintiff owed to Martin Resource Management.   The Partnership is not a party to the lawsuit, and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations, or (iii) against the Plaintiff with respect to his service as an officer or former director of the general partner of the Partnership. With respect to this lawsuit, the case was tried in January 2012 and the jury returned a verdict in favor of Martin Resource Management against Scott D. Martin for breach of fiduciary duty and awarded an amount of $1,800.  The court entered a judgment in favor of Martin Resource Management in the amount awarded by the jury plus interest.  Scott D. Martin is appealing this judgment.

Additionally, on July 11, 2011, Scott D. Martin sued Martin Resource Management in State District Court in Harris County, Texas, alleging that it tortiously interfered with his rights under an existing insurance policy.  A motion to transfer this case was granted and this case is currently pending in the 188th District Court of Gregg County, Texas.  

On June 22, 2012, the Partnership received from Scott D. Martin a demand that the Partnership indemnify him for legal fees and damages adjudged against him in the Gregg County Matter.  He followed this up with an additional demand that the Partnership indemnify him for legal fees and expenses he paid in defending the lawsuit brought in Gregg County, Texas by the daughters of the Defendant.  On June 25, 2012, the Partnership filed a petition in the District Court of Gregg County, Texas against Scott D. Martin, seeking a declaratory judgment regarding the Partnership’s obligations to indemnify Scott D. Martin.

XML

General (Details) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended		1 Months Ended				3 Months Ended		9 Months Ended
	Jan. 25, 2012	Feb. 09, 2011	Jul. 31, 2012	May 31, 2012	May 31, 2011	Feb. 28, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 segment	Oct. 02, 2012	Sep. 30, 2011	Feb. 27, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Sharesvested			6,850
Number of primary business lines									4
Purchase of treasury units				$ 221	$ 235	$ 347			$ 221		$ 582
Purchase of treasury units (in units)				6,250	5,750	9,100
Treasury units from forfeitures (in units)					500
Annual vesting increments				25.00%	25.00%							25.00%
Share-based compensation expense							261	36	379		131
Incentive Distribution Rights [Abstract]
General partner interest percentage	2.00%	2.00%				2.00%
General partner quarterly cash distribution entitlement percentage (in hundredths)							2.00%		2.00%
Distribution threshold tier 1 maximum (in dollars per unit)							0.55		0.55
Percentage of cash distribution after threshold 1 (in hundredths)							15.00%		15.00%
Distribution threshold tier 2 maximum (in dollars per unit)							0.625		0.625
Percentage of cash distribution after threshold 2 (in hundredths)							25.00%		25.00%
Distribution threshold tier 3 maximum (in dollars per unit)							0.75		0.75
Percentage of cash distribution after threshold 3 (in hundredths)							50.00%		50.00%
Incentive distributions							$ 0	$ 1,265	$ 2,857	$ 18,000	$ 3,635
sharesremainingtobevested			2,250
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units issued (in shares)				6,250	6,250	9,100

XML

Subsequent Events

9 Months Ended

Sep. 30, 2012

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Litigation Settlement. On October 2, 2012, the Partnership announced that the ongoing litigation and disputes as described in Note 14 involving the shareholders of Martin Resource Management and various members of the Martin family had settled. The settlement, among other things, provided for a resolution of all of the lawsuits and disputes referenced in Note 14. In connection with the settlement, Martin Resource Management transferred 1,500,000 common units of the Partnership to KCM, LLC, and Martin Resource Management now owns 5,093,267 common units of the Partnership.

Acquisition of Lubricant Packaging Assets. On October 2, 2012, the Partnership purchased certain specialty lubricant packaging assets from Cross Oil Refining & Marketing, Inc., a wholly-owned subsidiary of Martin Resource Management. The consideration consisted of $121,800 in cash, including working capital of approximately $36,800, subject to certain post-closing adjustments. The purchase was funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these packaging assets will be recorded at amounts based on the historical carrying value of the assets at the acquisition date, and we are required to revise our historical financial statements to include the activities of the packaging assets as of the date of common control. Our historical financial statements will be retrospectively revised to reflect the financial position, cash flows and results of operations attributable to these packaging assets as if we owned them for each period presented.

Acquisition of Redbird Class A Interests. On October 2, 2012, the Partnership acquired from Martin Resource Management all of the remaining Class A interests in Redbird for $150,000 in cash. Prior to the transaction, the Partnership owned a 10.74% Class A interest and a 100% Class B interest in Redbird. This transaction was also funded by borrowings under the Partnership's revolving credit facility. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these interests will be recorded at amounts based on the historical carrying value of the interests at the acquisition date, and we are required to revise our historical financial statements to include the activities of the Class A interests as of the date of common control. Our historical financial statements will be retrospectively revised to reflect the financial position, cash flows and results of operations attributable to these packaging assets as if we owned them for each period presented.

Amendment No. 2 to Omnibus Agreement. In connection with the purchase of the Cross packaging assets, on October 2, 2012, the Partnership entered into Amendment No. 2 to the Partnership's omnibus agreement (the “Amendment”) with Martin Resource Management, the General Partner, and Martin Operating Partnership L.P. The Amendment allows the Partnership to provide certain products and services to Martin Resource Management under the Omnibus Agreement by amending the definition of the term “Business” to reflect the operation of the packaging assets acquired by the Partnership pursuant to the purchase agreement.

Amendment No. 3 to the Second Amendment and Restated Agreement of Limited Partnership. In conjunction with the Redbird purchase agreement, on October 2, 2012, the General Partner executed Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (“the Partnership Agreement”). The Partnership Agreement Amendment provides that the General Partner, currently the holder of the incentive distribution rights, shall not receive the next $18,000 in incentive distributions that it would otherwise be entitled to receive.

XML

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL (Unaudited) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance			$ 285,616	$ 274,806
Net Income	72,401	5,399	90,122	21,491
Follow-on public offerings			91,361	70,330
General partner contribution			1,951	1,505
Cash distributions			(58,332)	(47,956)
Excess purchase price over carrying value of acquired assets				(19,685)
Unit-based compensation			379	131
Purchase of treasury units			(221)	(582)
Adjustment in fair value of derivatives			(626)	(42)
Ending Balance	410,250	299,998	410,250	299,998
Accumulated Other Comprehensive Income (Loss) [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance			626	1,419
Adjustment in fair value of derivatives			(626)	(42)
Ending Balance		1,377		1,377
Limited Partner [Member] | Common Limited [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance			279,562	250,785
Beginning Balance (in units)			20,471,776	17,707,832
Net Income			85,519	17,499
Recognition of beneficial conversion feature				(831)
Follow-on public offerings (in units)			2,645,000	1,874,500
Follow-on public offerings			91,361	70,330
Cash distributions			(52,880)	(43,321)
Excess purchase price over carrying value of acquired assets				(19,685)
Unit-based compensation (in units)			6,250	15,530
Unit-based compensation			379	131
Purchase of treasury units (in units)			(6,250)	(14,850)
Purchase of treasury units			(221)	(582)
Unit based compensation grant forfeitures (in units)				(500)
Ending Balance (in units)	23,116,776	19,582,512	23,116,776	19,582,512
Ending Balance	403,720	274,326	403,720	274,326
Limited Partner [Member] | Subordinated Limited [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance				17,721
Beginning Balance (in units)				889,444
Recognition of beneficial conversion feature				831
Ending Balance (in units)		889,444		889,444
Ending Balance		18,552		18,552
General Partner [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance			5,428	4,881
Net Income			4,603	3,992
Follow-on public offerings				0
General partner contribution			1,951	1,505
Cash distributions			(5,452)	(4,635)
Ending Balance	$ 6,530	$ 5,743	$ 6,530	$ 5,743

XML

CONSOLIDATED AND CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Assets
Accounts and other receivables, allowance for doubtful accounts	$ 3,264	$ 3,021

XML

Related Party Transactions

9 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

As of September 30, 2012, Martin Resource Management owns 6,593,267 of the Partnership’s common units representing approximately 28.5% of the Partnership’s outstanding limited partnership units.  The Partnership’s general partner is a wholly-owned subsidiary of Martin Resource Management.  The Partnership’s general partner owns a 2.0% general partner interest in the Partnership and the Partnership’s incentive distribution rights.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of September 30, 2012, of approximately 28.5% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

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

Omnibus Agreement

Omnibus Agreement.   The Partnership and its general partner are parties to an omnibus agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain of Martin Resource Management’s trade names and trademarks. The omnibus agreement was amended on November 24, 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 2, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. See Note 16.   

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, refining, processing, distribution and midstream logistical services for hydrocarbon products and by-products;

• providing marine and other transportation of hydrocarbon products and by-products; and

• manufacturing and marketing fertilizers and related sulfur-based products.

This restriction does not apply to:

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

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

◦ providing land transportation of various liquids;

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

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

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

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

◦ building and marketing sulfur processing equipment; and

◦ developing an underground natural gas storage facility in Arcadia, Louisiana.

• 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; and

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

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

Effective October 1, 2011, through September 30, 2012, the Conflicts Committee of the board of directors of the general partner of the Partnership (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $6,582.  The Partnership reimbursed Martin Resource Management for $1,646 and $4,937 of indirect expenses for the three and nine months ended September 30, 2012, respectively.  The Partnership reimbursed Martin Resource Management $1,042 and $3,126 of indirect expenses for the three and nine months ended September 30, 2011, 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 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 of the general partner’s board of directors. For purposes of the omnibus agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read “Services” above.

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

Amendment and Termination. The omnibus agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the conflicts committee of the Partnership’s general partner if such amendment would adversely affect the unitholders. The omnibus agreement was first amended on November 24, 2009, to permit the Partnership to provide refining services to Martin Resource Management.  The omnibus agreement was amended further on October 2, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.  See Note 16. Such amendments were approved by the conflicts committee of the Partnership’s general partner.  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, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations.  This agreement replaced a prior agreement effective November 1, 2002, between the Partnership and Martin Transport, Inc. for land transportation services.  Under the agreement, Martin Transport, Inc. agreed to ship our NGL shipments as well as other liquid products.

Term and Pricing. This agreement was amended in November 2006, January 2007, April 2007 and January 2008 to add additional point-to-point rates and to modify certain fuel and insurance surcharges being charged to the Partnership.  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.  Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustment which are mutually agreed 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.

Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. This agreement replaced a prior agreement effective November 1, 2002 between the Partnership and Martin Resource Management covering marine transportation services which expired November 2005.  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.

Cross Marine Charter Agreements. Cross Oil & Refining Marketing, Inc. (“Cross”) entered into two marine charter agreements with the Partnership effective March 1, 2012.  These agreements have an initial term of five years and continue indefinitely thereafter subject to cancellation after the initial term by either party upon a 30 day written notice of cancellation. The charter hire payable under these agreements will be adjusted annually to reflect the percentage change in the Consumer Price Index.

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

Terminal Services Agreements

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

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

Other Agreements

 Cross Tolling Agreement. The Partnership is a party to an agreement under which it processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The Tolling Agreement has a 22 year term which expires November 25, 2031.   Under this Tolling Agreement, Martin Resource Management 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, Martin Resource Management agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement.  All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period.  In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. The Partnership is party to an agreement under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations.  This agreement, which was amended and restated in July 2011, will remain in place until the Partnership terminates it by providing 180 days’ written notice.  Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management.  Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

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

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

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Revenues:
Terminalling and storage	$	18,531		$	14,210	$	48,611	$	40,045
Marine transportation	3,979			6,352		13,282		19,223
Product sales:
Natural gas services	(1		)	29		104		663
Sulfur services	1,469			1,537		4,829		6,358
Terminalling and storage	168			62		850		176
	1,636			1,628		5,783		7,197
	$	24,146		$	22,190	$	67,676	$	66,465

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

Cost of products sold:
Natural gas services	$	6,761	$	9,257	$	18,783	$	13,679
Sulfur services	4,111		4,762		12,512		13,407
Terminalling and storage	127		45		292		183
	$	10,999	$	14,064	$	31,587	$	27,269

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

Expenses:
Operating expenses
Marine transportation	$	7,236	$	8,631	$	21,217	$	21,412
Natural gas services	453		480		1,368		1,176
Sulfur services	1,494		1,901		4,796		4,803
Terminalling and storage	4,917		5,893		14,927		14,779
	$	14,100	$	16,905	$	42,308	$	42,170

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

Selling, general and administrative:
Marine transportation	$	15	$	19	$	47	$	49
Natural gas services	366		308		1,052		884
Sulfur services	737		1,004		2,183		2,285
Terminalling and storage	—		—		39		—
Indirect overhead allocation, net of reimbursement	1,646		1,042		4,937		3,126
	$	2,764	$	2,373	$	8,258	$	6,344

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2012	Nov. 05, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	MARTIN MIDSTREAM PARTNERS LP
Entity Central Index Key	0001176334
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		23,116,776
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2012

XML

Business Segments

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Business Segments

Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, sulfur services and marine transportation. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

The accounting policies of the operating segments are the same as those described in Note 2 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011, filed with the SEC on March 5, 2012. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

The natural gas services segment information below excludes the discontinued operations of the Prism Assets for all periods.  See Note 4.

	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (loss) after eliminations			Capital Expenditures
Three Months Ended September 30, 2012
Terminalling and storage	$	45,667	$	(1,191	)	$	44,476	$	5,503	$	5,493		$	7,990
Natural gas services	190,738		—			190,738		149		3,270			143
Sulfur services	60,596		—			60,596		1,750		7,273			7,549
Marine transportation	22,879		(777		)	22,102		2,564		811			1,711
Indirect selling, general and administrative	—		—			—		—		(1,966		)	—
Total	$	319,880	$	(1,968	)	$	317,912	$	9,966	$	14,881		$	17,393
Three Months Ended September 30, 2011
Terminalling and storage	$	38,080	$	(1,174	)	$	36,906	$	4,829	$	3,457		$	14,360
Natural gas services	159,748		—			159,748		148		2,164			277
Sulfur services	70,169		—			70,169		1,676		5,921			2,598
Marine transportation	22,411		(1,638		)	20,773		3,372		(896		)	2,061
Indirect selling, general and administrative	—		—			—		—		(2,967		)	—
Total	$	290,408	$	(2,812	)	$	287,596	$	10,025	$	7,679		$	19,296
Nine Months Ended September 30, 2012
Terminalling and storage	$	130,131	$	(3,542	)	$	126,589	$	15,170	$	12,919		$	45,768
Natural gas services	527,666		—			527,666		436		6,457			410
Sulfur services	202,241		—			202,241		5,325		34,320			9,204
Marine transportation	65,912		(2,234		)	63,678		8,526		662			7,627
Indirect selling, general and administrative	—		—			—		—		(6,733		)	—
Total	$	925,950	$	(5,776	)	$	920,174	$	29,457	$	47,625		$	63,009
Nine Months Ended September 30, 2011
Terminalling and storage	$	115,492	$	(3,220	)	$	112,272	$	14,114	$	9,576		$	24,270
Natural gas services	423,953		—			423,953		435		5,598			581
Sulfur services	206,860		—			206,860		4,998		27,818			14,826
Marine transportation	63,201		(5,653		)	57,548		9,976		(5,143		)	9,092
Indirect selling, general and administrative	—		—			—		—		(6,547		)	—
Total	$	809,506	$	(8,873	)	$	800,633	$	29,523	$	31,302		$	48,769

The Partnership's assets by reportable segment, which exclude assets held for sale of $0 and $212,787, respectively, as of September 30, 2012 and December 31, 2011, are as follows:

	September 30, 2012		December 31, 2011
Total assets:
Terminalling and storage	$	161,544	$	231,764
Natural gas services	288,003		198,845
Sulfur services	258,712		162,289
Marine transportation	115,537		143,424
Total assets	$	823,796	$	736,322

XML

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS (Unaudited) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Revenues:
Terminalling and storage	$ 23,875	[1]	$ 19,381	[1]	$ 65,107	[1]	$ 56,831	[1]
Marine transportation	22,102	[1]	20,773	[1]	63,678	[1]	57,548	[1]
Sulfur services	2,926		2,850		8,777		8,550
Product sales:
Natural gas services	190,738	[1]	159,748	[1]	527,666	[1]	423,953	[1]
Sulfur services	57,670	[1]	67,319	[1]	193,464	[1]	198,310	[1]
Terminalling and storage	20,601	[1]	17,525	[1]	61,482	[1]	55,441	[1]
Total product sales	269,009		244,592		782,612		677,704
Total revenues	317,912		287,596		920,174		800,633
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	185,686	[1]	156,236	[1]	515,928	[1]	414,162	[1]
Sulfur services	47,272	[1]	59,808	[1]	149,582	[1]	164,142	[1]
Terminalling and storage	18,767		15,676		56,154		49,631
Total cost of products sold (excluding depreciation and amortization)	251,725		231,720		721,664		627,935
Expenses:
Operating expenses	36,655	[1]	34,354	[1]	108,109	[1]	100,676	[1]
Selling, general and administrative	4,680	[1]	5,538	[1]	13,687	[1]	13,015	[1]
Depreciation and amortization	9,966		10,025		29,457		29,523
Total costs and expenses	303,026		281,637		872,917		771,149
Other operating income (loss)	(5)		1,720		368		1,818
Operating income	14,881		7,679		47,625		31,302
Other income (expense):
Equity in earnings (loss) of unconsolidated entities	(169)		(54)		(532)		100
Interest expense	(6,263)		(4,297)		(21,735)		(17,102)
Debt prepayment premium	0		0		(2,470)		0
Other, net	587		24		732		125
Total other expense	(5,845)		(4,327)		(24,005)		(16,877)
Income from continuing operations before taxes	9,036		3,352		23,620		14,425
Income tax expense	(238)		(218)		(810)		(662)
Income from continuing operations	8,798		3,134		22,810		13,763
Income from discontinued operations, net of income taxes	63,603		2,265		67,312		7,728
Net income	72,401		5,399		90,122		21,491
Limited partner interest [Abstract]
Continuing Operations Attributable to Limited Partner Interest	10,128		2,157		21,645		10,674
Discontinuing Operations Attributable to Limited Partner Interest	60,825		1,617		63,874		5,994
Net Income (Loss) Allocated to Limited Partners	70,953		3,774		85,519		16,668
General partner interest [Abstract]
Continuing Operations Attributable to General Partner Interest	(1,330)		811		1,165		2,557
Discontinuing Operations Attributable to General Partner Interest	2,778		537		3,438		1,435
Net Income Allocated to General Partners	1,448		1,348		4,603		3,992
Net income attributable to:
Income from continuing operations	8,798		3,134		22,810		13,763
Income from discontinued operations	63,603		2,265		67,312		7,728
Net income	$ 72,401		$ 5,399		$ 90,122		$ 21,491
Basic:
Continuing operations (in dollars per unit)	0.44		0.11		0.94		0.56
Discontinued operations (in dollars per unit)	2.63		0.09		2.79		0.31
Net Income, Basic (in dollars per unit)	3.07		0.20		3.73		0.87
Weighted average limited partner units outstanding basic (in units)	23,101,233		19,158,334		22,929,172		19,161,403
Diluted:
Continuing operations (in dollars per unit)	0.44		0.11		0.94		0.56
Discontinued operations (in dollars per unit)	2.63		0.09		2.79		0.31
Net Income, Diluted (in dollars per unit)	3.07		0.20		3.73		0.87
Weighted average limited partner units (in thousands) - diluted (in units)	23,105,000		19,163,000		22,932,000		19,163,000

[1] *Related Party Transactions Included Above

XML

Discontinued operations and divestitures

9 Months Ended

Sep. 30, 2012

Discontinued Operations and Disposal Groups [Abstract]

Discontinued operations and divestitures

Discontinued operations and divestitures

On July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas Systems I, L.P. (“Prism Gas”), a wholly-owned subsidiary of the Partnership, and other natural gas gathering and processing assets also owned by the Partnership to a subsidiary of CenterPoint Energy Inc. (NYSE: CNP) (“CenterPoint”). The Partnership received net cash proceeds from the sale of $273,269.  The asset sale includes the Partnership’s 50% operating interest in Waskom Gas Processing Company (“Waskom”).  A subsidiary of CenterPoint owned the other 50% percent interest.  

Additionally, on September 18, 2012, the Partnership completed the sale of its interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) to a private investor group for $1,530.  

The assets described above collectively are referred to herein as the Prism Assets.

The Partnership classified the results of operations of the Prism Assets which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the consolidated and condensed statements of operations for all periods presented. The assets and liabilities to be sold met the accounting criteria to be classified as held for sale and were aggregated and reported on separate lines in the consolidated and condensed balance sheet at December 31, 2011.

The assets and liabilities classified held for sale as of December 31, 2011 were as follows:

	December 31, 2011
Assets
Inventories	$	486
Property, plant and equipment	78,324
Accumulated depreciation	(18,438		)
Goodwill	28,931
Investment in unconsolidated entities	107,549
Other assets, net	15,935
Assets held for sale	$	212,787
Liabilities
Other long-term obligations	501
Liabilities held for sale	$	501

The Prism Assets’ operating results, which are included within income from discontinued operations, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Total revenues from third parties1	$	9,269		$	28,714		$	66,842		$	90,917
Total costs and expenses, excluding depreciation and amortization	(9,296		)	(26,892		)	(64,556		)	(85,888		)
Depreciation and amortization	—			(1,375		)	(2,320		)	(4,128		)
Other operating income2	62,251			—			61,421			3
Equity in earnings of Waskom, Matagorda, and PIPE	377			1,839			4,611			6,854
Income from discontinued operations before income taxes	62,601			2,286			65,998			7,758
Income tax expense (benefit)	(1,002		)	21			(1,314		)	30
Income from discontinued operations, net of income taxes	$	63,603		$	2,265		$	67,312		$	7,728

¹ Total revenues from third parties excludes intercompany revenues of $3,285, $17,741, $26,431, and $49,444 for the three months ended September 30, 2012 and 2011, and nine months ended September 30, 2012 and 2011, respectively.

² The Partnership recognized a gain on the sale of its Prism Gas Business of $62,251 and $61,411 in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011, respectively.

XML

Acquisitions

9 Months Ended

Sep. 30, 2012

Business Combinations [Abstract]

Acquisitions

Acquisitions

Redbird Gas Storage

On May 31, 2011, the Partnership acquired all of the Class B equity interests in Redbird Gas Storage LLC (“Redbird”) for approximately $59,319.  This amount was recorded as an investment in an unconsolidated entity.  Redbird, a subsidiary of Martin Resource Management, is a natural gas storage joint venture formed to invest in Cardinal Gas Storage Partners, LLC (“Cardinal”).  Cardinal is a joint venture between Redbird and Energy Capital Partners that is focused on the development, construction, operation and management of natural gas storage facilities across North America.  Redbird owns an unconsolidated 40.95% interest in Cardinal.  Concurrent with the closing of this transaction, Cardinal acquired all of the outstanding equity interests in Monroe Gas Storage Company, LLC (“Monroe”) as well as an option on development rights to an adjacent depleted reservoir facility.  This acquisition was funded by borrowings under the Partnership’s revolving credit facility.  In addition to owning all of the Class B equity interests of Redbird, the Partnership also owns 10.74% of the Class A equity interests of Redbird at September 30, 2012.

Terminalling Facilities

On January 31, 2011, the Partnership acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for $36,500.  These assets are located across the Louisiana Gulf Coast.  This acquisition was funded by borrowings under the Partnership’s revolving credit facility.

These terminalling assets were acquired by Martin Resource Management in its acquisition of L&L Holdings LLC (“L&L”) on January 31, 2011.  During the second quarter of 2011, Martin Resource Management finalized the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the terminalling assets acquired by the Partnership.  The Partnership recorded an adjustment in the amount of $19,685 to reduce property, plant and equipment and partners’ capital for the difference between the purchase price and the fair value of the terminalling assets acquired based on Martin Resource Management’s final purchase price allocation.

XML

Consolidating Financial Statements

9 Months Ended

Sep. 30, 2012

Consolidating Financial Statements [Abstract]

Consolidating Financial Statements

Consolidating Financial Statements

Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, has issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. The Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has no independent assets or operations, the guarantees are full and unconditional, and the other subsidiary of the Partnership is minor. There are no significant restrictions on the ability of the Partnership or the Operating Partnership to obtain funds from any of their respective subsidiaries by dividend or loan.

XML

Long-Term Debt and Capital Leases

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Long-Term Debt and Capital Leases

Long-Term Debt and Capital Leases

At September 30, 2012 and December 31, 2011, long-term debt consisted of the following:

	September 30, 2012		December 31, 2011
$200,000*** Senior notes, 8.875% interest, net of unamortized discount of $1,688 and $2,192, respectively, issued March 2010 and due April 2018, unsecured**	$	173,312	$	197,808
$400,000 Revolving loan facility at variable interest rate (3.72%* weighted average at September 30, 2012), due April 2016 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	77,000		250,000
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured by equipment	—		6,363
Capital lease obligations	5,871		6,031
Total long-term debt and capital lease obligations	256,183		460,202
Less current installments	217		1,261
Long-term debt and capital lease obligations, net of current installments	$	255,966	$	458,941

     * Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%.  The applicable margin for existing LIBOR borrowings is 3.00%.  Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%.  Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to floating rate.  The floating rate cost was the applicable three-month LIBOR rate.  This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to floating rate.  The floating rate cost was the applicable three-month LIBOR rate.  This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

*** Pursuant to the Indenture under which the Senior Notes were issued, the Partnership has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings.  On April 24, 2012, the Partnership notified the Trustee of its intention to exercise a partial redemption of the Partnership’s Senior Notes pursuant to the Indenture.  On May 24, 2012, the Partnership redeemed $25,000 of the Senior Notes from various holders using proceeds of the Partnership’s January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under the Partnership’s revolving credit facility.  In conjunction with the redemption, the Partnership incurred a debt prepayment premium in the amount of $2,219, which is included in the consolidated and condensed statements of operations for the nine months ended September 30, 2012.

In August 2011, the Partnership terminated all of its existing interest rate swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes.  These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings.  The Partnership received a termination benefit of $2,800 upon cancellation of these swap agreements.

Effective May 10, 2012, the Partnership increased the maximum amount of borrowings and letters of credit available under the Credit Facility from $375,000 to $400,000.

The Partnership paid cash interest in the amount of $4,696 and $2,813 for the three months ended September 30, 2012 and 2011, respectively.  The Partnership paid cash interest in the amount of $19,039 and $6,662 for the nine months ended September 30, 2012 and 2011, respectively.  Capitalized interest was $175 and $127 for the three months ended September 30, 2012 and 2011, respectively.  Capitalized interest was $799 and $373 for the nine months ended September 30, 2012 and 2011, respectively.

XML

Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

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

The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of its outstanding hedge contracts, including assessing the possibility of counterparty default. If the Partnership determines that a derivative is no longer expected to be highly effective, the Partnership discontinues hedge accounting prospectively and recognizes subsequent changes in the fair value of the hedge in earnings.

All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings. The Partnership is exposed to the risk that periodic changes in the fair value of derivatives qualifying for hedge accounting will not be effective, as defined, or that derivatives will no longer qualify for hedge accounting. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is recorded to earnings. Likewise, if a hedge ceases to qualify for hedge accounting, any change in the fair value of derivative instruments since the last period is recorded to earnings; however, any amounts previously recorded to AOCI would remain there until such time as the original forecasted transaction occurs, then would be reclassified to earnings or if it is determined that continued reporting of losses in AOCI would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods, then the losses would be immediately reclassified to earnings.  If a forecasted hedge transaction is no longer probable of occurring, any gain or loss in AOCI is reclassified to earnings.

For derivative instruments that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. The effective portion of the derivative represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. To the extent the change in the fair value of the hedge does not perfectly offset the change in the fair value of the hedged item, the ineffective portion of the hedge is immediately recognized in earnings.

(a) Commodity Derivative Instruments

The Partnership is exposed to market risks associated with commodity prices and from time to time uses derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure.  These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership is focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

Due to the sale of the Prism Assets completed on July 31, 2012, as of September 30, 2012, the Partnership has terminated and settled all of its commodity derivative instruments.  For the three and nine months ended September 30, 2012, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in AOCI as a component of partners’ capital.

(b) Impact of Commodity Cash Flow Hedges

Crude Oil.  For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts decreased and increased crude revenue (included in income from discontinued operations) by $36 and $361, respectively.  For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased crude revenue (included in income from discontinued operations) by $496 and $658, respectively.

Natural Gas.  For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $77 and $72, respectively.  For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $813 and $215, respectively.  

Natural Gas Liquids.  For the three months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $5 and $236, respectively.  For the nine months ended September 30, 2012 and 2011, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $1,066 and $458, respectively. 

For information regarding fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note.

(c) Impact of Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt credit facility and its’ senior notes. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in AOCI until such time as the hedged item is recognized in earnings.

In August 2011, the Partnership terminated all of its existing interest swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes as described in Note 11.  These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings.  Termination fees of $2,800 were received on the early extinguishment of the interest rate swap agreements in August 2011.

The Partnership was not a party to interest rate derivatives during the nine months ended September 30, 2012.  The Partnership recognized decreases in interest expense of $3,244 and $5,779 for the three and nine months ended September 30, 2011, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges.

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

(d) Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items

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

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	September 30, 2012		December 31, 2011		Balance Sheet Location	September 30, 2012		December 31, 2011
Derivatives designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	622	Fair value of derivatives	$	—	$	245
Total derivatives designated as hedging instruments		$	—	$	622		$	—	$	245
Derivatives not designated as hedging instruments:	Current:					Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	117
Total derivatives not designated as hedging instruments		$	—	$	—		$	—	$	117

	Effect of Derivative Instruments on the Consolidated Statement of Operations For the Three Months Ended September 30, 2012 and 2011
	Effective Portion									Ineffective Portion and Amount  Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives				Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income				Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011			2012		2011			2012		2011
Derivatives designated as hedging instruments:
Commodity contracts	$	—	$	1,295	Income from discontinued operations	$	63	$	500	Income from discontinued operations	$	—	$	38
Total derivatives designated as hedging instruments	$	—	$	1,295		$	63	$	500		$	—	$	38

	Location of Gain or (Loss) Recognized in Income on  Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012			2011
Derivatives not designated as hedging instruments:
Interest rate contracts	Interest expense	$	—		$	3,244
Commodity contracts	Income from discontinued operations	(18		)	131
Total derivatives not designated as hedging instruments		$	(18	)	$	3,375

Effect of Derivative Instruments on the Consolidated Statement of Operations

For the Nine Months Ended September 30, 2012 and 2011

	Effective Portion										Ineffective Portion and Amount  Excluded from Effectiveness Testing
	Amount of Gain or (Loss) Recognized in OCI on Derivatives				Location of Gain or (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income					Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
	2012		2011			2012		2011				2012		2011
Derivatives designated as hedging instruments
Interest rate contracts	$	—	$	—	Interest expense	$	—	$	(18	)	Interest expense	$	—	$	—
Commodity contracts	126		1,231		Income from discontinued operations	748		1,264			Income from discontinued operations	4		$	27
Total derivatives designated as hedging instruments	$	126	$	1,231		$	748	$	1,246			$	4	$	27

	Location of Gain or (Loss) Recognized in Income on  Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2012		2011
Derivatives not designated as hedging instruments
Interest rate contracts	Interest Expense	$	—	$	5,797
Commodity contracts	Income from discontinued operations	1,623		41
Total derivatives not designated as hedging instruments		$	1,623	$	5,838

No amounts are expected to be reclassified into earnings for the subsequent 12-month period for commodity cash flow hedges.

XML

Inventories

9 Months Ended

Sep. 30, 2012

Inventory Disclosure [Abstract]

Inventories

Inventories

Components of inventories at September 30, 2012 and December 31, 2011 were as follows: 

	September 30, 2012		December 31, 2011
Natural gas liquids	$	64,783	$	25,178
Sulfur	26,460		24,335
Sulfur based products	14,115		14,857
Lubricants	8,471		11,012
Other	2,431		2,295
	$	116,260	$	77,677

XML

Investments in Unconsolidated Entities and Joint Ventures

9 Months Ended

Sep. 30, 2012

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Entities and Joint Ventures

Investments in Unconsolidated Entities and Joint Ventures

As discussed in detail in Note 4, the Partnership sold its 50% interests in Waskom, Matagorda, and PIPE. The equity in earnings associated with these investments during the periods owned is recorded in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011.

The Partnership and Martin Resource Management formed Redbird, a natural gas storage joint venture formed to invest in Cardinal.  The Partnership owns 10.74% of the Class A equity interests and all the Class B equity interests in Redbird.  Redbird owns an unconsolidated 40.95% interest in Cardinal.   Redbird utilized the investments by the Partnership to invest in Cardinal to fund projects for natural gas storage facilities.

During the second quarter of 2012, the Partnership acquired an unconsolidated 50% interest in Caliber Gathering System, LLC (“Caliber”) and Pecos Valley Producer Services LLC (“Pecos Valley”). The Partnership sold its interest in Pecos Valley during the third quarter of 2012 for $531, resulting in a gain of $486 recorded in Other, Net in the Partnership's consolidated and condensed statement of operations for the three and nine months ended September 30, 2012.

These investments are accounted for by the equity method.

The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s consolidated and condensed balance sheets and the components of equity in earnings of unconsolidated entities included in the Partnership’s consolidated and condensed statements of operations:

	September 30, 2012		December 31, 2011
Investment in Waskom1	$	—	$	102,896
Investment in PIPE1	—		1,291
Investment in Matagorda1	—		3,362
Investment in unconsolidated entities classified as assets held for sale	—		107,549
Investment in Redbird	80,168		62,948
Investment in Caliber	631		—
Investment in unconsolidated entities	80,799		62,948
Total Investment in unconsolidated entities	$	80,799	$	170,497

¹ As of December 31, 2011, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed balance sheet as assets held for sale.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Equity in earnings of Waskom1	$	287		$	1,767		$	4,172		$	6,779
Equity in earnings of PIPE1	10			(15		)	(60		)	(45		)
Equity in earnings of Matagorda1	80			87			499			120
Equity in earnings of discontinued operations	377			1,839			4,611			6,854
Equity in earnings of Redbird	(103		)	(54		)	(433		)	100
Equity in earnings of Caliber	(98		)	—			(119		)	—
Equity in earnings of Pecos Valley	32			—			20			—
Equity in earnings of unconsolidated entities	(169		)	(54		)	(532		)	100
Total equity in earnings of unconsolidated entities	$	208		$	1,785		$	4,079		$	6,954

¹ For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed statement of operations and cash flows as discontinued operations.

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

	As of September 30				Three Months Ended September 30				Nine Months Ended September 30
	Total Assets		Partner’s Capital		Revenues1		Net Income1		Revenues1		Net Income1
2012
Waskom	$	—	$	—	$	8,171	$	668	$	66,662	$	8,986
	As of December 31
2011
Waskom	$	146,655	$	126,863	$	29,508	$	3,808	$	95,086	$	14,382

¹ Revenues and Net Income for Waskom include financial information only for the periods owned. Three months ended September 30, 2012 only includes financial information for the one month ended July 31, 2012. Nine months ended September 30, 2012 only includes financial information for the seven months ended July 31, 2012.

As of September 30, 2012 and December 31, 2011 the amount of the Partnership’s consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity-method investees is $0 and $47,152, respectively.  There are no material restrictions to transfer funds in the form of dividends, loans or advances related to the equity-method investees.

As of September 30, 2012 and December 31, 2011, the Partnership’s interest in cash of the unconsolidated equity-method investees was $502 and $565, respectively.

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The Partnership provides disclosures pursuant to certain provisions of ASC 820, which provides a framework for measuring fair value and expanded disclosures about fair value measurements.  ASC 820 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value into one of the following categories:

Level 1: Quoted market prices in active markets for identical assets or liabilities.

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

Level 3: Unobservable inputs that are not corroborated by market data.

The Partnership’s derivative instruments, which consist of commodity and interest rate swaps, are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets, which is considered Level 2. Refer to Note 7 for further information on the Partnership’s derivative instruments and hedging activities.

The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at December 31, 2011:

	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	December 31, 2011		(Level 1)		(Level 2)		(Level 3)
Assets
Natural gas derivatives	$	622	$	—	$	622	$	—
Total assets	$	622	$	—	$	622	$	—
Liabilities
Crude oil derivatives	245		—		245		—
Natural gas liquids derivatives	117		—		117		—
Total liabilities	$	362	$	—	$	362	$	—

ASC 825-10-65, related to disclosures about fair value of financial instruments, requires that the Partnership disclose estimated fair values for its financial instruments.  Fair value estimates are set forth below for the Partnership’s financial instruments.  The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

• Accounts and other receivables, trade and other accounts payable, 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.

• Long-term debt including current installments — the carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate.

The estimated fair value of the Senior Notes was approximately $189,557 as of September 30, 2012 based on quoted market prices of similar debt at September 30, 2012, which is deemed a Level 2 measurement.

XML

Long-Term Debt and Capital Leases (Tables)

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Schedule of long-term debt

At September 30, 2012 and December 31, 2011, long-term debt consisted of the following:

	September 30, 2012		December 31, 2011
$200,000*** Senior notes, 8.875% interest, net of unamortized discount of $1,688 and $2,192, respectively, issued March 2010 and due April 2018, unsecured**	$	173,312	$	197,808
$400,000 Revolving loan facility at variable interest rate (3.72%* weighted average at September 30, 2012), due April 2016 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	77,000		250,000
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured by equipment	—		6,363
Capital lease obligations	5,871		6,031
Total long-term debt and capital lease obligations	256,183		460,202
Less current installments	217		1,261
Long-term debt and capital lease obligations, net of current installments	$	255,966	$	458,941

     * Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%.  The applicable margin for existing LIBOR borrowings is 3.00%.  Effective October 1, 2012, the applicable margin for existing LIBOR borrowings remained at 3.00%.  Effective January 1, 2013, the applicable margin for existing LIBOR borrowings will decrease to 2.25%.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to floating rate.  The floating rate cost was the applicable three-month LIBOR rate.  This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

** Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to floating rate.  The floating rate cost was the applicable three-month LIBOR rate.  This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011.

*** Pursuant to the Indenture under which the Senior Notes were issued, the Partnership has the option to redeem up to 35% of the aggregate principal amount at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest with the proceeds of certain equity offerings.  On April 24, 2012, the Partnership notified the Trustee of its intention to exercise a partial redemption of the Partnership’s Senior Notes pursuant to the Indenture.  On May 24, 2012, the Partnership redeemed $25,000 of the Senior Notes from various holders using proceeds of the Partnership’s January 2012 follow-on equity offering, which in the interim were used to pay down amounts outstanding under the Partnership’s revolving credit facility.  In conjunction with the redemption, the Partnership incurred a debt prepayment premium in the amount of $2,219, which is included in the consolidated and condensed statements of operations for the nine months ended September 30, 2012.

XML

Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 30, 2010 SDM v MRMC [Member]	Dec. 31, 2009 SDM v MRMC [Member]	Dec. 31, 2008 SDM v MRMC [Member] employee
Loss Contingencies [Line Items]
Number of other officers and employees named in suit				35
Damages awarded to defendants	$ 1,800	$ 2,700	$ 4,900

XML

Income Taxes

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Because its income is taxed directly to its partners, the operations of a partnership are generally not subject to income taxes, except as discussed below.  Effective January 1, 2007, the Partnership became subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the consolidated statements of operations.

The Partnership’s taxable subsidiary, Woodlawn, is subject to income taxes due to its corporate structure. Income tax expense related to Woodlawn is recorded in discontinued operations.  A current state income tax expense of $568 and $574, related to Woodlawn was recorded for the three and nine months ended September 30, 2012. A current state income tax expense of $6 and $17 related to Woodlawn was recorded for the three and nine months ended September 30, 2011, respectively.  

A deferred tax benefit related to the Woodlawn basis differences of  $7,373 and $7,695 was recorded for the three and nine months ended September 30, 2012, respectively. A deferred tax expense of $33 and $2 was recorded for the three and nine months ended September 30, 2011, respectively.  A deferred tax (asset) liability of $(38) and $7,657 related to the basis differences existed at September 30, 2012 and December 31, 2011, respectively.

Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.  State income taxes attributable to the Texas margin tax of $238 and $810 were recorded in current income tax expense in continuing operations for the three and nine months ended September 30, 2012 and $218 and $662 for the three and nine months ended September 30, 2011, respectively.

The components of income tax expense (benefit) from operations recorded for the three and nine months ended September 30, 2012 and 2011 are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	806			223			1,384			679
	6,609			206			7,191			690
Deferred:
Federal	(7,373		)	33			(7,695		)	2
Total income tax expense (benefit)	$	(764	)	$	239		$	(504	)	$	692

Total income tax expense was allocated to continuing and discontinued operations as follows:

Income tax expense (benefit) from continuing operations:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Current:
State	$	238	$	218	$	810	$	662
Total income tax expense from continuing operations	$	238	$	218	$	810	$	662

Income tax expense (benefit) from discontinued operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current:
Federal	$	5,803		$	(17	)	$	5,807		$	11
State	568			6			574			17
	6,371			(11		)	6,381			28
Deferred:
Federal	(7,373		)	32			(7,695		)	2
Total income tax expense (benefit) from discontinued operations	$	(1,002	)	$	21		$	(1,314	)	$	30

XML

General (Tables)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Reconciliation of net income to limited partners' interest

The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	8,798		$	3,134		$	22,810	$	13,763
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	(1,536		)	763			723		2,328
Distributions payable on behalf of general partner interest	(320		)	207			295		640
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	526			(159		)	147		(411		)
Less beneficial conversion feature	—			166			—		532
Limited partners’ interest in net income	$	10,128		$	2,157		$	21,645	$	10,674

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	63,603	$	2,265		$	67,312	$	7,728
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	1,536		502			2,134		1,307
Distributions payable on behalf of general partner interest	709		138			872		360
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest	533		(103		)	432		(232		)
Less beneficial conversion feature	—		111			—		299
Limited partners’ interest in net income	$	60,825	$	1,617		$	63,874	$	5,994

XML

Equity Offering (Details) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended		1 Months Ended	9 Months Ended
	Jan. 25, 2012	Feb. 09, 2011	Feb. 28, 2011	Sep. 30, 2012	Sep. 30, 2011
Equity Offering [Abstract]
Units issued in public offering (in shares)	2,645,000	1,874,500
Sale of stock (in dollars per share)	$ 36.15	$ 39.35
Proceeds from the public offering	$ 91,361	$ 70,330
General partner contribution to maintain GP interest	$ 1,951	$ 1,505		$ 1,951	$ 1,505
General partner interest percentage	2.00%	2.00%	2.00%

XML

Investments in Unconsolidated Entities and Joint Ventures (Details) (USD $)	1 Months Ended		3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Unconsolidated interest ownership	50.00%		50.00%				50.00%
Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities [Abstract]
Investment in unconsolidated entities classified as assets held for sale	$ 0		$ 0				$ 0				$ 107,549,000
Investment in unconsolidated entities	80,799,000		80,799,000				80,799,000				62,948,000
Total Investment in unconsolidated entities	80,799,000		80,799,000				80,799,000				170,497,000
Equity in earnings of discontinued operations			377,000		1,839,000		4,611,000		6,854,000
Equity in earnings of unconsolidated entities			(169,000)		(54,000)		(532,000)		100,000
Total equity in earnings of unconsolidated entities			208,000		1,785,000		4,079,000		6,954,000
Select financial information for significant unconsolidated equity-method investees [Abstract]
Undistributed earnings related to unconsolidated equity-method investees	0		0				0				47,152,000
Partnership's interest in cash of the unconsolidated equity-method investees	502,000		502,000				502,000				565,000
Proceeds from sale of equity method investment	531						531,000		0
Equity Method Investment, Realized Gain (Loss) on Disposal	486						486,000		0
Waskom [Member]
Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities [Abstract]
Investment in unconsolidated entities classified as assets held for sale	0	[1]	0	[1]			0	[1]			102,896,000	[1]
Equity in earnings of discontinued operations			287,000	[2]	1,767,000	[2]	4,172,000	[2]	6,779,000	[2]
Select financial information for significant unconsolidated equity-method investees [Abstract]
Total Assets	0		0				0				146,655,000
Partner's Capital	0		0				0				126,863,000
Revenues			8,171,000	[3]	29,508,000	[3]	66,662,000	[3]	95,086,000	[3]
Net Income			668,000	[3]	3,808,000	[3]	8,986,000	[3]	14,382,000	[3]
Panther Interstate Pipeline Energy LLC [Member]
Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities [Abstract]
Investment in unconsolidated entities classified as assets held for sale	0	[1]	0	[1]			0	[1]			1,291,000	[1]
Equity in earnings of discontinued operations			10,000	[2]	(15,000)	[2]	(60,000)	[2]	(45,000)	[2]
Matagorda Offshore Gathering System [Member]
Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities [Abstract]
Investment in unconsolidated entities classified as assets held for sale	0	[1]	0	[1]			0	[1]			3,362,000	[1]
Equity in earnings of discontinued operations			80,000	[2]	87,000	[2]	499,000	[2]	120,000	[2]
Redbird [Member]
Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities [Abstract]
Investment in unconsolidated entities	80,168,000		80,168,000				80,168,000				62,948,000
Equity in earnings of unconsolidated entities			(103,000)		(54,000)		(433,000)		100,000
Pecos Valley [Member]
Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities [Abstract]
Equity in earnings of unconsolidated entities			32,000		0		20,000		0
Caliber [Member]
Schedule of Equity Method Investments [Line Items]
Unconsolidated interest ownership	50.00%		50.00%				50.00%
Summary of components of investment in unconsolidated entities and components of equity in earnings of unconsolidated entities [Abstract]
Investment in unconsolidated entities	631,000		631,000				631,000				0
Equity in earnings of unconsolidated entities			$ (98,000)		$ 0		$ (119,000)		$ 0
Waskom Matagorda and PIPE [Member]
Schedule of Equity Method Investments [Line Items]
Unconsolidated interest ownership	50.00%		50.00%				50.00%
Redbird Gas Storage [Member] | Common Class A [Member]
Schedule of Equity Method Investments [Line Items]
Unconsolidated interest ownership	10.74%		10.74%				10.74%
Redbird Gas Storage [Member] | Common Class B [Member]
Schedule of Equity Method Investments [Line Items]
Unconsolidated interest ownership	40.95%		40.95%				40.95%

[1] As of December 31, 2011, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed balance sheet as assets held for sale. Three Months Ended September 30, Nine Months Ended September 30, 2012 2011 2012 2011Equity in earnings of Waskom1$287 $1,767 $4,172 $6,779Equity in earnings of PIPE110 (15) (60) (45)Equity in earnings of Matagorda180 87 499 120 Equity in earnings of discontinued operations377 1,839 4,611 6,854Equity in earnings of Redbird(103) (54) (433) 100Equity in earnings of Caliber(98) — (119) —Equity in earnings of Pecos Valley32 — 20 — Equity in earnings of unconsolidated entities(169) (54) (532) 100 Total equity in earnings of unconsolidated entities$208 $1,785 $4,079 $6,954

[2] For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated and condensed statement of operations and cash flows as discontinued operations.

[3] Revenues and Net Income for Waskom include financial information only for the periods owned. Three months ended September 30, 2012 only includes financial information for the one month ended July 31, 2012. Nine months ended September 30, 2012 only includes financial information for the seven months ended July 31, 2012.

XML

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Revenues:
Terminalling and storage	$ 18,531	$ 14,210	$ 48,611	$ 40,045
Marine transportation	3,979	6,352	13,282	19,223
Product Sales	1,636	1,628	5,783	7,197
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	6,761	9,257	18,783	13,679
Sulfur services	4,111	4,762	12,512	13,407
Expenses:
Operating expenses	14,100	16,905	42,308	42,170
Selling, general and administrative	$ 2,764	$ 2,373	$ 8,258	$ 6,344

XML

New Accounting Pronouncements

9 Months Ended

Sep. 30, 2012

Accounting Changes and Error Corrections [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

In September 2011, the FASB amended the provisions of ASC 350 related to testing goodwill for impairment.  This update simplifies the goodwill impairment assessment by allowing a company to first review qualitative factors to determine the likelihood of whether the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, the company would not be required to perform the two-step goodwill impairment test for that reporting unit. This update is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  This amended guidance was adopted by the Partnership effective January 1, 2012.

In June 2011, the FASB amended the provisions of ASC 220 related to other comprehensive income. This newly issued guidance: (1) eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity; (2) requires the consecutive presentation of the statement of net income and other comprehensive income; and (3) requires an entity to present reclassification adjustments on the face of the financial statements from other comprehensive income to net income. The amendments in this guidance do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income nor do the amendments affect how earnings per share is calculated or presented. This guidance is required to be applied retrospectively and is effective for fiscal years and interim periods within those years beginning after December 15, 2011.  This amended guidance was adopted by the Partnership effective January 1, 2012.  As this new guidance only requires enhanced disclosure, adoption did not impact the Partnership’s financial position or results of operations.

XML

Discontinued operations and divestitures (Tables)

9 Months Ended

Sep. 30, 2012

Discontinued Operations and Disposal Groups [Abstract]

Schedule of disposal groups including discontinued operations income statement and balance sheet

The assets and liabilities classified held for sale as of December 31, 2011 were as follows:

	December 31, 2011
Assets
Inventories	$	486
Property, plant and equipment	78,324
Accumulated depreciation	(18,438		)
Goodwill	28,931
Investment in unconsolidated entities	107,549
Other assets, net	15,935
Assets held for sale	$	212,787
Liabilities
Other long-term obligations	501
Liabilities held for sale	$	501

The Prism Assets’ operating results, which are included within income from discontinued operations, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Total revenues from third parties1	$	9,269		$	28,714		$	66,842		$	90,917
Total costs and expenses, excluding depreciation and amortization	(9,296		)	(26,892		)	(64,556		)	(85,888		)
Depreciation and amortization	—			(1,375		)	(2,320		)	(4,128		)
Other operating income2	62,251			—			61,421			3
Equity in earnings of Waskom, Matagorda, and PIPE	377			1,839			4,611			6,854
Income from discontinued operations before income taxes	62,601			2,286			65,998			7,758
Income tax expense (benefit)	(1,002		)	21			(1,314		)	30
Income from discontinued operations, net of income taxes	$	63,603		$	2,265		$	67,312		$	7,728

¹ Total revenues from third parties excludes intercompany revenues of $3,285, $17,741, $26,431, and $49,444 for the three months ended September 30, 2012 and 2011, and nine months ended September 30, 2012 and 2011, respectively.

² The Partnership recognized a gain on the sale of its Prism Gas Business of $62,251 and $61,411 in income from discontinued operations for the three and nine months ended September 30, 2012 and 2011, respectively.

XML

Acquisitions (Details) (USD $) In Thousands, unless otherwise specified				9 Months Ended
	Sep. 30, 2012	May 31, 2011 Redbird Gas Storage [Member] Common Class A [Member]	Sep. 30, 2012 Redbird Gas Storage [Member] Common Class B [Member]	Sep. 30, 2012 Terminalling Facilities [Member] facility	Jan. 31, 2011 Terminalling Facilities [Member] facility	Sep. 30, 2012 Redbird Gas Storage [Member] Common Class A [Member]	Sep. 30, 2012 Redbird Gas Storage [Member] Common Class B [Member]
Business Acquisition [Line Items]
Cost of acquired entity		$ 59,319			$ 36,500
Unconsolidated interest ownership	50.00%		40.95%			10.74%	40.95%
Number of marine terminalling facilities				13	13
Number of specialty terminalling facility				1	1
Assets, Fair Value Adjustment				$ 19,685

XML

Equity Offering

9 Months Ended

Sep. 30, 2012

Equity Offering [Abstract]

Equity Offering

Equity Offering

On January 25, 2012, the Partnership completed a public offering of 2,645,000 common units at a price of $36.15 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 2,645,000 common units, net of underwriters’ discounts, commissions and offering expenses were $91,361.  The Partnership’s general partner contributed $1,951 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership.  On January 25, 2012, all of the net proceeds were used to reduce outstanding indebtedness of the Partnership.

On February 9, 2011, the Partnership completed a public offering of 1,874,500 common units at a price of $39.35 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 1,874,500 common units, net of underwriters’ discounts, commissions and offering expenses were $70,330.  The Partnership’s general partner contributed $1,505 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership.  The net proceeds were used to reduce the outstanding balance under its revolving credit facility.