Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

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 7, 2011 was 19,582,332. The number of the registrant’s subordinated units outstanding at November 7, 2011 was 889,444.

		Page

PART I –FINANCIAL INFORMATION		2

Item 1.	Financial Statements	2
	Consolidated and Condensed Balance Sheets as of September 30, 2011 (unaudited) and December 31, 2010 (audited);	2
	Consolidated and Condensed Statements of Operations for the Three and Nine Months ended September 30, 2011 and 2010 (unaudited);	3
	Consolidated and Condensed Statements of Capital for the Three and Nine Months Ended September 30, 2011 and 2010 (unaudited);	4
	Consolidated and Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2011 and 2010 (unaudited);	5
	Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010 (unaudited);	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	62

Item 4.	Controls and Procedures	64

PART II. OTHER INFORMATION		65

Item 1.	Legal Proceedings	65

Item 1A.	Risk Factors	65

Item 5.	Other Information	65

Item 6.	Exhibits	67

SIGNATURE
CERTIFICATIONS

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	September 30, 2011 (Unaudited)			December 31, 2010 (Audited)
Assets
Cash	$	296		$	11,380
Accounts and other receivables, less allowance for doubtful accounts of $3,592 and $2,528, respectively		99,196			95,276
Product exchange receivables		25,651			9,099
Inventories		80,852			52,616
Due from affiliates		12,279			6,437
Fair value of derivatives		934			2,142
Other current assets		908			2,784
Total current assets		220,116			179,734

Property, plant and equipment, at cost		689,905			632,456
Accumulated depreciation		(225,058	)		(200,276	)
Property, plant and equipment, net		464,847			432,180

Goodwill		37,268			37,268
Investment in unconsolidated entities		163,414			98,217
Fair value of derivatives		144			—
Deferred debt costs		13,850			13,497
Other assets, net		24,239			24,582
	$	923,878		$	785,478
Liabilities and Partners’ Capital
Current portion of capital lease obligations	$	1,201		$	1,121
Trade and other accounts payable		94,447			82,837
Product exchange payables		49,702			22,353
Due to affiliates		14,708			6,957
Income taxes payable		789			811
Fair value of derivatives		—			282
Other accrued liabilities		14,261			10,034
Total current liabilities		175,108			124,395

Long-term debt and capital leases, less current maturities		439,213			372,862
Deferred income taxes		7,816			8,213
Fair value of derivatives		—			4,100
Other long-term obligations		1,743			1,102
Total liabilities		623,880			510,672

Partners’ capital		298,621			273,387
Accumulated other comprehensive income		1,377			1,419
Total partners’ capital		299,998			274,806
Commitments and contingencies
	$	923,878		$	785,478

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues:
Terminalling and storage *	$	19,381		$	17,357		$	56,831		$	50,062
Marine transportation *		20,773			21,468			57,548			57,458
Sulfur services		2,850			—			8,550			—
Product sales: *
Natural gas services		188,461			107,842			514,870			397,855
Sulfur services		67,319			36,658			198,310			113,945
Terminalling and storage		17,525			12,062			55,441			30,687
		273,305			156,562			768,621			542,487
Total revenues		316,309			195,387			891,550			650,007

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *		180,499			102,487			492,120			379,433
Sulfur services *		59,808			30,505			164,142			86,855
Terminalling and storage		15,676			11,363			49,631			28,771
		255,983			144,355			705,893			495,059
Expenses:
Operating expenses *		35,669			29,017			104,730			86,314
Selling, general and administrative *		6,849			4,542			16,889			14,650
Depreciation and amortization		11,400			10,175			33,651			30,066
Total costs and expenses		309,901			188,089			861,163			626,089

Other operating income		1,720			405			1,818			450
Operating income		8,128			7,703			32,205			24,368

Other income (expense):
Equity in earnings of unconsolidated entities		1,784			2,951			6,953			7,469
Interest expense		(4,297	)		(6,051	)		(17,102	)		(22,248	)
Other, net		23			34			127			117
Total other income (expense)		(2,490	)		(3,066	)		(10,022	)		(14,662	)
Net income before taxes		5,638			4,637			22,183			9,706
Income tax benefit (expense)		( 239	)		( 1	)		(692	)		(224	)

Net income	$	5,399		$	4,636		$	21,491		$	9,482

General partner’s interest in net income	$	1,348		$	1,000		$	3,992		$	2,832
Limited partners’ interest in net income	$	3,774		$	3,359		$	16,668		$	5,819

Net income per limited partner unit - basic and diluted	$	0.20		$	0.19		$	0.87		$	0.33

Weighted average limited partner units - basic		19,158,334			17,700,875			19,161,403			17,466,200
Weighted average limited partner units - diluted		19,163,128			17,701,719			19,163,066			17,467,514

See accompanying notes to consolidated and condensed financial statements.

*Related Party Transactions Included Above

Revenues:
Terminalling and storage	$	14,210	$	12,292	$	40,045	$	34,579
Marine transportation		6,351		7,968		19,223		20,948
Product Sales		2,024		5,265		10,745		8,647
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services		31,871		16,353		80,829		57,721
Sulfur services		4,762		4,212		13,407		11,448
Expenses:
Operating expenses		17,223		12,215		42,966		35,986
Selling, general and administrative		3,576		2,704		9,490		8,141

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)

	Partners’ Capital
	Common						Subordinated				General Partner			Accumulated Other Comprehensive Income
	Units			Amount			Units		Amount		Amount			(Loss)			Total

Balances – January 1, 2010		16,057,832		$	245,683			889,444	$	16,613	$	4,731		$	(2,076	)	$	264,951

Net income		—			6,650			—		—		2,832			—			9,482

Recognition of beneficial conversion feature		—			(831	)		—		831		—			—			—

Follow-on public offering		2,650,000			78,600			—		—		—			—			78,600

Redemption of common units		(1,000,000	)		(28,070	)		—		—		—			—			(28,070	)

General partner contribution		—			—			—		—		1,089			—			1,089

Distributions to parent		—			(4,369	)		—		—		—			—			(4,369	)

Cash distributions		—			(38,605	)		—		—		(3,580	)		—			(42,185	)

Unit-based compensation		3,500			66			—		—		—			—			66

Purchase of treasury units		(3,500	)		(108	)		—		—		—			—			(108	)

Adjustment in fair value of derivatives		—			—			—		—		—			3,906			3,906

Balances – September 30, 2010		17,707,832		$	259,016			889,444	$	17,444	$	5,072		$	1,830		$	283,362


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	)

Distribution to parent		—			(19,685	)		—		—		—			—			(19,685	)

Unit-based compensation		15,350			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		19,582,332		$	274,326			889,444	$	18,552	$	5,743		$	1,377		$	299,998

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

Net income	$	5,399		$	4,636		$	21,491		$	9,482
Changes in fair values of commodity cash flow hedges		1,295			71			1,231			816
Commodity cash flow hedging gains (losses) reclassified to earnings		(538	)		(223	)		(1,291	)		(609	)
Changes in fair value of interest rate cash flow hedges		—			—			—			(241	)
Interest rate cash flow hedging losses reclassified to earnings		—			606			18			3,940

Comprehensive income	$	6,156		$	5,090		$	21,449		$	13,388

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Nine Months Ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	21,491		$	9,482
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		33,651			30,066
Amortization of deferred debt issuance costs		3,071			3,676
Amortization of debt discount		262			181
Deferred taxes		2			(474	)
(Gain) loss on sale of property, plant and equipment		405			(450	)
Equity in earnings of unconsolidated entities		(6,953	)		(7,469	)
Distributions in-kind from equity investments		9,010			7,524
Non-cash mark-to-market on derivatives		(3,360	)		(3,592	)
Other		131			66
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		(1,516	)		16,171
Product exchange receivables		(16,552	)		1,372
Inventories		(28,236	)		(15,766	)
Due from affiliates		(5,842	)		(2,217	)
Other current assets		1,477			(950	)
Trade and other accounts payable		11,610			(5,633	)
Product exchange payables		27,350			4,165
Due to affiliates		7,751			467
Income taxes payable		(22	)		109
Other accrued liabilities		4,227			9,625
Change in other non-current assets and liabilities		(122	)		(3,865	)
Net cash provided by operating activities		57,835			42,488
Cash flows from investing activities:
Payments for property, plant and equipment		(49,634	)		(12,616	)
Acquisitions		(16,815	)		(7,331	)
Payments for plant turnaround costs		(2,103	)		(1,090	)
Proceeds from sale of property, plant and equipment		530			1,944
Investment in unconsolidated entities		(59,319	)		(20,110	)
Return of investments from unconsolidated entities		1,668			2,430
Distributions from (contributions to) unconsolidated entities for operations		(9,603	)		628
Net cash used in investing activities		(135,276	)		(36,145	)
Cash flows from financing activities:
Payments of long-term debt		(389,000	)		(383,100	)
Payments of notes payable and capital lease obligations		(831	)		(260	)
Proceeds from long-term debt		456,000			392,269
Net proceeds from follow on offering		70,330			78,600
Redemption of common units		—			(28,070	)
General partner contribution		1,505			1,089
Distribution to parent		(19,685	)		(4,369	)
Payments of debt issuance costs		(3,424	)		(7,425	)
Purchase of treasury units		(582	)		(108	)
Cash distributions paid		(47,956	)		(42,185	)
Net cash provided by financing activities		66,357			6,441
Net increase (decrease) in cash		(11,084	)		12,784
Cash at beginning of period		11,380			5,956
Cash at end of period	$	296		$	18,740

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(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, 2010, filed with the Securities and Exchange Commission (the “SEC”) on March 2, 2011.

(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 2011, the Partnership issued 6,250 restricted common units to 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. These units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015.

In August 2010, the Partnership issued 1,500 restricted common units to each of two new non-employee directors under its long-term incentive plan from 500 treasury units purchased by the Partnership in the open market for $16 and 2,500 common units from forfeited unit grants. These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.

In May 2010, the Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan from treasury shares purchased by the Partnership in the open market for $92. These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014.

The cost resulting from share-based payment transactions was $36 and $28 for the three months ended September 30, 2011 and 2010, respectively, and $131 and $66 for the nine months ended September 30, 2011 and 2010, respectively.

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.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

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, 2011 and 2010 the general partner received $1,265 and $926, respectively, in incentive distributions. For the nine months ended September 30, 2011 and 2010, the general partner received $3,635 and $2,696, respectively, in incentive distributions.

(d) Net Income per Unit

The Partnership follows the provisions of Financial Accounting Standards Board(“FASB”) Accounting Standards Codification Topic (“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. To the extent the Partnership Agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the Partnership Agreement. 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.

The provisions of ASC 260-10 did not impact the Partnership’s computation of earnings per limited partner unit as cash distributions exceeded earnings for the three and nine months ended September 30, 2011 and 2010, respectively, and the IDRs do not share in losses under the Partnership Agreement. In the event the Partnership’s earnings exceed cash distributions, ASC 260-10 will have an impact on the computation of the Partnership’s earnings per limited partner unit. For the three months and nine months ended September 30, 2011 and 2010, the general partner’s interest in net income, including the IDRs, represents distributions declared after period-end on behalf of the general partner interest and IDRs less the allocated excess of distributions over earnings for the periods.

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 table reconciles net income to limited partners’ interest in net income:

	Three Months Ended September 30,						Nine months Ended September 30,
	2011			2010			2011			2010
Net income attributable to Martin Midstream Partners L.P.	$	5,399		$	4,636		$	21,491		$	9,482
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs		1,265			926			3,635			2,696
Distributions payable on behalf of general partner interest		345			304			1,000			884
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest		(262	)		(230	)		(643	)		(748	)
Less beneficial conversion feature		277			277			831			831
Limited partners’ interest in net income	$	3,774		$	3,359		$	16,668		$	5,819

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

The weighted average units outstanding for basic net income per unit were 19,158,334 and 19,161,403 for the three months and nine months ended September 30, 2011, respectively, and 17,700,875 and 17,466,200 for the three months and nine months ended September 30, 2010, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 4,794 and 1,663 for the three and nine months ended September 30, 2011, respectively, and 844 and 1,314 for the three and nine months ended September 30, 2010, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

(e) Goodwill and Other Intangible Assets.

The Partnership has historically performed its annual impairment testing of goodwill and indefinite-lived intangible assets as of September 30 of each year. During the third quarter of fiscal 2011, the Partnership changed the annual impairment testing date from September 30 to August 31. The Partnership believes this change, which represents a change in the method of applying an accounting principle, is preferable in the circumstances as the earlier date provides additional time prior to the Partnership’s quarter-end to complete the goodwill impairment testing and report the results in its quarterly report on Form 10-Q. A preferability letter from the Partnership’s independent registered public accounting firm regarding this change in the method of applying an accounting principle has been filed as an exhibit to this quarterly report on Form 10-Q for the quarter ended September 30, 2011.

(f) 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

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 with early adoption permitted which for the Partnership means January 1, 2012. This amended guidance will be 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, which for the Partnership means January 1, 2012. As this new guidance only requires enhanced disclosure, adoption will not impact the Partnership’s financial position or results of operations.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

(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 40.08% 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 loan facility.

In August 2011, the board of directors of the general partner of the Partnership approved aggregate investments not to exceed $8,500 in the Class A equity interests of Redbird through December 31, 2011. Redbird will utilize the investments by the Partnership to invest in Cardinal to fund projects for natural gas storage facilities other than Monroe. In 2012, the Partnership will have additional opportunities to invest in the Class A equity interests of Redbird which will be evaluated on a case by case basis to determine whether or not to undertake such additional investments.

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 loan 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, 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. The impact on first quarter depreciation expense as a result of the finalization of the purchase price allocation is accounted for retrospectively and was a reduction of $241.

On August 26, 2010, the Partnership acquired certain shore-based marine terminalling assets from Martin Resource Management for $11,700. The net book value of the acquired assets was $7,331 and was recorded in property, plant and equipment. The remaining $4,369 was recorded as a distribution to Martin Resource Management. These assets are located in Theodore, Alabama and Pascagoula, Mississippi.

Marine Equipment

On December 22, 2010, the Partnership acquired a 60,000 bbl. offshore tank barge from Martin Resource Management for a total purchase price of $17,000. The Partnership paid cash in the amount of $9,600 and assumed a note payable to a third party for $7,400. The net book value of the acquired assets was $16,805 and was recorded in property, plant, and equipment. The remaining $195 was recorded as a distribution to Martin Resource Management.

Darco Gathering System

On November 1, 2010, the Partnership, through its wholly owned subsidiary, Prism Gas, acquired approximately 20 miles of natural gas gathering pipeline and various equipment located in Harrison County, Texas. The final purchase price of approximately $25,015 was funded by borrowings under the Partnership’s credit agreement.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

The purchase price including other intangibles reflected as other assets was allocated as follows:

Property, plant and equipment		9,925
Other assets		15,090
	$	25,015

The identifiable intangible asset of $15,090 is a life of lease contract with an active producer in the Haynesville Shale and Cotton Valley sand. The contract is subject to amortization over an approximate useful life of twenty years.

Harrison Gathering System

On January 15, 2010, the Partnership, through Prism Gas Systems I, L.P. (“Prism Gas”), as 50% owner and the operator of Waskom Gas Processing Company (“Waskom”), through Waskom’s wholly-owned subsidiary Waskom Midstream LLC, acquired from Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and equipment referred to as the Harrison Gathering System. The Partnership’s share of the acquisition cost was approximately $20,000 and was recorded as an investment in an unconsolidated entity.

(4) Inventories

Components of inventories at September 30, 2011 and December 31, 2010, were as follows:

	September 30, 2011		December 31, 2010
Natural gas liquids	$	28,239	$	19,775
Sulfur		27,523		15,933
Sulfur Based Products		12,643		9,027
Lubricants		9,912		5,267
Other		2,535		2,614
	$	80,852	$	52,616

(5) Investments in Unconsolidated Entities and Joint Ventures

Prism Gas owns an unconsolidated 50% interest in Waskom, the Matagorda Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these assets are accounted for by the equity method.

In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity-method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $148 and $445 for the three and nine months ended September 30, 2011 and 2010, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated entities. The remaining unamortized excess investment relating to property and equipment was $8,458 and $8,903 at September 30, 2011 and December 31, 2010, respectively. The equity-method goodwill is not amortized; however, it is analyzed for impairment annually or when changes in circumstance indicate that a potential impairment exists. No impairment was recognized for the nine months ended September 30, 2011 or 2010.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids (“NGLs”) that are retained according to Waskom’s contracts with certain producers. The NGLs are valued at prevailing market prices. In addition, cash distributions are received and cash contributions are made to fund operating and capital requirements of Waskom.

The Partnership and Martin Resource Management formed Redbird, a natural gas storage joint venture formed to invest in Cardinal. The Partnership owns all the Class B equity interests in Redbird. Redbird owns an unconsolidated 40.08% interest in Cardinal. These assets are accounted for by the equity method.

Activity related to these investment accounts for the nine months ended September 30, 2011 and 2010 is as follows:

	Waskom			PIPE			Matagorda			Redbird			Total

Investment in unconsolidated entities, December 31, 2010	$	93,768		$	1,311		$	3,138			—		$	98,217

Distributions in kind		(9,010	)		—			—			—			(9,010	)
Contributions to unconsolidated entities:
Cash contributions (See Note 3)		—			—			—			59,319			59,319
Contributions to unconsolidated entities for operations		8,504			—			170			929			9,603
Return of investments		(1,200	)		—			(85	)		(383	)		(1,668	)
Equity in earnings:
Equity in earnings (losses) from operations		7,191			(32	)		141			98			7,398
Amortization of excess investment		(412	)		(12	)		(21	)		—			(445	)

Investment in unconsolidated entities, September 30, 2011	$	98,841		$	1,267		$	3,343		$	59,963		$	163,414

	Waskom			PIPE			Matagorda			Redbird		Total

Investment in unconsolidated entities, December 31, 2009	$	75,844		$	1,401		$	3,337			—	$	80,582
											—
Distributions in kind		(7,524	)		—			—			—		(7,524	)
Contributions to unconsolidated entities:											—
Cash contributions (See Note 3)		20,110			—			—			—		20,110
Contributions to (distributions from) unconsolidated entities for operations		(748	)		120			—			—		(628	)
Return of investments		(2,100	)		(30	)		(300	)		—		(2,430	)
Equity in earnings:											—
Equity in earnings (losses) from operations		7,945			(180	)		148			—		7,913
Amortization of excess investment		(412	)		(11	)		(21	)		—		(444	)

Investment in unconsolidated entities, September 30, 2010	$	93,115		$	1,300		$	3,164		$	—	$	97,579

Select 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		Revenues		Net Income		Revenues		Net Income
2011
Waskom	$	136,493	$	118,479	$	29,508	$	3,808	$	95,086	$	14,382

	As of December 31
2010
Waskom	$	128,250	$	108,669	$	32,154	$	5,123	$	60,808	$	9,714

As of September 30, 2011 and December 31, 2010, the amount of the Partnership’s consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity-method investees is $45,793 and $36,964, respectively. There are no material restrictions to transfer funds in the form of dividends, loans or advances related to the equity-method investees.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

As of September 30, 2011 and December 31, 2010, the Partnership’s interest in cash of the unconsolidated equity-method investees was $839 and $1,145, respectively.

(6) 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 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. As a result of its effectiveness assessment at September 30, 2011, the Partnership believes certain hedge contracts will continue to be effective in offsetting changes in cash flow or fair value attributable to the hedged risk.

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.

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 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. The Partnership has entered into hedging transactions through 2012 to protect a portion of its commodity 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 volatility in commodity markets, the Partnership is unable to predict the amount of ineffectiveness each period, including the loss of hedge accounting, which is determined on a derivative by derivative basis. This may result, and has resulted, in increased volatility in the Partnership’s financial results. Factors that have and may continue to lead to ineffectiveness and unrealized gains and losses on derivative contracts include: a substantial fluctuation in energy prices, the number of derivatives the Partnership holds and significant weather events that have affected energy production. The number of instances in which the Partnership has discontinued hedge accounting for specific hedges is primarily due to those reasons. However, even though these derivatives may not qualify for hedge accounting, the Partnership continues to hold the instruments as it believes they continue to afford the Partnership opportunities to manage commodity risk exposure.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

As of September 30, 2011 and 2010, the Partnership has both derivative instruments qualifying for hedge accounting with fair value changes being recorded in AOCI as a component of partners’ capital and derivative instruments not designated as hedges being marked to market with all market value adjustments being recorded in earnings.

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2011 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of September 30, 2011, the remaining term of the contracts extend no later than December 2012, with no single contract longer than one year. For the three months and nine months ended September 30, 2011 and 2010, 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.

Transaction Type	Total Volume Per Month	Pricing Terms	Remaining Terms of Contracts	Fair Value

Mark to Market Derivatives::

Crude Oil Swap	2,000 BBL	Fixed price of $91.20 settled against WTI NYMEX average monthly closings	October 2011 to December 2011		67
Total commodity swaps not designated as hedging instruments				$	67

Cash Flow Hedges:

Natural Gas Swap	10,000 Mmbtu	Fixed price of $6.1250 settled against IF_ANR_LA first of the month posting	October 2011 to December 2011		71

Natural Gas Swap	20,000 Mmbtu	Fixed price of $4.3225 settled against IF_ANR_LA first of the month posting	October 2011 to December 2011		35

Natural Gasoline Swap	2,000 BBL	Fixed price of $87.10 settled against WTI NYMEX average monthly closings	October 2011 to December 2011		42

Natural Gasoline Swap	1,000 BBL	Fixed price of $88.85 settled against WTI NYMEX average monthly closings	October 2011 to December 2011		26

Natural Gasoline Swap	1,000 BBL	Fixed price of $2.383 settled against Mont Belvieu Non-TET OPIS Average	October 2011 to December 2011		48

Crude Oil Swap	1,000 BBL	Fixed price of $101.90 settled against WTI NYMEX average monthly closings	October 2011 to December 2011		65

Natural Gas Swap	10,000 Mmbtu	Fixed price of $4.8700 settled against IF_ANR_LA first of the month posting	January 2012 to December 2012		81

Natural Gas Swap	20,000 Mmbtu	Fixed price of $4.9600 settled against IF_ANR_LA first of the month posting	January 2012 to December 2012		184

Natural Gasoline Swap	1,000 BBL	Fixed price of $90.20 settled against WTI NYMEX average monthly closings	January 2012 to December 2012		112

Natural Gasoline Swap	1,000 BBL	Fixed price of $2.340 settled against Mont Belvieu Non-TET OPIS Average	January 2012 to December 2012		160

Crude Oil Swap	2,000 BBL	Fixed price of $88.63 settled against WTI NYMEX average monthly closings	January 2012 to December 2012		187

Total commodity swaps designated as hedging instruments				$	1,011

Total net fair value of commodity derivatives				$	1,078

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

Based on estimated volumes, as of September 30, 2011, the Partnership had hedged approximately 49% and 36% of its commodity risk by volume for 2011 and 2012, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.

The Partnership’s credit exposure related to commodity cash flow hedges is represented by the positive fair value of contracts to the Partnership at September 30, 2011. These outstanding contracts expose the Partnership to credit loss in the event of nonperformance by the counterparties to the agreements. The Partnership has incurred no losses associated with counterparty nonperformance on derivative contracts.

On all transactions where the Partnership is exposed to a counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Partnership has agreements with four counterparties containing collateral provisions. Based on those current agreements, cash deposits are required to be posted whenever the net fair value of derivatives associated with the individual counterparty exceed a specific threshold. If this threshold is exceeded, cash is posted by the Partnership if the value of derivatives is a liability to the Partnership. As of September 30, 2011, the Partnership has no cash collateral deposits posted with counterparties.

The Partnership’s principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of the Partnership’s natural gas and NGL sales are made at market-based prices. The Partnership’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Partnership.

(b) Impact of Commodity Cash Flow Hedges

Crude Oil. For the three months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased crude revenue by $361 and $17, respectively. For the nine months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased crude revenue by $658 and $270, respectively. As of September 30, 2011 an unrealized derivative fair value gain of $428, related to current and terminated cash flow hedges of crude oil price risk, was recorded in AOCI. Fair value gains of $247 and $181 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at September 30, 2011, adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

Natural Gas. For the three months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased gas revenue by $72 and $152, respectively. For the nine months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased gas revenue $215 and $409, respectively. As of September 30, 2011 an unrealized derivative fair value gain of $359 related to cash flow hedges of natural gas was recorded in AOCI. Fair value gains of $100 and $259 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

Natural Gas Liquids. For the three months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased natural gas liquids revenue by $236 and $41, respectively. For the nine months ended September 30, 2011 and 2010, net gains and losses on swap hedge contracts increased natural gas liquids revenue $458 and $230, respectively. As of September 30, 2011 an unrealized derivative fair value gain of $590 related to cash flow hedges of natural gas was recorded in AOCI. Fair value gains of $329 and $260 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

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.

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 and term loan credit facilities. 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 10. 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.

In March 2010, in connection with a pay down of the Partnership’s revolving credit facility, the Partnership terminated all of its existing cash flow hedge agreements with an aggregate notional amount of $140,000, which it had entered to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. Termination fees of $3,850 were paid on the early extinguishment of all interest rate swap agreements in March 2010. The amounts remaining in AOCI were reclassified into interest expense over the original term of the terminated interest rate derivatives.

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. The Partnership recognized increases (decreases) in interest expense of $(957) and $2,567 for the three and nine months ended September 30, 2010, 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.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

(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, 2011		December 31,, 2010		Balance Sheet Location	September 30, 2011		December 31, 2010
Derivatives designated as hedging instruments
	Current:					Current:
Interest rate contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	—
Commodity contracts	Fair value of derivatives		867		201	Fair value of derivatives		—		230
			867		201			—		230
	Non-current:					Non-current:
Interest rate contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		—
Commodity contracts	Fair value of derivatives		144		—	Fair value of derivatives		—		171
			144		—			—		171
Total derivatives designated as hedging instruments		$	1,011	$	201		$	—	$	401


Derivatives not designated as hedging instruments
	Current:					Current:
Interest rate contracts	Fair value of derivatives	$	—	$	1,941	Fair value of derivatives	$	—	$	—
Commodity contracts	Fair value of derivatives		67		—	Fair value of derivatives		—		51
			67		1,941			—		51
	Non-current:					Non-current:
Interest rate contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		3,930
Commodity contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		—
			—		—			—		3,930
Total derivatives not designated as hedging instruments		$	67	$	1,941		$	—	$	3,981

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2011

(Unaudited)

Effect of Derivative Instruments on the Consolidated Statement of Operations For the Three Months Ended September 30, 2011 and 2010
	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
		2011		2010			2011		2010				2011		2010
Derivatives designated as hedging instruments
Interest rate contracts	$	—	$	—	Interest Expense	$	—	$	(606	)	Interest Expense	$	—	$	—
Commodity contracts		1,295		71	Natural Gas Services Revenues		500		205		Natural Gas Services Revenues		38		18

Total derivatives designated as hedging instruments	$	1,295	$	71		$	500	$	(401	)		$	38	$	18

	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2011		2010
Derivatives not designated as hedging instruments
Interest rate contracts	Interest Expense	$	3,244	$	1,563
Commodity contracts	Natural Gas Services Revenues		131		(13	)
Total derivatives not designated as hedging instruments		$	3,375	$	1,550