8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of report (date of earliest event reported): August 21, 2012

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of Registrant as specified in its charter)

DELAWARE (State of incorporation or organization)	000-50056 (Commission file number)		05-0527861 (I.R.S. employer identification number)
4200 STONE ROAD
KILGORE, TEXAS (Address of principal executive offices)		75662 (Zip code)

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

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events

                On July 31, 2012, Martin Midstream Partners L.P. (the “Partnership”) completed the previously announced 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 certain other natural gas gathering and processing assets also owned by the Partnership, to CenterPoint Energy Field Services, LLC, an indirect, wholly-owned subsidiary of CenterPoint Energy Inc.  In consideration of the sale of these assets, the Partnership received net cash proceeds of $273.3 million subject to certain purchase price adjustments.

Additionally, the Partnership has reached agreement with a private investor group to sell its interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) for $2.0 million in cash.  This sale is expected to be completed in the third quarter of 2012.

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

For reporting purposes, the results of operations of the Prism Assets are included as income from discontinued operations in this Current Report on Form 8-K.

Capitalized terms used in Exhibits 99.1, 99.2, and 99.3, hereto shall have the meanings given to them in our original Annual Report on Form 10-K for the year ended December 31, 2011, filed by the Partnership with the Securities and Exchange Commission on March 5, 2012 (the “December 2011 Form 10-K”).

The December 2011 Form 10-K is revised by this Current Report on Form 8-K to reflect the presentation of the Prism Assets in discontinued operations as follows:

The Selected Financial Data of the Partnership included herein as Exhibit 99.1 supersedes Part II, Item 6 in the December 2011 Form 10-K;

The Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) of the Partnership included herein as Exhibit 99.2 supersedes Part II, Item 7 in the December 2011 Form 10-K; and

The Financial Statements and Supplementary Data included herein as Exhibit 99.3 supersedes Part II, Item 8 in the December 2011 Form 10-K.

Other than the revisions noted above, we have made no attempt to revise or update our December 2011 Form 10-K for events occurring after the original filing of the December 2011 Form 10-K.

This Current Report on Form 8-K should be read in conjunction with the December 2011 Form 10-K.  Any references herein to Part II, Item 6 of the December 2011 Form 10-K refer to Exhibit 99.1., any references herein to Part II, Item 7 of the December 2011 Form 10-K refer to Exhibit 99.2, and any references herein to Part II, Item 8 of the December 2011 Form 10-K refer to Exhibit 99.3.  From and after the date of this Current Report on Form 8-K, future references to the Partnership’s historical financial statements and MD&A for period ended December 31, 2011 should be made to this Current Report.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

23.1Consent of Independent Registered Public Accounting Firm

99.1Part II, Item 6.  Selected Financial Data

99.2Part II, Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations

99.3Part II, Item 8.  Financial Statements and Supplementary Data

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 hereunto duly authorized.

	MARTIN MIDSTREAM PARTNERS L.P. By: Martin Midstream GP LLC, Its General Partner
Date August 21, 2012		By: /s/ Robert D. Bondurant
		Robert D. Bondurant,
		Executive Vice President and Chief Financial Officer

INDEX TO EXHIBITS

23.1 Consent of Independent Registered Public Accounting Firm

99.1 Part II, Item 6.  Selected Financial Data, updated

99.2 Part II, Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations, updated

99.3 Part II, Item 8.  Financial Statements and Supplementary Data, updated

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Martin Midstream GP LLC:

We consent to the incorporation by reference in the registration statements (No. 333-148146, No. 333-117023 and No. 333-171028) on Form S-3 and (No. 333-140152) on Form S-8 of Martin Midstream Partners L.P. of our reports dated March 5, 2012 (except for the updated disclosures and reclassification of gas gathering and processing assets as held for sale and discontinued operations for all periods presented, as described in notes 2(a) and 6, as to which the date is August 21, 2012), with respect to the consolidated balance sheets of Martin Midstream Partners L.P. as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2011 and the effectiveness of internal control over financial reporting as of December 31, 2011, which reports appear in this Current Report on Form 8-K of Martin Midstream Partners L.P.

KPMG LLP

Shreveport, Louisiana

August 21, 2012

EX-99.1

Exhibit 99.1

           As further discussed in notes 2(a) and 6 to our consolidated financial statements herein, our consolidated financial statements for all periods presented herein have been updated to reclassify the assets and related liabilities of our natural gas gathering and processing business as held for sale and the related results of operations as discontinued operations.  This filing includes updates only to the portions of Item 6, Item 7 and Item 8 of the December 31, 2011 Form 10-K that specifically relate to the reclassification of the assets and related liabilities of our natural gas gathering and processing business as held for sale and the related results of operations as discontinued operations and does not otherwise modify or update any other disclosures set forth in the December 31, 2011 Form 10-K.

Item 6.                      Selected Financial Data

The following table sets forth selected financial data and other operating data of Martin Midstream Partners L.P. for the years ended December 31, 2011, 2010, 2009, 2008 and 2007  is derived from the audited consolidated financial statements of Martin Midstream Partners L.P.

The following selected financial data are qualified by reference to and should be read in conjunction with our Consolidated and Combined Financial Statements and Notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this document.

		2011			2010			2009			2008			2007
	(Dollars in thousands, except per unit amounts)
Income Statement Data:
Revenues	$	1,115,735		$	799,641		$	591,244		$	1,095,149		$	702,000
Cost of product sold		885,645			594,327			398,107			878,586			524,650
Operating expenses		134,734			111,923			111,901			121,343			100,187
Selling, general, and administrative		17,430			15,111			14,551			15,305			10,202
Depreciation and amortization		39,445			36,204			35,543			31,348			23,424
Total costs and expenses		1,077,254			757,565			560,102			1,046,582			658,463
Other operating income		1,326			228			6,025			209			707
Operating income		39,807			42,304			37,167			48,776			44,244
Equity in earnings of unconsolidated entities		124			—			—			—			—
Interest expense		(24,518	)		(33,716	)		(18,995	)		(21,433	)		(15,125	)
Other, net		233			287			327			798			374
Income before income taxes		15,646			8,875			18,499			28,141			29,493
Income taxes		696			(914	)		(1,564	)		(1,399	)		(5,488	)
Income from continuing operations		14,950			7,961			16,935			26,742			24,005
Income from discontinued operations, net of tax		9,392			8,061			5,268			16,816			8,556
Net income	$	24,342		$	16,022		$	22,203		$	43,558		$	32,561
Net income per limited partner unit – continuing operations	$	0.57		$	0.31		$	0.87		$	1.65		$	1.09
Net income per limited partner unit – discontinued operations		0.35			0.32			0.30			1.07			0.58
Net income per limited partner unit	$	0.92		$	0.63		$	1.17		$	2.72		$	1.67
Weighted average limited partner units		19,545,427			17,525,089			14,680,807			14,529,826			14,018,799
Balance Sheet Data (at Period End):
Total assets	$	949,109		$	785,478		$	685,939		$	706,322		$	656,604
Due to affiliates		18,485			6,957			13,810			23,085			17,119
Long-term debt		458,941			372,862			304,372			295,000			225,000
Partner’s capital (owner’s equity)		285,616			274,806			264,951			246,379			246,765
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	86,870		$	37,518		$	47,592		$	86,340		$	61,209
Investing activities		(167,335	)		(76,728	)		(14,675	)		(106,621	)		(130,295	)
Financing activities		69,351			44,634			(34,944	)		24,151			69,896
Other Financial Data:
Maintenance capital expenditures	$	10,947		$	4,653		$	7,601		$	17,998		$	11,955
Expansion capital expenditures		63,048			12,367			28,572			89,435			109,474
Total capital expenditures	$	73,995		$	17,020		$	36,173		$	107,433		$	121,429
Cash dividends per common unit (in dollars)	$	3.05		$	3.00		$	3.00		$	2.91		$	2.60

 We acquired the assets of Cross from Martin Resource Management in November 2009.  The acquisition of the Cross assets was considered a transfer of net assets between entities under common control.  The acquisition of the Cross assets and increase in partners’ capital for the common and subordinated units issued in November 2009 are recorded at amounts based on the historical carrying value of the Cross assets at that date, and we are required to revise our historical financial statements to include the activities of the Cross assets as of the date of common control.  Our historical financial statements for 2007, 2008 and the period January 1, 2009 through November 24, 2009, have been revised to reflect the financial position, cash flows and results of operations attributable to the Cross assets as if we owned the Cross assets for these periods.

The following tables present our historical results of operations, the effect of including the results of the Cross assets, which are included in our terminalling and storage segment and the revised total amounts included in our consolidated financial statements:

1

	Year Ended December 31, 2009
	Historical Martin Midstream Partners LP			Cross Assets Results			Revised Total
	(Dollars in thousands, except per unit amounts)
Revenues	$	562,635		$	28,609		$	591,244
Costs and expenses:
Cost of products sold (excluding depreciation and amortization)		398,107			—			398,107
Operating expenses		93,140			18,761			111,901
Selling, general and administrative		12,866			1,685			14,551
Depreciation and amortization		31,180			4,363			35,543
Total costs and expenses		535,293			24,809			560,102
Other operating income		6,172			(147	)		6,025
Operating income		33,514			3,653			37,167
Interest expense		(18,124	)		(871	)		(18,995	)
Other, net		304			23			327
Net income before taxes		15,694			2,805			18,499
Income tax benefit (expense)		(423	)		( 1,141	)		(1,564	)
Income from continuing operations		15,271			1,664			16,935
Income from discontinued operations, net of tax		5,268			—			5,268
Net income	$	20,539		$	1,664		$	22,203

	Year Ended December 31, 2008
	Historical Martin Midstream Partners LP			Cross Assets Results			Revised Total
	(Dollars in thousands, except per unit amounts)
Revenues	$	1,062,663		$	32,486		$	1,095,149
Costs and expenses:
Cost of products sold (excluding depreciation and amortization)		878,586			—			878,586
Operating expenses		97,428			23,915			121,343
Selling, general and administrative		13,182			2,123			15,305
Depreciation and amortization		27,673			3,675			31,348
Total costs and expenses		1,016,869			29,713			1,046,582
Other operating income		209			—			209
Operating income		46,003			2,773			48,776
Interest expense		(19,777	)		(1,656	)		(21,433	)
Other, net		480			318			798
Net income before taxes		26,706			1,435			28,141
Income tax benefit (expense)		( 712	)		( 687	)		(1,399	)
Income from continuing operations		25,994			748			26,742
Income from discontinued operations, net of tax		16,816			—			16,816
Net income	$	42,810		$	748		$	43,558

	Year Ended December 31, 2007
	Historical Martin Midstream Partners LP			Cross Assets Results			Revised Total
	(Dollars in thousands, except per unit amounts)
Revenues	$	663,495		$	38,505		$	702,000
Costs and expenses:
Cost of products sold (excluding depreciation and amortization)		524,650			—			524,650
Operating expenses		79,555			20,632			100,187
Selling, general and administrative		8,269			1,933			10,202
Depreciation and amortization		20,543			2,881			23,424
Total costs and expenses		633,017			25,446			658,463
Other operating income		707			—			707
Operating income		31,185			13,059			44,244
Interest expense		(14,533	)		(592	)		(15,125	)
Other, net		268			106			374
Net income before taxes		16,920			12,573			29,493
Income tax benefit (expense)		( 537	)		( 4,951	)		(5,488	)
Income from continuing operations		16,383			7,622			24,005
Income from discontinued operations, net of tax		8,556			—			8,556
Net income	$	24,939		$	7,622		$	32,561

EX-99.2

Exhibit 99.2

As further discussed in notes 2(a) and 6 to our consolidated financial statements herein, our consolidated financial statements for all periods presented herein have been updated to reclassify the assets and related liabilities of our natural gas gathering and processing business as held for sale and the related results of operations as discontinued operations.  This filing includes updates only to the portions of Item 6, Item 7 and Item 8 of the December 31, 2011 Form 10-K that specifically relate to the reclassification of the assets and related liabilities of our natural gas gathering and processing business as held for sale and the related results of operations as discontinued operations and does not otherwise modify or update any other disclosures set forth in the December 31, 2011 Form 10-K.

Item 7.                      Management’s Discussion and Analysis of Financial Condition and Results of Operations

References in this annual report to “we,” “ours,” “us” or like terms when used in a historical context refer to the assets and operations of Martin Resource Management’s business contributed to us in connection with our initial public offering on November 6, 2002.  References in this annual report to “Martin Resource Management” refer to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires.  You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and the notes thereto included elsewhere in this annual report.  For more detailed information regarding the basis for presentation for the following information, you should read the notes to the consolidated financial statements included elsewhere in this annual report.

Forward-Looking Statements

This annual report on Form 10-K 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 annual 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), 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 above in “Item 1A. Risk Factors − Risks Related to our Business”.

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 products 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 generate the majority of our cash flow from fee-based contracts with these customers. Our location in the Gulf Coast region of the United States provides us strategic access to 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 Corporation (“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.  As of March 5, 2012, 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 and incentive distribution rights in us.

The historical operation of our business segments by Martin Resource Management provides us with several decades of experience and a demonstrated track record of customer service across our operations.  Our current lines of business have been developed and systematically integrated over this period of more than 60 years, including natural gas services (1950s); sulfur (1960s); marine transportation (late 1980s) and terminalling and storage (early 1990s).  This development of a diversified and integrated set of assets and operations has produced a complementary portfolio of midstream services that facilitates the maintenance of long-term customer relationships and encourages the development of new customer relationships.

2011 Developments and Subsequent Events

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 2010 and 2011, the financial markets have been available to us.  As such, we were able to issue senior unsecured long-term debt in the first quarter 2010 and equity in both the first and third quarters of 2010.  Additionally, 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 was subsequently refinanced in April 2011 and upsized in April and December 2011. 

1

               Conditions in our industry continued to be challenging in 2011.  For example:

·   Several gas producers in our areas of operation have reduced drilling activity as compared to their previous levels of activity, demonstrating a bias toward newly found shale plays in other areas.

·   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.  In October 2010, the United States Government lifted the moratorium on deep water permitting and drilling.  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. 

·   There has been a decline in the demand for certain marine transportation services based on decreased refinery production resulting in an oversupply of equipment.  This was partially offset in 2010 by the marine transportation services required in the efforts to clean up the BP oil spill in the Gulf of Mexico.   

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 2011, we have experienced positive changing market dynamics in certain segments, including activity associated with the rapidly developing basins such as the Eagle Ford shale. 

Recent Acquisitions

Redbird.  On May 31, 2011, we acquired all of the Class B equity interests in Redbird Gas Storage LLC (“Redbird”) for approximately $59.3 million.  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 owned an unconsolidated 40.08% interest in Cardinal at December 31, 2011.  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.  As of March 5, 2012, Redbird’s ownership interest in Cardinal increased to 40.23%.   

Other Developments

Conversion of Subordinated Units.  On November 25, 2011, the 889,444 subordinated units held indirectly by Martin Resource Management automatically converted pursuant to their terms on a one-for-one basis into common units of the Partnership Public Offerings.

On February 9, 2011, we completed a public offering of 1,874,500 common units, resulting in net proceeds of $70.3 million, after payment of underwriters’ discounts, commissions and offering expenses.  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.  The net proceeds were used to pay down revolving debt under our credit facility.

Debt Financing Activities.  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, (iv) adjust the financial covenants, (v) increase the maximum allowable amount of additional outstanding indebtedness of the borrower and the Partnership and certain of its subsidiaries, and (vi) adjust the commitment fee incurred on the unused portion of the loan facility.

For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Credit Facility” within this Item.

Subsequent Events

Public Offering.  On January 25, 2012, we completed a public offering of 2,645,000 common units, resulting in net proceeds of $91.4 million after the payment of underwriters’ discounts, commissions and offering expenses.  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, we used all the net proceeds to reduce outstanding indebtedness.

Quarterly Distribution.  On January 26, 2012, we declared a quarterly cash distribution of $0.7625 per common unit for the fourth quarter of 2011, or $3.05 per common unit on an annualized basis, to be paid on February 14, 2012 to unitholders of record as of February 7, 2012.

2

Disposition of Natural Gas Gathering Assets.  On June 18, 2012, we and a subsidiary of CenterPoint Energy Inc. (NYSE: CNP), (“CenterPoint”) entered into a definitive agreement under which CenterPoint would acquire our East Texas and Northwest Louisiana natural gas gathering and processing assets owned by Prism Gas, and other natural gas gathering and processing assets also owned by us, for cash in a transaction valued at approximately $275.0 million excluding any transaction costs and purchase price adjustments.  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.  On July 31, 2012, we completed the sale of our East Texas and Northwest Louisiana natural gas gathering and processing assets for net cash proceeds of $273.3 million.

Additionally, during the second quarter of 2012, we reached agreement with a private investor group to sell our interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) for $2.0 million in cash.  This sale is expected to be completed in the third quarter of 2012.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated 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. However, we have described below the critical accounting policies that we believe could impact our consolidated financial statements most significantly.

You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements contained in this annual report on Form 10-K.  Some of the more significant estimates in these financial statements include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units as it relates to our annual goodwill evaluation.

Derivatives

All derivatives and hedging instruments are included on the balance sheet as an asset or 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 other comprehensive income until such time as the hedged item is recognized in earnings. Our hedging policy allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges or hedges that become ineffective are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2011, we have designated a portion of our derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of partners’ capital.

Product Exchanges

We enter into product exchange agreements with third parties whereby we agree to exchange natural gas liquids (“NGLs”) and sulfur with third parties. We record the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out method.  Revenue and costs related to product exchanges are recorded on a gross basis.

Revenue Recognition

Revenue for our four operating segments is recognized as follows:

Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through our terminals at the contracted rate.   For our tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, we recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.

Sulfur services – Revenue is recognized when the customer takes title to the product at our plant or the customer facility.

Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip. For time charters, revenue is recognized based on a per day rate.

Equity Method Investments

We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. This goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment evaluation.No portion of the net income from these entities is included in our operating income.

At December 31, 2011, we owned an unconsolidated 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”).  We own all of the Class B equity interests in Redbird.  Redbird, as of December 31, 2011, owned a 40.08% interest in Cardinal Gas Storage Partners, LLC.  Each of these interests is accounted for under the equity method of accounting.

3

Goodwill

Goodwill is subject to a fair-value based impairment test on an annual basis. We are required to identify our reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. We are required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit; we would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.

All four of our “reporting units”, terminalling and storage, natural gas services, sulfur services and marine transportation, contain goodwill.

We have historically performed our annual impairment testing of goodwill and indefinite-lived intangible assets as of September 30 of each year.  During the third quarter of fiscal 2011, we changed the annual impairment testing date from September 30 to August 31.  We believe 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 our quarter-end to complete the goodwill impairment testing and report the results in our quarterly report on Form 10-Q.  A preferability letter from our independent registered public accounting firm regarding this change in the method of applying an accounting principle has been filed as an exhibit to our quarterly report on Form 10-Q for the quarter ended September 30, 2011.

We performed the annual impairment test as of August 31, 2011, and we determined the fair value in each reporting unit based on the weighted average of three valuation techniques: (i) the discounted cash flow method, (ii) the guideline public company method, and (iii) the guideline transaction method.

We have performed the annual impairment tests as of August 31, 2011, September 30, 2010, and September 30, 2009, and we have determined fair value in each reporting unit based on the weighted average of three valuation techniques: (i) the discounted cash flow method, (ii) the guideline public company method, and (iii) the guideline transaction method.  At August 31, 2011, September 30, 2010, and September 30, 2009, the estimated fair value of each of our four reporting units was in excess of its carrying value resulting in no impairment.

No such triggering events occurred that would cause us to perform an impairment test at either December 31, 2011 or 2010.

Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.

Environmental Liabilities and Litigation

We have not historically experienced circumstances requiring us to account for environmental remediation obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other related environmental studies that we may elect to perform. We would record changes to our estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related eventual liability.

Because the outcomes of both contingent liabilities and litigation are difficult to predict, when accounting for these situations, significant management judgment is required. Amounts paid for contingent liabilities and litigation have not had a materially adverse effect on our operations or financial condition, and we do not anticipate they will in the future.

Allowance for Doubtful Accounts

In evaluating the collectability of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and historical collection experience. Based on these assessments, we record specific and general reserves for bad debts to reduce the related receivables to the amount we ultimately expect to collect from customers.

Our management closely monitors potentially uncollectible accounts. Estimates of uncollectible amounts are revised each period, and changes are recorded in the period they become known. If there is a deterioration of a major customer’s creditworthiness or actual defaults are higher than the historical experience, management’s estimates of the recoverability of amounts due us could potentially be adversely affected. These charges have not had a materially adverse effect on our operations or financial condition.

Asset Retirement Obligation

We recognize and measure our asset and conditional asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset and based upon the estimate of the cost to settle the obligation at its anticipated future date. The obligation is accreted to its estimated future value and the asset retirement cost is depreciated over the estimated life of the asset.

Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Such costs could differ significantly when they are incurred. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates due to surface repair, and labor and material costs, revisions to estimated inflation rates and changes in the estimated timing of abandonment. For example, we do not have access to natural gas reserves information related to our gathering systems to estimate when abandonment will occur.

Our Relationship with Martin Resource Management

Martin Resource Management directs our business operations through its ownership and control of our general partner and under an omnibus agreement.  In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2011, 2010 and 2009, the Conflicts Committee of our general partner approved reimbursement amounts of $4.8 million, $3.8 million and $3.5 million, respectively, reflecting our allocable share of such expenses.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

We are required 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.  Martin Resource Management also licenses certain of its trademarks and trade names to us under this omnibus agreement.

4

We are both an important supplier to and customer of Martin Resource Management.  Among other things, we sell sulfuric acid and provide marine transportation and terminalling and storage services to Martin Resource Management.  We purchase land transportation services, underground storage services, sulfuric acid and marine fuel from Martin Resource Management.  All of these services and goods are purchased and sold pursuant to the terms of a number of agreements between us and Martin Resource Management.

For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence – Agreements.”

Results of Operations

The results of operations for the twelve months ended December 31, 2011, 2010 and 2009 have been derived from our consolidated 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 twelve months ended December 31, 2011, 2010 and 2009.

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

	Operating Revenues		Revenues Intersegment Eliminations			Operating Revenues  after Eliminations		Operating Income (loss)			Operating Income Intersegment Eliminations			Operating Income (loss)  after Eliminations
	(In thousands)
Year ended December 31, 2011:
Terminalling and storage	$	156,420	$	(4,414	)	$	152,006	$	14,022		$	(948	)	$	13,074
Natural gas services		611,749		—			611,749		6,267			1,220			7,487
Sulfur services		275,044		—			275,044		27,651			6,944			34,595
Marine transportation		83,971		(7,035	)		76,936		731			(7,216	)		(6,485	)
Indirect selling, general and administrative		—		—			—		(8,864	)		—			(8,864	)
Total	$	1,127,184	$	(11,449	)	$	1,115,735	$	39,807		$	—		$	39,807
Year ended December 31, 2010:
Terminalling and storage	$	119,270	$	(4,354	)	$	114,916	$	16,032		$	(1,776	)	$	14,256
Natural gas services		442,005		—			442,005		6,780			964			7,744
Sulfur services		165,078		—			165,078		15,886			4,280			20,166
Marine transportation		82,635		(4,993	)		77,642		9,992			(3,468	)		6,524
Indirect selling, general and administrative		—		—			—		(6,386	)		—			(6,386	)
Total	$	808,988	$	(9,347	)	$	799,641	$	42,304		$	—		$	42,304
Year ended December 31, 2009:
Terminalling and storage	$	109,513	$	(4,219	)	$	105,294	$	20,231		$	(2,332	)	$	17,899
Natural gas services		337,848		(7	)		337,841		7,627			786			8,413
Sulfur services		79,631		(2	)		79,629		9,575			4,201			13,776
Marine transportation		72,103		(3,623	)		68,480		5,811			(2,655	)		3,156
Indirect selling, general and administrative		—		—			—		(6,077	)		—			(6,077	)
Total	$	599,095	$	(7,851	)	$	591,244	$	37,167		$	—		$	37,167

5

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.

Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

Our total revenues before eliminations were $1,127.2 million for the year ended December 31, 2011 compared to $809.0 million for the year ended December 31, 2010, an increase of $318.2 million, or 39%.  Our operating income before eliminations was $39.8 million for the year ended December 31, 2011 compared to $42.3 million for the year ended December 31, 2010, a decrease of $2.5 million, or 6%.

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.

	Years Ended December 31,
		2011			2010
	(In thousands)
Revenues:
Services	$	81,697		$	71,471
Products		74,723			47,799
Total Revenues		156,420			119,270
Cost of products sold		70,601			44,549
Operating expenses		52,041			41,857
Selling, general and administrative expenses		242			426
Depreciation and amortization		18,983			16,650
		14,553			15,788
Other operating income (loss)		(531	)		244
Operating income	$	14,022		$	16,032

Revenues.  Our terminalling and storage revenues increased $37.2 million, or 31%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  Of the increase in total revenues, $10.2 million is attributable to services revenue and $26.9 million pertains to product revenues.  The increase in services revenue of $10.2 million is primarily related to the acquisition of certain terminalling assets from Martin Resource Management in February 2011.  Product revenue increased $26.9 million compared to the prior year, primarily due to the conversion of consigned product delivery agreements with two of our customers to buy/sell product delivery agreements of $22.8 million.  The remaining $4.1 million of the increase was due to increases in average selling prices at our Mega Lubricants facility.

Cost of products sold.  Our cost of products sold increased $26.1 million, or 58% for the year ended December 31, 2011 compared to the year ended December 31, 2010.  Of this increase, $20.6 million was primarily due to the conversion of consigned product delivery agreements with two of our customers.  The remaining increase was due to a $3.9 million increase in our average purchase price of products at our Mega Lubricants facility and $1.5 million of additional marine freight related to the acquisition of certain terminalling assets from Martin Resource Management in February 2011.

Operating expenses.  Operating expenses increased $10.2 million, or 24%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  Of this increase, $5.1 million was due primarily to operating expenses associated with the acquisition of certain terminalling assets from Martin Resource Management in February 2011.  Additionally, operating expenses associated with our Cross terminalling assets increased $1.6 million, primarily due to $0.7 million related to labor and burden, $0.4 million related to repairs and maintenance, and $0.3 million associated with increased materials and supply expense.  The remaining balance of $3.5 million pertains to increases in various areas of operations including $0.9 million related to a new pipeline lease in November 2011 and increases in operating expenses at our specialty terminals of $2.1, of which $0.4 million was for the deductible accrued for expenses associated with the Stanolind tank fire on September 11, 2011.

Selling, general and administrative expenses.Selling, general and administrative expenses remained relatively consistent for the year ended December 31, 2011 compared to the year ended December 31, 2010.

Depreciation and amortization.  Depreciation and amortization increased $2.3 million, or 14%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  Of the increase $1.5 million relates to additional depreciation expense associated with the acquisition of certain terminalling assets from Martin Resource Management in February 2011.  The balance of the increase was a result of capital expenditures made in the past 12 months.

Other operating income (loss). Other operating income for the year ended December 31, 2011, primarily consists of a loss of $0.7 million on the disposition of certain property, plant and equipment at our terminal located in Corpus Christi, TX.  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.

In summary, terminalling and storage operating income decreased $2.0 million, or 13%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.

6

Natural Gas Services Segment

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

	Years Ended December 31,
	2011		2010
	(In thousands)
Revenues	$	611,749	$	442,005
Cost of products sold		600,034		428,843
Operating Expenses		2,994		3,210
Selling, general and administrative expenses		1,876		2,581
Depreciation and amortization		578		571
		6,267		6,800
Other operating income (loss)		—		(20	)
Operating income	$	6,267	$	6,780
NGLs Volumes (Bbls)		7,866		6,997
Equity in Earnings of Unconsolidated Entities	$	124	$	—

Revenues. Our natural gas services revenues increased $169.7 million, or 38%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  During 2011, our NGL average sales price per barrel increased $14.60, or 23%, compared to the same period in 2010.  NGL sales volumes increased 12% compared to the same period of 2010.

Costs of product sold.  Our cost of products increased $171.2 million, or 40%, for the year ended December 31, 2011 compared to the same period in 2010.  The increase in NGL revenues was slightly lower than our increase in NGL cost of products sold as our NGL margins fell $0.39 per barrel, or 21%.

Operating expenses.  Operating expenses decreased $0.2 million, or 7% for the year ended December 31, 2011 compared to the same period of 2010 primarily as a result of decreased pipeline maintenance expenses.      

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased $0.7 million, or 27%, for the year ended December 31, 2011 compared to the same period of 2010.  This decrease was primarily a result of the write-off of an uncollectible customer receivable of $0.7 million.

Depreciation and amortization. Depreciation and amortization remained consistent for the year ended December 31, 2011 compared to the same period of 2010.

In summary, our natural gas services operating income decreased $0.5 million, or 8%, for the year ended December 31, 2011, compared to the year ended December 31, 2010.

7

Sulfur Services Segment

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

	Years Ended December 31,
	2011		2010
	(In thousands)
Revenues:
Services	$	11,400	$	—
Products		263,644		165,078
Total revenues		275,044		165,078
Cost of products sold		220,059		122,483
Operating expenses		19,328		17,013
Selling, general and administrative expenses		3,361		3,422
Depreciation and amortization		6,725		6,262
		25,571		15,898
Other operating income(loss)		2,080		(12	)
Operating income	$	27,651	$	15,886
Sulfur (long tons)		1,314.5		1,129.2
Fertilizer (long tons)		271.8		274.9
Sulfur Services Volumes (long tons)		1,586.3		1,404.1

Revenues.  Our sulfur services revenues increased $110.0 million, or 67%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  This increase was a result of higher market prices in 2011 compared to 2010.  The services revenue relates to a new contract that began on January 1, 2011.

Cost of products sold.  Our cost of products sold increased $97.6 million, or 80%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  This increase was directly related to the increased price of our raw materials in 2011 compared to 2010.  Our overall gross margin per ton increased to $34.66 in 2011 from $30.34 in 2010.

Operating expenses.  Our operating expenses increased $2.3 million, or 14%, for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase consists of marine fuel expense increasing $0.8 million, workers compensation claims of $0.8 million, outside towing of $0.4 million, and property taxes of $0.2 million.

Selling, general, and administrative expenses.  Our selling, general, and administrative expenses remained flat for the year ended December 31, 2011, compared to the year ended December 31, 2010.

Depreciation and amortization.  Depreciation and amortization increased $0.4 million, or 6%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  This increase was primarily a result of normal capital expenditure activity during the current year.

Other operating income.  Other operating income increased $2.1 million for the year ended December 31, 2011 consisting of $1.4 million received for the termination of a rail services agreement and $0.7 million for business interruption insurance recoveries from Hurricane Ike.

In summary, our sulfur services operating income increased $11.8 million, or 74%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.

8

Marine Transportation Segment

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

	Years Ended December 31,
	2011			2010
	(In thousands)
Revenues	$	83,971		$	82,635
Operating expenses		66,771			57,642
Selling, general and administrative expenses		3,087			2,296
Depreciation and amortization		13,159			12,721
		954			9,976
Other operating income (loss)		(223	)		16
Operating income	$	731		$	9,992

Revenues.  Our marine transportation revenues increased $1.3 million, or 2%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  This increase was primarily a result of an increase in our inland marine operations, offset by a decrease in our offshore marine operations.  Our inland marine operations increased $7.2 million, of which $2.8 million is attributed to increased utilization of the inland fleet through the utilization of new leased equipment and increases in contract rates.  The remaining $4.4 million is due to an increase in ancillary charges.  Our offshore revenues decreased $6.3 million primarily due to decreased utilization of the offshore fleet in 2011 of $8.1 million due to various dry dockings and reduced demand for our two offshore tows which operate in the spot market, offset by an increase in ancillary charges of $1.8 million.

Operating expenses.  Operating expenses increased $9.1 million, or 16%, for the year ended December 31, 2011 compared to the year ended December 31, 2010, primarily as a result of increased fuel expense of $4.4 million, outside towing expense of $1.7 million, increased repairs and maintenance expense of $1.7 million, operating supplies of $1.0 million, and increased wages and burden costs of $1.7 million.  Offsetting these increases was a decrease in barge lease expense of $2.0 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $0.8 million, or 34%, for the year ended December 31, 2011 compared to the year ended December 31, 2010, primarily due to the reserve of an uncollectible customer receivable of $0.7 million.

Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 3%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.  This increase was primarily a result of capital expenditures made in the last twelve months.

Other operating income.  Other operating income for the year ended December 31, 2011 and the year ended December 31, 2010 consisted of gains and losses on the disposal of assets.

In summary, our marine transportation operating income decreased $9.3 million, or 93%, for the year ended December 31, 2011 compared to the year ended December 31, 2010.

Equity in Earnings of Unconsolidated Entities

For the years ended December 31, 2011 and 2010, equity in earnings of unconsolidated entities relates to our unconsolidated interests in Redbird.

Equity in earnings of unconsolidated entities was $0.1 million for the year ended December 31, 2011, compared to $0.0 million for the year ended December 31, 2010, an increase of $0.1 million.  This increase is a result of equity in earnings related to our interest in Redbird, which was acquired in May 2011.

 Interest Expense

Our interest expense for all operations was $24.5 million for 2011 compared to $33.7 million for 2010, a decrease of $9.2 million, or 27%.   This decrease was primarily due to the termination of all our interest rate swaps at a cost of $3.8 million during the first quarter 2010, the termination of all our interest rate swaps at a benefit of $2.8 million during the 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, offset by increases due to the issuance of our senior notes at the end of the first quarter 2010.

Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses were $8.9 million for 2011 compared to $6.4 million for 2010, an increase of $2.5 million or 39%.

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 allocation for these expenses.  Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2011 and 2010, the Conflicts Committee of our general partner approved reimbursement amounts of $4.8 million and $3.8 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

9

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

Our total revenues before eliminations were $809.0 million for the year ended December 31, 2010 compared to $599.1 million for the year ended December 31, 2009, an increase of $209.9 million, or 35%.  Our operating income before eliminations was $42.3 million for the year ended December 31, 2010 compared to $37.2 million for the year ended December 31, 2009, an increase of $5.1 million, or 14%.

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.

	Years Ended December 31,
	2010		2009
	(In thousands)
Revenues:
Services	$	71,471		$	73,885
Products		47,799			35,628
Total Revenues		119,270			109,513
Cost of products sold		44,549			31,331
Operating expenses		41,857			45,783
Selling, general and administrative expenses		426			1,955
Depreciation and amortization		16,650			15,717
		15,788			14,727
Other operating income (loss)		244			5,504
Operating income	$	16,032		$	20,231

Revenues.  Our terminalling and storage revenues increased $9.8 million, or 9%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  Service revenue decreased $2.4 million compared to the prior year period.  This decrease is primarily due to the historical Cross refining margin included in the recast 2009 historical revenues exceeding the contractual tolling fee for feedstock processing received in 2010 of $4.7 million.  This decrease was offset by an increase in activities at terminals of $2.3 million.   Product revenue increased $12.2 million compared to the prior year period.  Of this increase, $10.1 million was due to a 13% increase in average selling price and an 18% increase in sales volumes at our Mega Lubricants facility.  Additionally, $7.5 million of this increase was due to the conversion of a consigned product delivery agreement with one of our customers to a buy/sell product delivery agreement during the third quarter of 2010.  These increases were partially offset by a $5.4 million decrease due to the sale of our traditional lubricant business including inventory to Martin Resource Management in April 2009 in return for a service fee for lubricant volumes moved through our terminals.

Cost of products sold.  Our cost of products sold increased $13.2 million, or 42%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  Of this increase, $10.1 million was due to an 18% increase in average cost of product and an 18% increase in sales volumes at our Mega Lubricants facility, and $6.7 million of this increase was due to the conversion of a consigned product delivery agreement with one of our customers to a buy/sell product delivery agreement during the third quarter of 2010.  The remaining $1.0 million increase was due to the increase in consigned marine delivery expenses.  These increases were partially offset by a $4.6 million decrease due to the sale of our traditional lubricant business including inventory to Martin Resource Management in April 2009 in return for a service fee for lubricant volumes moved through our terminals.

Operating expenses.  Operating expenses decreased $3.9 million, or 9%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This decrease was primarily the result of a reduction of the historical level of expenses attributable to the Cross assets of $4.6 million. This decrease was offset by an increase in salaries and burden of $0.7 million.

Selling, general and administrative expenses.Selling, general and administrative expenses decreased $1.5 million, or 78%,for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This decrease was primarily a result of the historical level of expenses attributable to the Cross assets.

Depreciation and amortization.  Depreciation and amortization increased $0.9 million, or 6%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This increase was primarily a result of our recent acquisitions and capital expenditures.

Other operating income (loss). Other operating income for the year ended December 31, 2010 consisted primarily of gains and losses on the disposal of assets.  Other operating income for the year ended December 31, 2009 consisted primarily of a gain on the sale of our Mont Belvieu terminal on April 30, 2009.

In summary, terminalling and storage operating income decreased $4.2 million, or 21%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.

10

Natural Gas Services Segment

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

	Years Ended December 31,
	2010			2009
	(In thousands)
Revenues	$	442,005		$	337,848
Cost of products sold		428,843			324,459
Operating expenses		3,210			3,090
Selling, general and administrative expenses		2,581			2,108
Depreciation and amortization		571			564
		6,800			7,627
Other operating income		(20	)		—
Operating income	$	6,780		$	7,627
NGLs Volumes (Bbls)		6,997			7,054

Revenues.  Our natural gas services revenues increased $104.2 million, or 31%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  During 2010, our NGL average sales price per barrel increased $15.28, or 32% compared to the same period in 2009.  NGL sales volumes for the year remained relatively consistent compared to the same period of 2009.

Costs of product sold.  Our cost of products increased $104.4 million, or 32%, for the year ended December 31, 2010 compared to the same period in 2009.  Our NGL per barrel margins remained relatively consistent compared to the same period in 2009.

Operating expenses.  Operating expenses increased $0.1 million, or 4%, for the year ended December 31, 2010 compared to the same period of 2009 as a result of increased pipeline maintenance expenses of $0.3 million, offset by decreased land lease expense of $0.2 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $0.5 million, or 22% for the year ended December 31, 2010 compared to the same period of 2009.  This increase was primarily a result of the write-off of an uncollectible customer receivable.

Depreciation and amortization. Depreciation and amortization remained consistent for the year ended December 31, 2010 compared to the same period of 2009.

In summary, our natural gas services operating income decreased $0.8 million, or 11%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.

11

Sulfur Services Segment

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

	Years Ended December 31,
	2010			2009
	(In thousands)
Revenues	$	165,078		$	79,631
Cost of products sold		122,483			43,748
Operating expenses		17,013			17,113
Selling, general and administrative expenses		3,422			3,449
Depreciation and amortization		6,262			6,151
		15,898			9,170
Other operating income		(12	)		405
Operating income	$	15,886		$	9,575
Sulfur (long tons)		1,129.2			1,107.5
Fertilizer (long tons)		274.9			238.0
Sulfur Services Volumes (long tons)		1,404.1			1,345.5

Revenues.  Our sulfur services revenues increased $85.4 million, or 107%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This increase was a result of higher market prices in 2010 compared to 2009.

Cost of products sold.  Our cost of products sold increased $78.8 million, or 180%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This increase was directly related to the increased price of our raw materials in 2010 compared to 2009.  Our overall gross margin per ton increased from $26.66 in 2009 to $30.34 in 2010.

Operating expenses.  Our operating expenses decreased $0.1 million, or 1%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This decrease was a result of decreased costs relating to fuel prices for marine transportation of our sulfur products.

Selling, general, and administrative expenses.  Our selling, general, and administrative expenses increased less than$0.1 million, or 1%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.

Depreciation and amortization.  Depreciation and amortization increased $0.1 million, or 2%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This increase was primarily a result of normal capital expenditure activity during the current year.

In summary, our sulfur services operating income increased $6.3 million, or 66%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.

12

Marine Transportation Segment

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

	Years Ended December 31,
	2010		2009
	(In thousands)
Revenues	$	82,635	$	72,103
Operating expenses		57,642		52,335
Selling, general and administrative expenses		2,296		962
Depreciation and amortization		12,721		13,111
		9,976		5,695
Other operating income		16		116
Operating income	$	9,992	$	5,811

Revenues.  Our marine transportation revenues increased $10.5 million, or 15%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  Our offshore revenues increased $7.7 million primarily due to increased utilization of the offshore fleet in 2010. Our inland marine operations increased $2.8 million primarily due to an increase in inland freight revenue of $1.5 million.  This increase was primarily a result of an increased utilization of the inland fleet, which was offset by decreased day rates in 2010.  The remaining $1.3 million increase was due to an increase in ancillary revenues which consisted primarily of fuel and tankerman services.

Operating expenses.  Operating expenses increased $5.3 million, or 10%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This was primarily a result of an increase in barge leases of $4.6 million and an increase in wages and burden costs of $1.1 million.  These increases were offset by a decrease in repairs and maintenance expenses of $0.7 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $1.3 million, or 139% for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This increase was primarily a result of bad debt in 2010.

Depreciation and amortization. Depreciation and amortization decreased $0.4 million, or 3%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.  This decrease was primarily a result of equipment disposals offset by capital expenditures made in the last 12 months.

Other operating income.  Other operating income for the year ended December 31, 2010 and the year ended December 31, 2009 consisted of gains and losses on the disposal of assets.

In summary, our marine transportation operating income increased $4.2 million, or 72%, for the year ended December 31, 2010 compared to the year ended December 31, 2009.

Interest Expense

Our interest expense for all operations was $33.8 million for 2010 compared to $19.0 million for 2009, an increase of $14.8 million, or 78%.   This increase was primarily due to an increase in average debt outstanding and an increase in the average interest rates paid on the indebtedness throughout 2010 compared to 2009.

Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses were $6.4 million for 2010 compared to $6.1 million for 2009, an increase of $0.3 million or 5%.

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 allocation for these expenses.  Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

In addition to the direct expenses, under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2010 and 2009, the Conflicts Committee of our general partner approved reimbursement amounts of $3.8 and $3.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

13

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 2011 and 2010, we completed several transactions that have improved our liquidity position.  In February 2011, we received net proceeds of $70.3 million from a public offering of common units.  In March 2010, we received net proceeds of $197.2 million from a private placement of senior notes and in February 2010, $50.5 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 $375.0 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 – Risks related to Our Business” for a discussion of such risks.

Debt Financing Activities

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.

Effective March 26, 2010, we amended our credit facility to (i) decrease the size of our aggregate facility from $350.0 million to $275.0 million, (ii) convert all term loans to revolving loans, (iii) extend the maturity date from November 9, 2012 to March 15, 2013, (iv) permit us to invest up to $40.0 million in our joint ventures, (v) eliminate the covenant that limits our ability to make capital expenditures, (vi) decrease the applicable interest rate margin on committed revolver loans, (vii) limit our ability to make future acquisitions, and (viii) adjust the financial covenants.    For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Credit Facility” within this Item.

On March 26, 2010, we completed a private placement of $200.0 million in aggregate principal amount of 8.875% senior unsecured notes due 2018 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $197.2 million, after deducting initial purchasers’ discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility.   For a more detailed discussion regarding the notes offering, see “Description of Our Long-Term Debt—Senior Notes” within this Item.

 For a more detailed discussion regarding our credit facility, see “Description of Our Long-Term Debt—Senior Notes” within this Item.

Equity Offerings

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.

On August 17, 2010, we completed a public offering of 1,000,000 common units, representing limited partner interests at a purchase price of $29.13 per common unit. We received net proceeds of approximately $28.1 million after payment of underwriters’ discounts. We used the net proceeds of $28.1 million to redeem from subsidiaries of Martin Resource Management an aggregate number of common units equal to the number of common units issued in the offering.  Martin Resource Management reimbursed us for its payments of commissions and offering expenses. As a result of these simultaneous transactions, our general partner was not required to contribute cash to us in conjunction with the issuance of these units in order to maintain its 2% general partner interest in us since there was no net increase in the outstanding limited partner units.

On February 8, 2010, we completed a public offering of 1,650,000 common units at a price of $32.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands).  The common units sold in the offering were registered under the Securities Act pursuant to our existing shelf registration statement.  Following this offering, the common units represented a 93.3% limited partnership interest in us.  Total proceeds from the sale of the 1,650,000 common units, net of underwriters’ discounts, commissions and offering expenses were $50.5 million.  Our general partner contributed $1.1 million in cash us in conjunction with the issuance in order to maintain its 2% general partner interest in us.  On February 8, 2010, we made a $45.0 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 2012.

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 – Risks Related to Our Business” for a discussion of such risks.

14

Cash Flows and Capital Expenditures

In 2011, cash decreased $11.1 million as a result of $86.9 million provided by operating activities ($70.8 million provided by continuing operating activities and $16.1 million provided by discontinued operating activities), $167.3 million used in investing activities ($153.4 million used in continuing investing activities and $13.9 million used in discontinued investing activities), and $69.3 million provided by financing activities.  In 2010, cash increased $5.4 million as a result of $37.5 million provided by operating activities ($28.0 million provided by continuing operating activities and $9.5 million provided by discontinued operating activities), $76.7 million used in investing activities ($33.4 million used in continuing investing activities and $43.3 million used in discontinued investing activities), and $44.6 million provided by financing activities.  In 2009, cash decreased $2.0 million as a result of $47.6 million provided by operating activities ($30.6 million provided by continuing operating activities and $17.0 million provided by discontinued operating activities), $14.7 million used in investing activities ($9.2 million used in continuing investing activities and $5.5 million used in discontinued investing activities), and $34.9 million provided by financing activities.

For 2011, our continuing investing activities of $153.4 million consisted primarily of capital expenditures, acquisitions, investments in unconsolidated entities, and proceeds from sale of property, plant and equipment. For 2011, our discontinued investing activities of $13.9 million consisted primarily of capital expenditures, and investments in and returns of investments from unconsolidated partnerships.  Our investment in unconsolidated partnerships helped to fund $3.9 million and $11.1 million in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December 31, 2011, respectively.  For 2010, our continuing investing activities of $33.4 million consisted primarily of capital expenditures, acquisitions, and proceeds from sale of property, plant and equipment.  For 2010, our discontinued investing activities of $43.3 million consisted primarily of capital expenditures, acquisitions, and investments in and returns of investments from unconsolidated partnerships.  Our investment in unconsolidated partnerships helped to fund $1.2 million and $3.2 million in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December 31, 2010, respectively.  For 2009, our continuing investing activities of $9.2 million consisted primarily of capital expenditures, proceeds from sale of property, and insurance proceeds from involuntary conversion of property, plant and equipment.  For 2009, our discontinuing investing activities of $5.5 million consisted primarily of capital expenditures, proceeds from sale of property, and insurance proceeds from involuntary conversion of property, plant and equipment.   Our investment in unconsolidated partnerships helped to fund $0.4 million and $3.8 million in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December 31, 2009, respectively.

For 2011, 2010 and 2009 our capital expenditures for property and equipment related to continuing activities were $72.7 million, $16.5 million, and $30.7 million, respectively.  For 2011, 2010 and 2009 our capital expenditures for property and equipment related to discontinued activities were $1.3 million, $1.4 million, and $5.2 million, respectively.

As to each period:

·   In 2011, we spent $62.9 million for expansion and $9.8 million for maintenance capital expenditures (including $0.3 million for maintenance in the fourth quarter of 2011) related to continuing operations.  Our expansion capital expenditures were made in connection with marine vessel conversions, construction projects associated with our terminalling and storage and sulfur services businesses.  Our maintenance capital expenditures were primarily made in our marine and sulfur services divisions for routine operating equipment improvements.  In 2011, we spent $0.2 million for expansion and $1.1 million for maintenance capital expenditures (including $0.5 million for maintenance in the fourth quarter of 2010) related to discontinued operations.

·   In 2010, we spent $12.4 million for expansion and $4.1 million for maintenance (including $0.9 million for maintenance in the fourth quarter of 2010) related to continuing operations.  Our expansion capital expenditures were made in connection with marine vessel conversions, construction projects associated with our terminalling and storage and sulfur services businesses.  Our maintenance capital expenditures were primarily made in our terminalling and storage and sulfur services divisions for routine operating equipment improvements.  In 2010, we spent $0.8 million for expansion and $0.6 million for maintenance capital expenditures (including $0.3 million for maintenance in the fourth quarter of 2010) related to discontinued operations.

·   In 2009, we spent $23.4 million for expansion and $7.3 million for maintenance (including $0.7 million for maintenance in the fourth quarter of 2009) related to continuing operations.  Our expansion capital expenditures were made in connection with marine vessel purchases and conversions, construction projects associated with our terminalling and storage and sulfur services businesses.  Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements.  In 2009, we spent $4.4 million for expansion and $0.6 million for maintenance capital expenditures (including $0.2 million for maintenance in the fourth quarter of 2009) related to discontinued operations.

In 2011, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of $442.0 million and borrowings of long-term debt under our credit facilities of $529.0 million, cash distributions paid to common and subordinated unitholders of $64.5 million, payments of notes payable and capital lease obligations of $1.1 million, purchase of treasury units of $0.6 million and payments of debt issuance costs of $3.6 million.  Additional financing activities consisted of contributions of $1.5 million from our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $70.3 million and excess purchase price over carrying value of acquired assets of $19.7 million.

In 2010, our financing activities consisted of payments of long-term debt under our credit facilities and senior notes of $441.9 million and borrowings of long-term debt under our credit facilities of $503.9 million, cash distributions paid to common and subordinated unitholders of $56.7 million, payments of notes payable and capital lease obligations of $0.1 million, purchase of treasury units of $0.1 million and payments of debt issuance costs of $7.5 million.  Additional financing activities consisted of contributions of $1.1 million from our general partner to maintain its 2% general partner interest, net proceeds from follow on public offering of $78.6 million, redemption of common units of $28.1 million and excess purchase price over carrying value of acquired assets of $4.6 million.

In 2009, our financing activities consisted of payments of long-term debt under our credit facilities of $430.5 million and borrowings of long-term debt under our credit facilities of $433.7 million, cash distributions paid to common and subordinated unitholders of $47.5 million, payments of notes payable and capital lease obligations of $1.5 million, purchase of treasury units of $0.1 million and payments of debt issuance costs of $10.4 million.  Additional financing activities consisted of $20.0 million in connection with a private equity offering issuance of 714,285 common units to Martin Resource Management and contributions of $1.3 million from our general partner to maintain its 2% general partner interest.

In November 2009, we acquired the Cross assets from Martin Resource Management for total consideration of $44.9 million as a result of a non-cash financing activity.  As consideration for the contribution of the Cross assets, we issued 804,721 of our common units and 889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per limited partner unit, respectively.  Since Martin Resource Management and the Partnership are companies under common control, the acquired assets were recorded in property, plant and equipment based on their carrying values of $33.0 million in the financial statements of Martin Resource Management.  In connection with the contribution of the Cross assets, our general partner made a capital contribution of $0.9 million to us in order to maintain its 2% general partner interest.

15

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 December 31, 2011, we had $460.2 million of outstanding indebtedness, consisting of outstanding borrowings of $197.8 million (net of unamortized discount) under our Senior Notes, $250.0 million under our revolving credit facility, $6.4 million under a note payable to a bank, and $6.0 million under capital lease obligations.  As of December 31, 2011, we had $124.9 million of available borrowing capacity under our revolving credit facility.

Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of December 31, 2011 is as follows (dollars in thousands):

	Payment due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Long-Term Debt
Revolving credit facility	$	250,000	$	—	$	—	$	250,000	$	—
Senior unsecured notes		197,808		—		—		—		197,808
Note payable		6,363		1,068		2,392		2,778		125
Capital leases including current maturities		6,031		193		534		5,304		—
Non-competition agreements		150		50		100		—		—
Throughput commitment		52,298		3,147		9,746		10,382		29,023
Operating leases		47,365		11,776		14,990		11,861		8,738
Interest expense(1)
Revolving credit facility		32,838		7,659		15,317		9,862		—
Senior unsecured notes		112,417		17,750		35,500		35,500		23,667
Note payable		1,311		441		628		241		1
Capital leases		4,057		945		1,782		1,330		—
Total contractual cash obligations	$	710,638	$	43,029	$	80,989	$	327,258	$	259,362

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

Letter of Credit. At December 31, 2011, 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.

16

Description of Our Long-Term Debt

Senior Notes

In March 2010, we and Martin Midstream Finance Corp. (“FinCo”), our subsidiary (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.

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 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.

17

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.  Additionally, effective 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.

As of December 31, 2011, we had approximately $250.0 million outstanding under the revolving credit facility and $0.1 million of letters of credit issued, leaving approximately $124.9 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 $135.0 million to a high of $272.0 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.  Prepayments as a result of asset sales and debt incurrences require a mandatory reduction of the lenders’ commitments under the credit facility equal to 25% of the corresponding mandatory prepayment, but in no event will such prepayments cause the lenders’ commitments under the credit facility to be less than $250.0 million.  Prepayments as a result of equity issuances do not require any reduction of the lenders’ commitments under the credit facility.

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:

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		2.00	%		3.00	%		3.00	%
Greater than or equal to 4.50 to 1.00		2.25	%		3.25	%		3.25	%

As of December 31, 2011, based on our leverage ratio the applicable margin for existing Eurodollar Rate borrowings is 2.50%.  Effective January 1, 2012, the applicable margin for Eurodollar Rate borrowings increased to 2.75%. Effective April 1, 2012, based on our leverage ratio at December 31, 2011, the applicable margin for Eurodollar Rate borrowings will increase to 3.00%.

The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter.  The maximum permitted leverage ratio is 5.00 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.

18

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;

• 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 March 2, 2012, our outstanding indebtedness includes $225.0 million under our credit facility.

19

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 $40.0 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 $60.0 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 October 2008, we entered into an interest rate swap that swapped $40.0 million of floating rate to fixed rate. The fixed rate cost was 2.820% plus our applicable LIBOR borrowing spread. Effective April 2009, we entered into two subsequent swaps to lower our effective fixed rate to 2.580% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap were accounted for using mark-to-market accounting. The second subsequent swap was accounted for using hedge accounting. Each of the swaps were scheduled to mature in October 2010, but were terminated in March 2010.

Effective January 2008, we entered into an interest rate swap that swapped $25.0 million of floating rate to fixed rate. The fixed rate cost was 3.400% plus our applicable LIBOR borrowing spread. Effective April 2009, we entered into two subsequent swaps to lower our effective fixed rate to 3.050% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap were accounted for using mark-to-market accounting. The second subsequent swap was accounted for using hedge accounting. Each of the swaps matured in January 2010.

Effective September 2007, we entered into an interest rate swap that swapped $25.0 million of floating rate to fixed rate. The fixed rate cost was 4.605% plus our applicable LIBOR borrowing spread. Effective March 2009, we entered into two subsequent swaps to lower our effective fixed rate to 4.305% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap were accounted for using mark-to-market accounting. The second subsequent swap was accounted for using hedge accounting. Each of the swaps were scheduled to mature in September 2010, but were terminated in March 2010.

Effective November 2006, we entered into an interest rate swap that swapped $30.0 million of floating rate to fixed rate. The fixed rate cost was 4.765% plus our applicable LIBOR borrowing spread. This interest rate swap, which matured in March 2010, was not accounted for using hedge accounting.

Effective March 2006, we entered into an interest rate swap that swapped $75.0 million of floating rate to fixed rate. The fixed rate cost was 5.25% plus our applicable LIBOR borrowing spread. Effective February 2009, we entered into two subsequent swaps to lower our effective fixed rate to 5.10% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap were accounted for using mark-to-market accounting. The second subsequent swap was accounted for using hedge accounting. Each of the swaps were scheduled to mature in November 2010, but were terminated in March 2010.

Seasonality

A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and sulfur-based fertilizer products, 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 storage and marine transportation businesses and the molten sulfur business are typically not impacted by seasonal fluctuations.  We expect to derive our net income from our diverse terminalling and storage, marine transportation, natural gas and sulfur 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.  For example, Hurricanes Gustav and Ike in the third quarter of 2008 and Hurricanes Katrina and Rita in the third quarter of 2005 adversely impacted our operating expenses and adversely impacted our terminalling and storage and marine transportation business’s revenues.

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2011, 2010 and 2009.  However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs.  We cannot assure our unitholders that we will be able to pass along increased costs to our customers.

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 assure our unitholders 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 significant environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2011, 2010 or 2009.

20

Item 7A.                      Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates.  For the year ended December 31, 2011, changes in the fair value of our derivative contracts were recorded both in earnings and accumulated other comprehensive income (“AOCI”) since we have designated a portion of our derivative instruments as hedges as of December 31, 2011.

Commodity Price Risk

We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Under our hedging policy, we monitor and manage the commodity market risk associated with the commodity risk exposure of Prism Gas.  In addition, we are focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

We use derivatives to manage the risk of commodity price fluctuations.These outstanding contracts expose us to credit loss in the event of nonperformance by the counterparties to the agreements. We have incurred no losses associated with counterparty nonperformance on derivative contracts.

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement; establish a maximum credit limit threshold pursuant to our hedging policy; and monitor the appropriateness of these limits on an ongoing basis. We have agreements with three 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 us if the value of derivatives is a liability to us. As of December 31, 2011, we have no cash collateral deposits posted with counterparties.

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales activities of the Prism Assets which were sold on July 31, 2012.  Our exposure to these fluctuations is primarily in the gas processing component of our business. Gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids and percent-of-proceeds bases.

•   Percent-of-liquids contracts:  Under these contracts, we receive a fee in the form of a percentage of the NGLs recovered, and the producer bears all of the cost of natural gas shrink. Therefore, margins increase during periods of high NGL prices and decrease during periods of low NGL prices.

•   Percent-of-proceeds contracts:  Under these contracts, we generally gather and process natural gas on behalf of certain producers, sell the resulting residue gas and NGLs at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGLs to the producer and sell the volumes kept to third parties at market prices. Under these types of contracts, revenues and gross margins increase as natural gas prices and NGL prices increase, and revenues and gross margins decrease as natural gas and NGL prices decrease.

Market risk associated with gas processing margins by contract type, and gathering and transportation margins as a percent of total gross margin remained consistent for the years ended December 31, 2011 and 2010, as our contract mix and percent of volumes associated with those contracts did not differ materially.

Due to the sale of the Prism Assets during July 2012, the aggregate effect of a hypothetical $1.00/MMbtu increase or decrease in the natural gas price index will not have a significant impact on our annual gross margin.  Additionally, the aggregate effect of a hypothetical $10.00/Bbl increase or decrease in the crude oil price index will not have a significant impact on our annual gross margin.

We will continue to manage our risks associated with market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that we will be able to do so or that the terms thereof will be similar to our existing hedging arrangements.

21

The relevant payment indices for our various commodity contracts are as follows:

•   Natural gas contracts - monthly posting for ANR Pipeline Co. - Louisiana as posted in Platts Inside FERC’s Gas Market Report;

•   Crude oil contracts - WTI NYMEX average for the month of the daily closing prices; and

•   Natural gasoline contracts - Mt. Belvieu Non-TET average monthly postings as reported by the Oil Price Information Service (OPIS).

Derivative Contracts in Place

As of December 31, 2011

Period	Underlying	Notional Volume	Commodity Price We Receive	Commodity Price We Pay	Fair Value Asset (In Thousands)		Fair Value Liability  (In Thousands)
January 2012-December 2012	Natural Gasoline	12,000 (BBL)	Index	$2.340/Gal	$	—	$	13
January 2012-December 2012	Natural Gas	120,000 (MMBTU)	Index	$4.87/Mmbtu		200		—
January 2012-December 2012	Natural Gas	240,000 (MMBTU)	Index	$4.96/Mmbtu		422		—
January 2012-December 2012	Crude Oil	24,000 (BBL)	Index	$88.63/bbl		—		245
January 2012-December 2012	Natural Gasoline	12,000 (BBL)	Index	$90.20/bbl		—		104
					$	622	$	362

Our 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 our natural gas and NGL sales are made at market-based prices. Our 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 us.

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 2.81% as of December 31, 2011.  As of March 2, 2012, we had total indebtedness outstanding under our credit facility of $225.0 million, all of which was unhedged floating rate debt.  Based on the amount of unhedged floating rate debt owed by us on December 31, 2011, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $2.5 million annually.

Historically, we have managed a portion of our interest rate risk on a portion of our long-term debt with interest rate swaps, which reduced our exposure to changes in interest rates by converting variable interest rates to fixed interest rates on our Credit Facility and fixed interest rates to variable interest rates on our Senior Notes. During the third quarter of 2011, we terminated all of our interest rate swaps on our Senior Notes.

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 $210.5 million as of December 31, 2011, based on market prices of similar debt at December 31, 2011.   Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately a $9.2 million decrease in fair value of our long-term debt at December 31, 2011.

EX-99.3

Exhibit 99.3

As further discussed in notes 2(a) and 6 to our consolidated financial statements herein, our consolidated financial statements for all periods presented herein have been updated to reclassify the assets and related liabilities of our natural gas gathering and processing business as held for sale and the related results of operations as discontinued operations.  This filing includes updates only to the portions of Item 6, Item 7 and Item 8 of the December 31, 2011 Form 10-K that specifically relate to the reclassification of the assets and related liabilities of our natural gas gathering and processing business as held for sale and the related results of operations as discontinued operations and does not otherwise modify or update any other disclosures set forth in the December 31, 2011 Form 10-K.

Item 8.                      Financial Statements and Supplementary Data

The following financial statements of Martin Midstream Partners L.P. (Partnership) are listed below:

                                                                                                                                          Page

 

Report of Independent Registered Public Accounting Firm	2
Report of Independent Registered Public Accounting Firm on Internal Controls	3
Consolidated Balance Sheets as of December 31, 2011 and 2010	4
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009	5
Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009	6
Consolidated Statements of Changes in Capital for the years ended December 31, 2011, 2010 and 2009	7
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009	8
Notes to the Consolidated Financial Statements	9

1

Report of Independent Registered Public Accounting Firm

The Board of Directors

Martin Midstream GP LLC:

We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2011.  These financial statements are the responsibility of Martin Midstream’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2011 and 2010 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 5, 2012 expressed an unqualified opinion on the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting.

/s/ KPMG LLP

Shreveport, Louisiana

March 5, 2012, except for the updated disclosures and reclassification of gas gathering and processing assets as held for sale and discontinued operations for all periods presented, as described in notes 2(a) and 6, as to which the date is August 21, 2012

2

Report of Independent Registered Public Accounting Firm

The Board of Directors

Martin Midstream GP LLC:

We have audited Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Martin Midstream’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A(b).  Our responsibility is to express an opinion on Martin Midstream’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.   Our audit also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with  generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated March 5, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Shreveport, Louisiana

March 5, 2012

3

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(Dollars in thousands)
Assets
Cash	$	266		$	11,380
Accounts and other receivables, less allowance for doubtful accounts of $3,021 and $2,528, respectively		126,461			95,276
Product exchange receivables		17,646			9,099
Inventories		77,677			51,865
Due from affiliates		5,968			6,437
Fair value of derivatives		622			2,142
Other current assets		1,978			2,784
Assets held for Sale		212,787			—
Total current assets		443,405			178,983
Property, plant and equipment, at cost		632,728			555,417
Accumulated depreciation		(215,272	)		(186,237	)
Property, plant and equipment, net		417,456			369,180
Goodwill		8,337			8,337
Investment in unconsolidated entities		62,948			—
Debt issuance costs, net		13,330			13,497
Other assets		3,633			7,556
Assets held for Sale		—			207,925
	$	949,109		$	785,478
Liabilities and Partners’ Capital
Current installments of long-term debt and capital lease obligations	$	1,261		$	1,121
Trade and other accounts payable		125,970			82,837
Product exchange payables		37,313			22,353
Due to affiliates		18,485			6,957
Income taxes payable		893			811
Fair value of derivatives		362			282
Other accrued liabilities		11,022			10,034
Liabilities held for sale		501			—
Total current liabilities		195,807			124,395
Long-term debt and capital leases, less current maturities		458,941			372,862
Deferred income taxes		7,657			8,213
Fair value of derivatives		—			4,100
Other long-term obligations		1,088			622
Liabilities held for sale		—			480
Total liabilities		663,493			510,672
Partners’ capital		284,990			273,387
Accumulated other comprehensive loss		626			1,419
Total partners’ capital		285,616			274,806
Commitments and contingencies
	$	949,109		$	785,478

See accompanying notes to consolidated financial statements.

4

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2011			2010				2009¹
	(Dollars in thousands, except per unit amounts)
Revenues:
Terminalling and storage  *	$	77,283		$	67,117		$	69,710
Marine transportation  *		76,936			77,642			68,480
Sulfur services  *		11,400			—			—
Product sales: *
Natural gas services		611,749			442,005			337,841
Sulfur services		263,644			165,078			79,629
Terminalling and storage		74,723			47,799			35,584
		950,116			654,882			453,054
Total revenues		1,115,735			799,641			591,244
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *		598,814			427,657			323,390
Sulfur services *		219,697			122,121			43,386
Terminalling and storage		67,134			44,549			31,331
		885,645			594,327			398,107
Expenses:
Operating expenses  *		134,734			111,923			111,901
Selling, general and administrative  *		17,430			15,111			14,551
Depreciation and amortization		39,445			36,204			35,543
Total costs and expenses		1,077,254			757,565			560,102
Other operating income		1,326			228			6,025
Operating income		39,807			42,304			37,167
Other income (expense):
Equity in earnings of unconsolidated entities		124			—			—
Interest expense		(24,518	)		(33,716	)		(18,995	)
Other, net		233			287			327
Total other income (expense)		(24,161	)		(33,429	)		(18,668	)
Net income before taxes		15,646			8,875			18,499
Income tax benefit (expense)		(696	)		(914	)		(1,564	)
Income from continuing operations		14,950			7,961			16,935
Income from discontinued operations, net of income taxes		9,392			8,061			5,268
Net income	$	24,342		$	16,022		$	22,203

¹ General and limited partner’s interest in net income includes net income of the Cross assets since the date of the acquisition.

*Related Party Transactions Included Above

Revenues:
Terminalling and storage	$	54,211	$	46,823	$	19,998
Marine transportation		23,478		28,194		19,370
Product Sales		9,081		7,903		5,838
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services		16,749		7,517		8,343
Sulfur services		18,314		16,061		12,583
Expenses:
Operating expenses		58,051		48,390		37,284
Selling, general and administrative		8,610		7,237		7,162

5

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF STATEMENTS OF OPERATIONS

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

	Year Ended December 31,
	2011		2010			2009¹
Allocation of net income attributable to: Limited partner interest:
Continuing operations	$	11,022	$	5,488	$	12,708
Discontinued operations		6,923		5,557		4,471
		17,945		11,045		17,179
General partner interest:
Continuing operations		3,248		1,922		2,478
Discontinued operations		2,041		1,947		771
		5,289		3,869		3,249
Net income attributable to:
Continuing operations		14,270		7,410		15,186
Discontinued operations		8,964		7,504		5,242
	$	23,234	$	14,914	$	20,428
Net income attributable to limited partners: Basic:
Continuing operations	$	0.57	$	0.31	$	0.87
Discontinued operations		0.35		0.32		0.30
	$	0.92	$	0.63	$	1.17
Weighted average limited partner units - basic		19,545		17,525		14,681
Diluted:
Continuing operations	$	0.57	$	0.31	$	0.87
Discontinued operations		0.35		0.32		0.30
	$	0.92	$	0.63	$	1.17
Weighted average limited partner units - diluted		19,547		17,526		14.685

See accompanying notes to consolidated financial statements.

¹ General and limited partner’s interest in net income includes net income of the Cross assets since the date of the acquisition.

6

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 (Dollars in thousands)

	Year Ended December 31,
	2011			2010			2009
	(Dollars in thousands)
Net income	$	24,342		$	16,022		$	22,203
Changes in fair values of commodity cash flow hedges		1,011			143			14
Commodity cash flow hedging (gains) losses reclassified to earnings		(1,822	)		(617	)		(2,646	)
Changes in fair value of interest rate cash flow hedges		—			(241	)		(1,854	)
Interest rate cash flow hedging losses reclassified to earnings		18			4,210			7,345
Comprehensive income	$	23,549		$	19,517		$	25,062

See accompanying notes to consolidated financial statements.

7

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL

For the years ended December 31, 2011, 2010 and 2009

	Partners’ Capital
	Parent Net			Common						Subordinated						General Partner			Accumulated Comprehensive Income
	Investment			Units			Amount			Units			Amount			Amount			Amount			Total
	(Dollars in thousands)
Balances – December 31, 2008	$	11,665			13,688,152		$	239,333			850,674		$	(3,688	)	$	4,004		$	(4,935	)	$	246,379
Net Income		1,664			—			16,310			—			980			3,249			—			22,203
General partner contribution		—			—			—			—			—			1,324			—			1,324
Units issued in connection with Cross acquisition					804,721			16,523			889,444			16,434			—			—			32,957
Recognition of beneficial conversion feature		—			—			(111	)		—			111			—			—			—
Issuance of common units		—			714,285			20,000			—			—			—			—			20,000
Cash distributions ($3.00  per unit)		—			—			(41,064	)		—			(2,552	)		(3,846	)		—			(47,462	)
Conversion of subordinated units to common units		—			850,674			(5,328	)		(850,674	)		5,328			—			—			—
Unit-based compensation		—			3,000			98			—			—			—			—			98
Purchase of treasury units		—			(3,000	)		(78	)		—			—			—			—			(78	)
Contributions to parent		(13,329	)		—			—			—			—			—			—			(13,329	)
Adjustment in fair value of derivatives		—			—			—			—			—			—			2,859			2,859
Balances – December 31, 2009	$	—			16,057,832		$	245,683			889,444		$	16,613		$	4,731		$	(2,076	)	$	264,951
Net Income		—			—			12,153			—			—			3,869			—			16,022
Recognition of beneficial conversion feature		—			—			(1,108	)		—			1,108			—			—			—
Follow-on public offerings		—			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
Excess purchase price over carrying value of acquired assets		—			—			(4,590	)		—			—			—			—			(4,590	)
Cash distributions ($3.00  per unit)		—			—			(51,886	)		—			—			(4,810	)		—			(56,696	)
Unit-based compensation		—			3,500			113			—			—			—			—			113
Purchase of treasury units		—			(3,500	)		(108	)		—			—			—			—			(108	)
Adjustment in fair value of derivatives		—			—			—			—			—			—			3,495			3,495

Balances – December 31, 2010	$	—	17,707,832		$	250,787		889,444		$	17,721		$	4,879		$	1,419		$	274,806
Net income		—	—			19,053		—			—			5,289			—			24,342
Recognition of beneficial conversion feature		—	—			(1,108	)	—			1,108			—			—			—
Follow-on public offering		—	1,874,500			70,330		—			—			—			—			70,330
General partner contribution		—	—			—		—			—			1,505			—			1,505
Conversion of subordinated units to common units		—	889,444			18,829		(889,444	)		(18,829	)		—			—			—
Cash distributions ($3.05 per unit)		—	—			(58,252	)	—			—			(6,245	)		—			(64,497	)
Excess purchase price over carrying value of acquired assets		—	—			(19,685	)	—			—			—			—			(19,685	)
Unit-based compensation		—	14,850			190		—			—			—			—			190
Purchase of treasury units		—	( 14,850	)		(582	)	—			—			—			—			(582	)
Adjustment in fair value of derivatives		—	—			—		—			—			—			(793	)		(793	)
Balances – December 31, 2011	$	—	20,471,776		$	279,562		—		$	—		$	5,428		$	626		$	285,616

See accompanying notes to consolidated financial statements.

8

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(Dollars in thousands)
Cash flows from operating activities:
Net income	$	24,342		$	16,022		$	22,203
Less:  Income from discontinued operations		(9,392	)		(8,061	)		(5,268	)
Net income from continuing operations		14,950			7,961			16,935
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		39,445			36,204			35,543
Amortization of deferred debt issue costs		3,755			4,814			1,689
Amortization of discount on notes payable		351			269			—
Deferred income taxes		—			—			204
(Gain) loss on disposition or sale of property, plant, and equipment		898			(229	)		(5,008	)
Gain on involuntary conversion of property, plant, and equipment		—			—			(1,017	)
Equity in earnings of unconsolidated entities		(124	)		—			—
Distributions from unconsolidated entities		—			—			—
Distribution in-kind from unconsolidated entities		—			—			—
Non-cash mark-to-market on derivatives		(1,971	)		633			36
Other		190			113			98
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		(28,470	)		(15,738	)		(8,947	)
Product exchange receivables		(8,547	)		(4,967	)		2,792
Inventories		(25,812	)		(16,877	)		7,126
Due from affiliates		5,551			(175	)		(5,319	)
Other current assets		384			(1,448	)		2,456
Trade and other accounts payable		47,157			11,364			(16,191	)
Product exchange payables		14,961			14,366			(2,938	)
Due to affiliates		4,155			(9,473	)		3,683
Income taxes payable		(681	)		355			990
Other accrued liabilities		1,083			5,185			871
Change in other non-current assets and liabilities		3,500			(4,341	)		(2,381	)
Net cash provided by continuing operating activities		70,775			28,016			30,622
Net cash provided by discontinued operating activities		16,095			9,502			16,970
Net cash provided by operating activities		86,870			37,518			47,592
Cash flows from investing activities:
Payments for property, plant, and equipment		(72,710	)		(16,519	)		(30,858	)
Acquisitions, net of cash acquired		(16,815	)		(16,747	)		—
Payments for plant turnaround costs		(2,103	)		(1,090	)		—
Proceeds from sale of property, plant, and equipment		1,025			994			19,445
Insurance proceeds from involuntary conversion of property, plant and equipment		—			—			2,224
Investments in unconsolidated entities		(59,319	)		—			—
Return of investments from unconsolidated entities		1,432			—			—
(Contributions to) unconsolidated entities for operations		(4,937	)		—			—
Net cash used in continuing investing activities		(153,427	)		(33,362	)		(9,189	)
Net cash used in discontinued investing activities		(13,908	)		(43,366	)		(5,486	)
Net cash used in investing activities		(167,335	)		(76,728	)		(14,675	)
Cash flows from financing activities:
Payments of long-term debt		(442,000	)		(441,868	)		(430,500	)
Payments of notes payable and capital lease obligations		(1,132	)		(111	)		(1,482	)
Proceeds from long-term debt		529,000			503,856			433,700
Net proceeds from follow on public offering		70,330			78,600			—
General partner contribution		1,505			1,089			1,324
Redemption of common units		—			(28,070	)		—
Excess purchase price over carrying value of acquired assets		(19,685	)		(4,590	)		—
Purchase of treasury units		(582	)		(108	)		(78	)
Proceeds from issuance of common units		—			—			20,000
Payments of debt issuance costs		(3,588	)		(7,468	)		(10,446	)
Cash distributions paid		(64,497	)		(56,696	)		(47,462	)
Net cash provided by (used in) financing activities		69,351			44,634			(34,944	)
Net increase(decrease) in cash		(11,114	)		5,424			(2,027	)
Cash at beginning of period		11,380			5,956			7,983
Cash at end of period	$	266		$	11,380		$	5,956
Supplemental schedule of non-cash investing and financing activities:
Purchase of assets under capital lease obligations	$	—		$	—		$	7,764
Issuance of common and subordinated units in connection with Cross acquisition	$	—		$	—		$	32,957
Purchase of assets under note payable	$	—		$	7,354		$	—

See accompanying notes to consolidated financial statements.

9

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(1) ORGANIZATION AND DESCRIPTION OF BUSINESS

Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the United Stated 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 petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, 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. The Partnership operates primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry.

The Partnership owns Prism Gas Systems I, L.P. (“Prism Gas”), which is engaged in the gathering, processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana.  Prism Gas owns a 50% ownership interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), and Panther Interstate Pipeline Energy LLC (“PIPE”), each accounted for under the equity method of accounting.

The Partnership and Martin Resource Management Corporation (“Martin Resource Management” or “Parent”) formed Redbird Gas Storage LLC (“Redbird”), a natural gas storage joint venture to invest in Cardinal Gas Storage Partners LLC (“Cardinal”).  The Partnership owns 2.07% of the Class A equity interests in Redbird and 100% of the Class B equity interests in Redbird.  As of December 31, 2011, Redbird owned an unconsolidated 40.08% interest in Cardinal.  These investments are accounted for by the equity method.

(2) SIGNIFICANT ACCOUNTING POLICIES

(a)   Principles of Presentation and Consolidation

The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees.  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.  In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”), 810-10 and to assess whether it is the primary beneficiary of such entities.  If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10.  No such variable interest entities exist as of December 31, 2011 or 2010.

The Partnership acquired the assets of Cross Oil Refining & Marketing Inc. (“Cross”) from Martin Resource Management in November 2009.  The acquisition of the Cross assets was considered a transfer of net assets between entities under common control.  The acquisition of the Cross assets and increase in partners’ capital for the common and subordinated units issued in November 2009 are recorded at amounts based on the historical carrying value of the Cross assets at that date, and the Partnership is required to revise its historical financial statements to include the activities of the Cross assets as of the date of common control.  Martin Resource Management acquired Cross in November 2006; however, the activity for the period Cross was owned by Martin Resource Management during 2006 was not considered significant to the Partnership’s consolidated financial statements and has been excluded from the consolidated financial statements.  The Partnership’s accompanying historical financial statements for the period January 1, 2009 through November 24, 2009 have been revised to reflect the financial position, cash flows and results of operations attributable to the Cross assets as if the Partnership owned the Cross assets for these periods.  Net income attributable to the Cross assets for periods prior to the Partnership’s acquisition of the assets is not allocated to the general and limited partners for purposes of calculating net income per limited partner unit.  See Note (2)(o).

As discussed in Note 6, 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 6 are collectively referred to as the "Prism Assets".  The Partnership has classified the Prism Assets, including related liabilities as held for sale at December 31, 2011 and 2010, respectively, and has presented the results of operations and cash flows as discontinued operations for the years ended December 31, 2011, 2010, and 2009, 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.

(b)           Product Exchanges

The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange NGLs and sulfur with third parties.  The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market.  Cost is determined using the first-in, first-out (“FIFO”) method.  Revenue and costs related to product exchanges are recorded on a gross basis.

(c)           Inventories

Inventories are stated at the lower of cost or market.  Cost is determined by using the FIFO method for all inventories.

10

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(d)           Revenue Recognition

Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or service is performed.  NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.

 Sulfur services – Revenue from sulfur product sales is recognized when the customer takes title to the product.  Revenue from sulfur services is recognized as deliveries are made during each monthly period.

Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip.  For time charters, revenue is recognized based on a per day rate.

(e)           Equity Method Investments

The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists.  Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions.  Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets.  Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually.  Under certain provisions of ASC 350-20, related to goodwill, this goodwill is not subject to amortization and is accounted for as a component of the investment.  Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock.  No portion of the net income from these entities is included in the Partnership’s operating income.

The Partnership’s Prism Gas subsidiary owns an unconsolidated 50% interest in Waskom, Matagorda, and PIPE. The Partnership owns 2.07% of the Class A equity interests in Redbird and 100% of the Class B equity interests in Redbird.  Redbird, as of December 31, 2011, owns a 40.08% interest in Cardinal Gas Storage Partners, LLC.  Each of these interests is accounted for under the equity method of accounting.

(f)           Property, Plant, and Equipment

Owned property, plant, and equipment is stated at cost, less accumulated depreciation.  Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.

Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized straight line over the estimated useful life of the asset.

Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized.  When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.

(g)           Goodwill and Other Intangible Assets

Goodwill represents the excess of costs over fair value of assets of businesses acquired.  Goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead, tested for impairment at least annually in accordance with certain provisions of ASC 350-20.  Intangible assets with estimated useful lives are amortized over their respective estimated useful lives to their estimated residual values and reviewed for impairment under certain provisions of ASC 360-10 related to accounting for impairment or disposal of long-lived assets.  Other intangible assets primarily consist of covenants not-to-compete and contracts obtained through business combinations and are being amortized over the life of the respective agreements.

Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets.  Goodwill is assigned to reporting units at the date the goodwill is initially recorded.  Once goodwill has been assigned to reporting units, it no longer retains its association with a particular acquisition, and all of the activities within a reporting unit, whether acquired or organically grown, are available to support value of the goodwill.

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 the quarterly report on Form 10-Q for the quarter ended September 30, 2011.

11

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

The Partnership performed the annual impairment tests as of August 31, 2011, September 30, 2010, and September 30, 2009, respectively.  In performing such tests, it was determined that there were four “reporting units” which contained goodwill. These reporting units were in each of the four reporting segments: terminalling and storage, natural gas services, marine transportation, and sulfur services.  The estimated fair value of the reporting units with goodwill were developed using the guideline public company method, the guideline transaction method, and the discounted cash flow (“DCF”) method using observable market data where available.  To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.  At August 31, 2011, September 30, 2010 and September 30, 2009, the estimated fair value of each of the four reporting units was in excess of its carrying value, which indicates no impairment existed.

(h)           Debt Issuance Costs

Debt issuance costs relating to the Partnership’s revolving credit facility and senior notes are deferred and amortized over the terms of the debt arrangements.

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $3,589, $7,468 and $10,446 in the years ended December 31, 2011, 2010 and 2009, respectively.

Due to a reduction in the number of lenders under the Partnership’s multi-bank credit agreement, $494, $634 and $495 of the existing debt issuance costs were determined not to have continuing benefit and were expensed during 2011, 2010 and 2009, respectively.  Remaining unamortized deferred issuance costs are amortized over the term of the revised debt arrangement.

Amortization of debt issuance costs, which is included in interest expense, totaled $3,755, $4,814 and $1,689 for the years ended December 31, 2011, 2010 and 2009, respectively.  Accumulated amortization amounted to $2,723 and $4,920 at December 31, 2011 and 2010, respectively.

     (i)           Impairment of Long-Lived Assets

In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.  Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and are no longer depreciated.  The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.  The Partnership has not identified any triggering events in 2011, 2010 or 2009 that would require an assessment for impairment of long-lived assets.

(j)           Asset Retirement Obligation

Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an Asset Retirement Obligation (“ARO”) at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset.  The Partnership’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment.

The transportation equipment includes pipeline systems.  The Partnership transports NGLs through the pipeline system and gathering system.  The Partnership also gathers natural gas from wells owned by producers and delivers natural gas and NGLs on the Partnership’s pipeline systems, primarily in Texas and Louisiana to the fractionation facility of the Partnership’s 50% owned joint venture.  The Partnership is obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of the Partnership’s assets.  However, the Partnership is not able to reasonably determine the fair value of the asset retirement obligations for the Partnership’s trunk and gathering pipelines and the Partnership’s surface facilities since future dismantlement and removal dates are indeterminate.  In order to determine a removal date of the Partnership’s gathering lines and related surface assets, reserve information regarding the production life of the specific field is required.  As a transporter and gatherer of natural gas, the Partnership is not a producer of the field reserves, and the Partnership therefore does not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which the Partnership gathers natural gas.  In the absence of such information, the Partnership is not able to make a reasonable estimate of when future dismantlement and removal dates of the Partnership’s gathering assets will occur.  With regard to the Partnership’s trunk pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease.  The Partnership’s right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe.  In addition, the Partnership can evaluate the Partnership’s trunk pipelines for alternative uses, which can be and have been found.  The Partnership will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations.

(k)           Derivative Instruments and Hedging Activities

In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included on the balance sheet as an asset or 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 other comprehensive income until such time as the hedged item is recognized in earnings.

Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations.  As of December 31, 2011, the Partnership has designated a portion of its derivative instruments as qualifying cash flow hedges.  Fair value changes for these hedges have been recorded in accumulated other comprehensive income as a component of equity.

12

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

                (l)           Comprehensive Income

Comprehensive income includes net income and other comprehensive income.  Other comprehensive income for the Partnership includes unrealized gains and losses on derivative financial instruments.  In accordance with ASC 815-10, the Partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

(m)           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 non-employee directors under its long-term incentive plan from treasury units 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.

In August 2009, the Partnership issued 1,000 restricted common units to each of its non-employee directors under its long-term incentive plan from treasury units purchased by the Partnership in the open market for $77. These units vest in 25% increments beginning in January 2010 and will be fully vested in January 2013.

In May 2008, the Partnership issued 1,000 restricted common units to each of its non-employee directors under its long-term incentive plan from treasury units purchased by the Partnership in the open market for $93.  These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.

The Partnership accounts for the transaction under certain provisions of FASB ASC 505-50-55 related to equity-based payments to non-employees.  The cost resulting from the unit-based payment transactions was $190, $113, and $98 for the years ended December 31, 2011, 2010 and 2009, respectively.

(n)           Incentive Distribution Rights

The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights in the Partnership.  Incentive distribution rights represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved.  The Partnership is required to distribute all of its available cash from operating surplus, as defined in the partnership agreement.  The target distribution levels entitle the general partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unit holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit.  For the years ended December 31, 2011, 2010 and 2009, the general partner received $4,901, $3,623, and $2,896 in incentive distributions.

13

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(o)           Net Income per Unit

ASC 260-10 relates to earnings per share, and 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. ASC 260-10 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.

The Partnership adopted the amended provisions of ASC 260-10 on January 1, 2009. Adoption did not impact the Partnership’s computation of earnings per limited partner unit as cash distributions exceeded earnings for the years ended December 31, 2011, 2010 and 2009, 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. The Partnership agreement does not explicitly limit distributions to the general partner; therefore, 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. For years ended December 31, 2011, 2010  and 2009, 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.

General and limited partner interest in net income includes only net income of the Cross assets since the date of acquisition in November 2009.   Accordingly, net income of the Partnership is adjusted to remove the net income attributable to the Cross assets prior to the date of acquisition and such income is allocated to Parent.  The recognition of the beneficial conversion feature for the period is considered a deemed distribution to the subordinated unit holders and reduces net income available to common limited partners in computing net income per unit.

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:

	Years Ended December 31,
	2011			2010			2009
Continuing operations:
Net income attributable to Martin Midstream Partners L.P.	$	14,950		$	7,961		$	16,935
Less pre-acquisition income allocated to Parent		—			—			1,664
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs		3,010			1,800			2,209
Distributions payable on behalf of general partner interest		825			590			724
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest		(587	)		(468	)		(455	)
Less beneficial conversion feature		680			551			85
Limited partners’ interest in net income	$	11,022		$	5,488		$	12,708

	Years Ended December 31,
	2011			2010			2009
Discontinued operations:
Net income attributable to Martin Midstream Partners L.P.	$	9,392		$	8,061		$	5,268
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs		1,891			1,823			687
Distributions payable on behalf of general partner interest		519			597			225
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest		(369	)		(473	)		(141	)
Less beneficial conversion feature		428			557			26
Limited partners’ interest in net income	$	6,923		$	5,557		$	4,471

    The weighted average units outstanding for basic net income per unit were 19,545,427, 17,525,089, and 14,680,807 for years ended December 31, 2011, 2010 and 2009, respectively.  For diluted net income per unit, the weighted average units outstanding were increased by 1,278, 900, and 3,968 units for the years ended December 31, 2011, 2010 and 2009, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

14

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(p)           Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services.  Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services.  Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2011, 2010 and 2009, the Conflicts Committee of our general partner approved reimbursement amounts of  $4,771, $3,791, and $3,542, respectively, reflecting our allocable share of such expenses.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

(q)           Environmental Liabilities and Litigation

The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable.  Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study.  Such accruals are adjusted as further information develops or circumstances change.  Costs of future expenditures for environmental remediation obligations are not discounted to their present value.  Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

(r)           Accounts Receivable and Allowance for Doubtful Accounts

     Trade accounts receivable are recorded at the invoiced amount and do not bear interest.  The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable.

(s)           Deferred Catalyst Costs

The cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 24 to 36 months.

(t)           Deferred Turnaround Costs

The Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 24 to 36 months.

(u)           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.

(v)           Income Taxes

With respect to the Partnership’s taxable subsidiary (Woodlawn Pipeline Co., Inc.) and the Cross assets prior to the date of acquisition, 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.

(w)           Prior Period Correction of an Immaterial Error

The statement of cash flows for the year ended December 31, 2010 has been revised to correct an immaterial error in the classification of excess purchase price over carrying value of acquired assets of $4,590.  The reclassification of this amount decreases acquisitions, net of cash acquired and net cash used in investing activities, increases the excess purchase price over carrying value of acquired assets and decreases net cash provided by financing activities, and had no effect on the Partnership’s cash and cash equivalents, property, plant and equipment, net income or partners’ capital.

15

(3)FAIR VALUE MEASUREMENTS

The Partnership follows the provisions of ASC 820 related to fair value measurements and disclosures, which established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of this guidance had no impact on the Partnership’s financial position or results of operations.

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 14 for further information on the Partnership’s derivative instruments and hedging activities.

The following items are measured at fair value on a recurring basis and are 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	$	—

16

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

The following items are measured at fair value on a recurring basis and are subject to the disclosure requirements of ASC 820 at December 31, 2010:

	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, 2010		(Level 1)		(Level 2)		(Level 3)
Assets
Interest rate derivatives	$	1,941	$	—	$	1,941	$	—
Natural gas derivatives		201		—		201		—
Total assets	$	2,142	$	—	$	2,142	$	—
Liabilities
Interest rate derivatives	$	3,930	$	—	$	3,930	$	—
Natural gas derivatives		28		—		28		—
Crude oil derivatives		177		—		177		—
Natural gas liquids derivatives		247		—		247		—
Total liabilities	$	4,382	$	—	$	4,382	$	—

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

• Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable and due from/to affiliates — The carrying amounts approximate fair value because of the short maturity of these instruments.

• Long-term debt including current installments — The carrying amount of the revolving and term loan facilities approximates fair value due to the debt having a variable interest rate.  The estimated fair value of the Senior Notes was approximately $210,500 as of December 31, 2011, based on market prices of similar debt at December 31, 2011.

(4)RECENT ACCOUNTING PRONOUNCEMENTS

In September 2011, the FASB amended the provisions of ASC350 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.

17

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(5)  ACQUISITIONS

Redbird Gas Storage

On May 31, 2011, the Partnership acquired all of the Class B equity interests in 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.  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. In addition to owning all of the Class B equity interests of Redbird, the Partnership also owns 2.07% of the Class A equity interests of Redbird at December 31, 2011.   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 credit facility.

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, 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 $4,395 was recorded as a reduction of partners’ capital.  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 revolving credit facility.

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

18

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

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 20 years.

Harrison Gathering System

On January 15, 2010, the Partnership, through 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 (in discontinued operations).

(6)  DISCONTINUED OPERATIONS AND DIVESTITURES

On June 18, 2012, the Partnership and a subsidiary of CenterPoint Energy Inc. (NYSE: CNP), (“CenterPoint”) entered into a definitive agreement under which CenterPoint would acquire the Partnership’s 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, for cash in a transaction valued at approximately $275,000 excluding any transaction costs and purchase price adjustments.  The asset sale includes the Partnership’s 50% operating interest in Waskom Gas Processing Company (“Waskom”).  A subsidiary of CenterPoint currently owns the other 50% interest.  On July 31, 2012, the Partnership completed the sale of its East Texas and Northwest Louisiana natural gas gathering and processing assets for net cash proceeds of $273,300.

Additionally, the Partnership has reached agreement with a private investor group to sell its interest in Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”) for $2,000 in cash.  This sale is expected to be completed in the third quarter of 2012.

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

The Partnership has 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 statements of operations for all periods presented. The assets and liabilities described above have been classified as held for sale and have been aggregated and reported on separate lines in the consolidated balance sheets for all periods presented.

The assets and liabilities held for sale as of December 31, 2011 and 2010 were as follows:

	2011			2010
Assets
Inventories	$	486		$	750
Property, plant and equipment		78,324			77,039
Accumulated depreciation		(18,438	)		(14,039	)
Goodwill		28,931			28,931
Investment in unconsolidated entities		107,549			98,217
Other assets, net		15,935			17,027
Assets held for sale	$	212,787		$	207,925
Liabilities
Other long-term obligations		501			480
Liabilities held for sale	$	501		$	480

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

	Year Ended December 31,
	2011			2010			2009
Total revenues from third parties1	$	121,338		$	112,477		$	71,141
Total costs and expenses and other, net, excluding depreciation and amortization		(115,957	)		(110,061	)		(69,914	)
Depreciation and amortization		(5,512	)		(4,452	)		(3,963	)
Other operating income		—			(92	)		(12	)
Equity in earnings of unconsolidated entities2		9,412			9,792			7,044
Income from discontinued operations before income taxes		9,281			7,664			4,296
Income tax expense (benefit)		(111	)		(397	)		(972	)
Income from discontinued operations, net of income taxes	$	9,392		$	8,061		$	5,268

1 Total revenues from third parties excludes intercompany revenues of $67,141, $56,390, and $45,998 for the years ended December 31, 2011, 2010 and 2009, respectively.

2  Represents equity in earnings of Waskom, Matagorda, and PIPE for the years ended December 31, 2011, 2010, and 2009.

19

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(7)  ISSUANCE OF COMMON UNITS

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).  Following this offering, the common units represented a 95.7% limited partnership interest in the Partnership.  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.  On February 9, 2011, the Partnership made a $65,500 payment to reduce the outstanding balance under its revolving credit facility.

On August 17, 2010, the Partnership completed a public offering of 1,000,000 common units, representing limited partner interests at a purchase price of $29.13 per common unit.  The Partnership received net proceeds of approximately $28,070 after payment of underwriters’ discounts.  The Partnership used the net proceeds of $28,070 to redeem from subsidiaries of Martin Resource Management an aggregate number of common units equal to the number of common units issued in the offering.   Martin Resource Management reimbursed the Partnership for its payments of commissions and offering expenses.   As a result of these simultaneous transactions, the Partnership’s  general partner was not required to contribute cash to the Partnership in conjunction with the issuance of these units in order to maintain its 2% general partner interest in the Partnership since there was no net increase in the outstanding limited partner units.

On February 8, 2010, the Partnership completed a public offering of 1,650,000 common units at a price of $32.35 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands).  Following this offering, the common units represented a 93.3% limited partner interest in the Partnership.  Total proceeds from the sale of the 1,650,000 common units, net of underwriters’ discounts, commissions and offering expenses were $50,530.  The Partnership’s general partner contributed $1,089 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership.  On February 8, 2010, the Partnership reduced the outstanding balance under its revolving credit facility by $45,000.

(8)  INVENTORIES

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

	2011		2010
Natural gas liquids	$	25,178	$	19,025
Sulfur		24,335		15,820
Sulfur Based Products		14,857		9,140
Lubricants		11,012		5,267
Other		2,295		2,613
	$	77,677	$	51,865

(9)  PROPERTY, PLANT AND EQUIPMENT

At December 31, 2011 and 2010, property, plant, and equipment consisted of the following:

	Depreciable Lives		2011		2010
Land		—	$	19,432	$	20,186
Improvements to land and buildings	10-25 years			73,298		53,521
Transportation equipment	3-7 years			1,759		1,727
Storage equipment	5-20 years			67,360		62,372
Marine vessels	4-25 years			228,043		226,376
Operating equipment	3-20 years			189,065		177,228
Furniture, fixtures and other equipment	3-20 years			1,862		1,209
Construction in progress				51,909		12,798
			$	632,728	$	555,417

Depreciation expense for the year ended December 31, 2011, 2010, and 2009 was $37,038, $34,116, and $33,431, respectively, which includes amortization of fixed assets acquired under capital lease obligations of $280, $280, and $116 for 2011, 2010, and 2009, respectively.  Gross assets under capital leases were $7,764 at December 31, 2011 and 2010.  Accumulated amortization associated with capital leases was $675 and $396 at December 31, 2011 and 2010, respectively.

 (10)  GOODWILL AND OTHER INTANGIBLE ASSETS

At December 31, 2011 and 2010, goodwill balances consisted of the following:

	2011		2010
Carrying amount of goodwill:
Terminalling and storage	$	883	$	883
Natural gas services		79		79
Sulfur services		5,349		5,349
Marine transportation		2,026		2,026
		8,337		8,337
Goodwill classified as held for sale		28,931		28,931
Total goodwill	$	37,268	$	37,268

20

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

Other intangible assets subject to amortization consist of covenants not-to-compete, customer contracts associated with gathering and processing assets and a transportation contract associated with the residue gas pipeline.

The unamortized balance of other intangible assets, classified in the consolidated balance sheets as other assets, net, amounted to $338 and $477 at December 31, 2011 and 2010, respectively.  The unamortized balance of other intangible assets, net, classified in the consolidated balance sheets as assets held for sale, amounted to $15,935 and $17,027 at December 31, 2011 and 2010, respectively.

Aggregate amortization expense for amortizing intangible assets included in continuing operations was $140, $226, and $336, for the years ended December 31, 2011, 2010 and 2009, respectively, and accumulated amortization amounted to $1,060 and $920 at December 31, 2011 and 2010, respectively.

Estimated amortization expenses for the years subsequent to December 31, 2011 are as follows:  2012 - $140; 2013 - $140; 2014 - $58; 2015 - $0; 2016 - $0; subsequent years - $0.

(11)  LEASES

The Partnership has numerous non-cancelable operating leases primarily for transportation and other equipment.  The leases generally provide that all expenses related to the equipment are to be paid by the lessee.  Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements.  The Partnership also has cancelable operating lease land rentals and outside marine vessel charters.  Certain of our marine vessels have been acquired under capital leases.

The Partnership’s future minimum lease obligations as of December 31, 2011 consist of the following:

Fiscal year	Operating Leases		Capital Leases
2012	$	11,776	$	1,138
2013		7,975		1,147
2014		7,015		1,169
2015		6,297		1,169
2016		5,564		5,465
Thereafter		8,738		—
Total	$	47,365		10,088
Less amounts representing interest costs				4,057
Present value of net minimum capital lease payments				6,031
Less current installments				193
Present value of net minimum capital lease payments, excludingcurrent installments			$	5,838

Rent expense for operating leases for the years ended December 31, 2011, 2010 and 2009 was $19,280, $15,710 and $11,158, respectively.  The amount recognized in interest expense for capital leases was $972, $991, and $250 for the years ended December 31, 2011, 2010 and 2009, respectively.

 (12)  INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES

At December 31, 2011, the Partnership’s Prism Gas subsidiary owned an unconsolidated 50% interest in Waskom, the Matagorda and PIPE.

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 $594 for the years ended December 31, 2011, 2010 and 2009, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated equity method investees.  The remaining unamortized excess investment relating to property and equipment was $8,310, $8,903 and $9,497 at December 31, 2011, 2010 and 2009, respectively.  The equity-method goodwill is not amortized; however, it is analyzed for impairment annually or if changes in circumstance indicate that a potential impairment exists. No impairment was recorded in 2011, 2010 or 2009.

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 2.07% of the Class A equity interests and all the Class B equity interests in Redbird.  Redbird owns an unconsolidated 40.08% interest in Cardinal.   Redbird utilized the investments by the Partnership to invest in Cardinal to fund projects for natural gas storage facilities.

These investments are accounted for by the equity method.

21

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

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

	December 31, 2011		December 31, 2010
Investment in Waskom1	$	102,896	$	93,768
Investment in PIPE1		1,291		1,311
Investment in Matagorda1		3,362		3,138
Investment in unconsolidated entities classified as assets held for sale		107,549		98,217
Investment in Redbird		62,948		—
Investment in unconsolidated entities		62,948		—
Total Investment in unconsolidated entities	$	170,497	$	98,217

1 For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated balance sheets as assets held for sale, and on the consolidated statements of operations and cash flows as discontinued operations.

	Years Ended December 31,
	2011			2010			2009
Equity in earnings of Waskom1	$	9,143		$	9,831		$	6,384
Equity in earnings of PIPE1		(45	)		(180	)		587
Equity in earnings of Matagorda1		314			141			153
Equity in earnings of BCP		—			—			(80	)
Equity in earnings of discontinued operations		9,412			9,792			7,044
Equity in earnings of Redbird		124			—			—
Equity in earnings of unconsolidated entities		124			—			—
Total equity in earnings of unconsolidated entities	$	9,536		$	9,792		$	7,044

1 For all periods presented, the financial information for Waskom, Matagorda, and PIPE is included in the consolidated balance sheets as assets held for sale, and on the consolidated statements of operations and cash flows as discontinued operations.

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

	As of December 31,				Years ended December 31,
	Total Assets		Partners’ Capital		Revenues		Net Income
2011
Waskom	$	146,655	$	126,863	$	129,119	$	19,385
2010
Waskom	$	122,057	$	107,508	$	124,122	$	20,762
2009
Waskom	$	79,604	$	70,561	$	71,044	$	13,867

As of December 31, 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 $47,152 and $40,509, 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 December 31, 2011 and 2010, the Partnership’s interest in cash of the unconsolidated equity method investees is $565 and $789, respectively.

22

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(13)  LONG-TERM DEBT AND CAPITAL LEASES

At December 31, 2011 and December 31, 2010, long-term debt consisted of the following:

	December 31,  2011		December 31, 2010
$200,000 Senior notes, 8.875% interest, net of unamortized discount of $2,192 and $2,543, respectively, issued March 2010 and due April 2018, unsecured**	$	197,808	$	197,457
$375,000 Revolving loan facility at variable interest rate (2.81%* weighted average at December 31, 2011), 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***		250,000		163,000
$7,354 Note payable to bank, interest rate at 7.50%, maturity date of   January 2017, secured by equipment		6,363		7,354
Capital lease obligations		6,031		6,172
Total long-term debt and capital lease obligations		460,202		373,983
Less current installments		1,261		1,121
Long-term debt and capital lease obligations, net of current installments	$	458,941	$	372,862

* 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 2.50%.  Effective January 1, 2012, the applicable margin for existing LIBOR borrowings increased to 2.75%.  Effective April 1, 2012, the applicable margin for existing LIBOR borrowings will increase to 3.00%.

** 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.

*** Effective October 2008, the Partnership entered into a cash flow hedge that swapped $40,000 of floating rate to fixed rate. The fixed rate cost was 2.820% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 2.580% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in October 2010, but were terminated in March 2010.

*** Effective January 2008, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to fixed rate. The fixed rate cost was 3.400% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 3.050% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges matured in January 2010.

*** Effective September 2007, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to fixed rate. The fixed rate cost was 4.605% plus the Partnership’s applicable LIBOR borrowing spread. Effective March 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 4.305% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in September 2010, but were terminated in March 2010.

*** Effective November 2006, the Partnership entered into an interest rate swap that swapped $30,000 of floating rate to fixed rate. The fixed rate cost was 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This cash flow hedge matured in March 2010.

*** Effective March 2006, the Partnership entered into a cash flow hedge that swapped $75,000 of floating rate to fixed rate. The fixed rate cost was 5.25% plus the Partnership’s applicable LIBOR borrowing spread. Effective February 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 5.10% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in November 2010, but were terminated in March 2010.

23

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(a)Senior Notes

In March 2010, the Partnership and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of the Partnership (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 $200,000 in aggregate principal amount of the Issuers’ 8.875% senior unsecured notes due 2018 (the “Senior Notes”).  The Partnership completed the aforementioned Senior Notes offering on March 26, 2010, and received proceeds of approximately $197,200, after deducting initial purchasers’ discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership’s revolving credit facility.

In connection with the issuance of the Senior Notes, all “non-issuer” wholly-owned subsidiaries of the Partnership issued full, irrevocable, and unconditional guarantees of the Senior Notes.  As discussed in Note 22, the Partnership does not provide separate financial statements of the Martin Operating Partnership L.P. (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.

Indenture.   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.

Interest and Maturity.  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 12-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.

Certain Covenants.  The Indenture restricts the Partnership’s ability and the ability of certain of its 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 the Partnership; (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) failure by the Partnership to comply with certain covenants relating to asset sales, repurchases of the Senior Notes upon a change of control and mergers or consolidations; (iv) failure by the Partnership for 180 days after notice to comply with its reporting obligations under the Securities Exchange Act of 1934; (v) failure by the Partnership 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 the Partnership or any of its 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 $20,000 or more, subject to a cure provision; (vii) failure by the Partnership or any of its restricted subsidiaries to pay final judgments aggregating in excess of $20,000, 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 the Partnership’s restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership. 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 the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, 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 an offer to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. The Partnership exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018.

24

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(b)           Credit Facility

On November 10, 2005, the Partnership entered into a multi-bank credit facility, which has subsequently been amended including most recently on September 7, 2011 (the “Credit Facility”), when the Partnership amended the Credit Facility to (1) increase the maximum amount of investments made in permitted joint ventures to $50,000,  and (2) increase the maximum amount of investments made in Redbird and Cardinal to $120,000.  Additionally, effective December 5, 2011, the Partnership increased the maximum amount of borrowings and letters of credit available under the Credit Facility from $350,000 to $375,000.

Under the Credit Facility, as of December, 2011, the Partnership had $250,000 outstanding under the revolving Credit Facility.  As of December 31, 2011, irrevocable letters of credit issued under the Credit Facility totaled $120. As of December 31, 2011, the Partnership had $124,880 available under its revolving Credit Facility.  The 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 the Credit Facility ranged from a low of $135,000 to a high of $272,000.

The Partnership’s obligations under the Credit Facility are secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time without penalty.

In addition, the Credit Facility contains various covenants, which, among other things, limit the Partnership’s ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell all or substantially all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) incur indebtedness or grant certain liens through its joint ventures.

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 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 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.  The Partnership was in compliance with the covenants contained in the Credit Facility as of December 31, 2011.

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

The Partnership is required to make certain prepayments under the Credit Facility.  If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the Credit Facility, it must prepay indebtedness under the Credit Facility with all such proceeds in excess of $15,000. The Partnership must prepay revolving loans under the Credit Facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the Credit Facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the Credit Facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by April 15, 2016. The Credit Facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

In March 2010, the Partnership terminated all of its existing interest rate swaps resulting in termination fees of $3,850.  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.

The Partnership paid cash interest in the amount of $22,818, $23,663, and $18,291 for the years ended December 31, 2011, 2010, and 2009, respectively.  Capitalized interest was $589, $130, and $259 for the years ended December 31, 2011, 2010, and 2009, respectively.

 (14)  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 December 31, 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.

25

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

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 and 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.

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.

As of December 31, 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 December 31, 2011 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of December 31, 2011, the remaining term of the contracts extend no later than December 2012, with no single contract longer than one year. For the years ended December 31, 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::
Natural Gasoline Swap	1,000 BBL	Fixed price of $90.20/bbl settled against WTI NYMEX average monthly closings	January 2012 to December 2012	$	(104	)
Natural Gasoline Swap	1,000 BBL	Fixed price of $2.34/gal settled against Mont Belvieu Non-TET OPIS Average	January 2012 to December 2012		(13	)
Total commodity swaps not designated as hedging instruments				$	(117	)
Cash Flow Hedges:
Natural Gas Swap	10,000 Mmbtu	Fixed price of $4.87/Mmbtu settled against IF_ANR_LA first of the month posting	January 2012 to December 2012		200
Natural Gas Swap	20,000 Mmbtu	Fixed price of $4.96/Mmbtu settled against IF_ANR_LA first of the month posting	January 2012 to December 2012		422
Crude Oil Swap	2,000 BBL	Fixed price of $88.63/bbl settled against WTI NYMEX average monthly closings	January 2012 to December 2012		(245	)
Total commodity swaps designated as hedging instruments				$	377
Total net fair value of commodity derivatives				$	260

Based on estimated volumes, as of December 31, 2011, the Partnership had hedged approximately 49% and 34% 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.

26

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

The Partnership’s credit exposure related to commodity cash flow hedges is represented by the positive fair value of contracts to the Partnership at December 31, 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 counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes 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 two 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 December 31, 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 allow 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.

Impact of Commodity Cash Flow Hedges

Crude Oil

For the years ended December 31, 2011, 2010 and 2009, net gains and losses on swap hedge contracts increased crude revenue (included in income from discontinued operations) by $775 and $27, and decreased crude revenue by $854, respectively.  As of December 31, 2011, an unrealized derivative fair value loss of $245 related to cash flow hedges of crude oil price risk was recorded in AOCI.  A fair value loss of $245 is expected to be reclassified into earnings in 2012.  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

For the years ended December 31, 2011, 2010 and 2009, net gains and losses on swap hedge contracts increased gas revenue (included in income from discontinued operations) by $332, $601, and $1,824, respectively. As of December 31, 2011, an unrealized derivative fair value gain of $611 related to cash flow hedges of natural gas was recorded in AOCI. A fair value gain of $611 is expected to be reclassified into earnings in 2012. 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 years ended December 31, 2011, 2010 and 2009, net gains and losses on swap hedge contracts increased liquids revenue (included in income from discontinued operations) by $254 and $207, and decreased liquids revenue by $186, respectively. As of December 31, 2011, an unrealized derivative fair value gain of $260 related to cash flow hedges of natural gas liquids price risk was recorded in AOCI. A fair value gain of $260 is expected to be reclassified into earnings in 2012. The actual reclassification to earnings for contracts remaining in effect 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.

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 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.  A termination benefit of $2,800 was 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 increases in interest expense of $5,779, $6,327 and $7,892 for the years ended December 31, 2011, 2010 and 2009, 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.

27

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

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 our derivative instruments in our Consolidated Balance Sheet:

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
		December 31,					December 31,
	Balance Sheet Location	2011		2010		Balance Sheet Location	2011		2010
Derivatives designated as hedging instruments:	Current Assets:					Current Liabilities:
Interest rate contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	—
Commodity contracts	Fair value of derivatives		622		201	Fair value of derivatives		245		230
			622		201			245		230
	Non-current Assets:					Non-current Liabilities:
Interest rate contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		—
Commodity contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		171
			—		—			—		171
Total derivatives designated as hedging instruments		$	622	$	201		$	245	$	401
Derivatives not designated as hedging instruments:	Current Assets:					Current Liabilities:
Interest rate contracts	Fair value of derivatives	$	—	$	1,941	Fair value of derivatives	$	—	$	—
Commodity contracts	Fair value of derivatives		—		—	Fair value of derivatives		117		51
			—		1,941			117		51
	Non-current Assets:					Non-current Liabilities:
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		$	—	$	2,142		$	117	$	3,981

Effect of Derivative Instruments on the Consolidated Statement of Operations For the Years Ended December 31, 2011, 2010 and 2009
									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			2009				2011			2010			2009				2011		2010		2009
Derivatives designated as hedging instruments:
Interest rate contracts	$	—		(241	)	$	(1,854	)	Interest Expense	$	(18	)	$	(4,210	)	$	(7,345	)	Interest Expense	$	—	$	—	$	—
Commodity contracts		1,011		143			14		Income from discontinued operations		1,785			547			2,667		Income from discontinued operations		37		70		(21	)
Total derivatives designated as hedging instruments	$	1,011	$	(98	)	$	(1,840	)		$	1,767		$	(3,663	)	$	(4,678	)		$	37	$	70	$	(21	)

Amounts expected to be reclassified into earnings for the subsequent twelve month period are losses of $0 for interest rate cash flow hedges and gains of $626 for commodity cash flow hedges.

28

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(15)  RELATED PARTY TRANSACTIONS

As of December 31, 2011, Martin Resource Management owns 6,593,267 of the Partnership’s common units representing approximately 32.2% 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 general partner’s ability to manage and operate the Partnership and Martin Resource Management’s ownership as of December 31, 2011 of approximately 32.2% 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 agreements:

Omnibus Agreement

            Omnibus Agreement.   The Partnership and its general partner are parties to an omnibus agreement dated November 1, 2002 with Martin Resource Management (the “Omnibus Agreement”) that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks. 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.

Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls our general partner, 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 our behalf of any asset or group of assets owned by us or our affiliates;

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

o   providing land transportation of various liquids,

o   distributing fuel oil, sulfuric acid, marine fuel and other liquids,

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

o   operating a crude oil gathering business in Stephens, Arkansas,

o   operating an underground NGL storage facility in Arcadia, Louisiana,

o   building and marketing sulfur processing equipment, and

o   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 $5.0 million;

·   any business that Martin Resource Management acquires or constructs that has a fair market value of $5.0 million 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 $5.0 million 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 us with corporate staff, support services, and administrative services necessary to operate our business. 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. 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, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses under the Omnibus Agreement.

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 $4.8, $3.8, and $3.5 million of indirect expenses for the years ending December 31, 2011, 2010, and 2009, 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 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 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 our general partner.

29

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

Related Party Transactions. The Omnibus Agreement prohibits us from entering into any material agreement with Martin Resource Management without the prior approval of the conflicts committee of our 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 us 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 our general partner if such amendment would adversely affect the unitholders. The Omnibus Agreement was amended on November 24, 2009 to permit us to provide refining services to Martin Resource Management.  Such amendment was approved by the conflicts committee of our 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 our 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 us and Martin Transport, Inc. for land transportation services.  Under the agreement, Martin Transport Inc. agrees 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 United States 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 market rates for marine transportation services.

Cross Marine Charter Agreements. Cross entered into four marine charter agreements with the Partnership effective March 1, 2007.  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 United States 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 we charge 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.

30

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

Other Agreements

 Cross Tolling Agreement. We are party to an agreement under which we process crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The Tolling Agreement has a 12 year term which expires November 24, 2021.   Under this Tolling Agreement, Martin Resource Management agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a fixed price per barrel.  Any additional barrels are refined at a modified price per barrel.  In addition, Martin Resource Management agrees 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, and which is not consumed by the Partnership’s internal operations.  This agreement, which was amended and restated in August 2008, 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:

Revenues:	2011		2010		2009
Terminalling and storage	$	54,211	$	46,823	$	19,998
Marine transportation		23,478		28,194		19,370
Product sales:
Natural gas services		716		591		238
Sulfur services		8,151		7,146		5,445
Terminalling and storage		214		166		155
		9,081		7,903		5,838
	$	86,770	$	82,920	$	45,206

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	$	16,749	$	7,517	$	8,343
Sulfur services		18,314		16,061		12,583
Terminalling and storage		195		298		287
	$	35,258	$	23,876	$	21,213

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

Operating expenses
Marine transportation	$	29,870	$	26,730	$	20,464
Natural gas services		1,590		1,349		1,491
Sulfur services		6,573		5,271		4,496
Terminalling and storage		20,018		15,040		10,833
	$	58,051	$	48,390	$	37,284

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	$	65	$	—	$	—
Natural gas services		1,069		1,048		1,116
Sulfur services		2,704		2,398		2,504
Indirect overhead allocation, net of reimbursement		4,772		3,791		3,542
	$	8,610	$	7,237	$	7,162

The amount of related party interest expense reflected in the consolidated financial statement is $0, $0 and $872 for the years ending December 31, 2011, 2010 and 2009, respectively.

31

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

 (16)  PARTNERS’ CAPITAL

As of December 31, 2011, partners’ capital consists of 20,471,776 common limited partner units, representing a 98% partnership interest and a 2% general partner interest.  Martin Resource Management, through subsidiaries, owned an approximate 31.6% limited partnership interest consisting of 6,593,267 common limited partner units and a 2% general partner interest as of December 31, 2011.

The Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

Distributions of Available Cash

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

(17)  GAIN ON DISPOSAL OF ASSETS

On April 30, 2009, the Partnership sold certain assets comprising the Mont Belvieu railcar unloading facility, which yielded net proceeds from the sale in the amount of $19,610. The assets sold related to twenty railcar spaces and a newly constructed major expansion that had not been placed in operation. The disposition was comprised of property, plant and equipment and allocated goodwill included in the Partnership’s terminalling segment with an aggregate carrying value of $14,329. This transaction yielded a gain on the sale of property, plant, and equipment in the amount of $5,281. The gain is included in “other operating income” in the consolidated statement of operations for the year ending December 31, 2009.

In September 2010, the Partnership received $349 from an indemnity escrow.  The gain is included in “other operating income” in the consolidated statement of operations for the year ended December 31, 2010.  Additionally, the Partnership expects to receive payment of $375 in April 2012, which represents payment from an indemnity escrow resulting from the sale. The Partnership expects to record this amount as a gain in the respective quarter.  The Partnership paid down the outstanding revolving loans under its credit facility with the net cash proceeds from this sale of assets. The amount paid down is available for future borrowings under the revolving credit facility.

 (18)  STANOLIND TANK DAMAGE

During the third quarter of 2011, a single tank fire occurred at the Partnership’s Stanolind Terminal in Beaumont, Texas.  This specific tank stores No. 6 oil for Martin Resource Management under a through-put agreement.  The tank contained approximately 3,200 barrels of No. 6 oil at the time the incident occurred, all of which is the property of Martin Resource Management. 

Physical damage to the Partnership’s asset caused by the fire as well as the related removal and recovery costs, are fully covered by the Partnership’s non-windstorm insurance policy subject to a deductible of $443, which has been expensed and included in “operating expenses” in the consolidated statements of operations for the year ended December 31, 2011.  

Insurance proceeds received as a result of the this claim will be used to replace the tank and, in the event the proceeds exceed the net book value of the tank that was destroyed, the Partnership will recognize a gain equal to the amount of the excess.

The costs incurred to reconstruct tank No. 6 for the year ended December 31, 2011 was $678.

32

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(19)  INCOME TAXES

The operations of a partnership are generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners.  Effective January 1, 2007, the Partnership became subject to the Texas margin tax as described below.

Woodlawn, a subsidiary of the Partnership, is subject to income taxes due to its corporate structure.  Income tax expense related to Woodlawn is recorded in discontinued operations.  A current federal income tax expense of $11, and a current federal income tax benefit of $0 and $1,061, related to the operation of the subsidiary, were recorded for the years ended December 31, 2011, 2010 and 2009, respectively.  In connection with the Woodlawn acquisition, the Partnership also established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities.  The basis differences are primarily related to property, plant and equipment.

The activities of the Cross assets prior to the acquisition by the Partnership were subject to federal and state income taxes.  Accordingly, income taxes have been included in the Cross assets operating results from January 1, 2009 through November 24, 2009.  Related payables/receivables are included in Due to affiliates and Other current assets, respectively, on the consolidated balance sheet.

A deferred tax benefit of $139 and $415 and a deferred tax expense of $90 related to the Woodlawn basis differences was recorded for the years ended December 31, 2011, 2010 and 2009, respectively.  A deferred tax expense of $204 related to the Cross basis differences was recorded for the year ended December 31, 2009. A deferred tax liability of $7,657 and $8,213 related to these basis differences existed at December 31, 2011 and 2010, respectively.

Beginning in 2007, the Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new “taxable margin” component.  Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.   State income taxes attributable to the Texas margin tax of $713, $932 and $422 were recorded in income tax expense for the years ended December 31, 2011, 2010 and 2009, respectively.

An income tax receivable of $760 is included in other current assets at December 31, 2010 and 2009.  An income tax liability of $893, $811 and $454 existed at December 31, 2011, 2010 and 2009, respectively.

     The components of income tax expense (benefit) from operations recorded for the years ended December 31, 2011, 2010 and 2009 are as follows:

	2011			2010			2009
Current:
Federal	$	11		$	—		$	(311	)
State		713			932			609
		724			932			298
Deferred:
Federal		(139	)		(415	)		294
Total income tax expense (benefit)	$	585		$	517		$	592

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

Income tax expense (benefit) from continuing operations:

	2011		2010		2009
Current:
Federal	$		$	—	$	750
State		696		914		610
Deferred:		696		914		1,360
Federal		-		-		204
Total income tax expense (benefit) from continuing operations	$	696	$	914	$	1,564

Income tax expense (benefit) from discontinued operations:

	2011			2010			2009
Current:
Federal	$	11		$	—		$	(1,061	)
State		17			18			(1	)
		28			18			(1,062	)
Deferred:
Federal		(139	)		(415	)		90
Total income tax expense (benefit) from discontinued operations	$	(111	)	$	(397	)	$	(972	)

33

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(20)  BUSINESS SEGMENTS

The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services.  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 of the Notes to Consolidated Financial Statements. 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 6.

	Operating Revenues		Intersegment Eliminations			Operating Revenues After Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures
Year ended December 31, 2011:
Terminalling and storage	$	156,420	$	(4,414	)	$	152,006	$	18,983	$	13,074		$	43,795
Natural gas services		611,749		—			611,749		578		7,487			620
Sulfur services		275,044		—			275,044		6,725		34,595			16,158
Marine transportation		83,971		(7,035	)		76,936		13,159		(6,485	)		12,137
Indirect selling, general, and administrative		—		—			—		—		(8,864	)		—
Total	$	1,127,184	$	(11,449	)	$	1,115,735	$	39,445	$	39,807		$	72,710
Year ended December 31, 2010:
Terminalling and storage	$	119,270	$	(4,354	)	$	114,916	$	16,650	$	14,256		$	6,996
Natural gas services		442,005		—			442,005		571		7,744			257
Sulfur services		165,078		—			165,078		6,262		20,166			7,107
Marine transportation		82,635		(4,993	)		77,642		12,721		6,524			2,159
Indirect selling, general, and administrative		—		—			—		—		(6,386	)		—
Total	$	808,988	$	(9,347	)	$	799,641	$	36,204	$	42,304		$	16,519
Year ended December 31, 2009:
Terminalling and storage	$	109,513	$	(4,219	)	$	105,294	$	15,717	$	17,899		$	18,426
Natural gas services		337,848		(7	)		337,841		564		8,413			—
Sulfur services		79,631		(2	)		79,629		6,151		13,776			7,909
Marine transportation		72,103		(3,623	)		68,480		13,111		3,156			4,523
Indirect selling, general, and administrative		—		—			—		—		(6,077	)		—
Total	$	599,095	$	(7,851	)	$	591,244	$	35,543	$	37,167		$	30,858

Revenues from one customer in the natural gas services segment were $137,177, $92,265 and $72,492 for the years ended December 31, 2011, 2010 and 2009, respectively.  Revenues from one customer in the sulfur services segment were $111,172, $50,357 and $9,748 for the years ended December 31, 2011, 2010 and 2009, respectively.

The Partnership's assets by reportable segment, which exclude assets held for sale of $212,787 and $207,925, respectively, as of December 31, 2011 and 2010, respectively, are as follows:

	2011		2010
Total assets:
Terminalling and storage	$	231,764	$	188,234
Natural gas services		198,845		106,890
Sulfur services		162,289		138,224
Marine transportation		143,424		144,205
Total assets	$	736,322	$	577,553

34

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(21)  QUARTERLY FINANCIAL INFORMATION

CONSOLIDATED QUARTERLY INCOME STATEMENT INFORMATION

	(Unaudited)
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2011
Revenues	$	252,980	$	260,057	$	287,596		$	315,102
Operating Income		13,454		10,169		7,679			8,505
Equity in earnings of unconsolidated entities		—		153		(53	)		24
Income from continuing operations		4,889		5,740		3,134			1,187
Income from discontinued operations		2,433		3,030		2,265			1,664
Net income		7,322		8,770		5,399			2,851
Net income per limited partner unit	$	0.31	$	0.37	$	0.20		$	0.06
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2010
Revenues	$	216,064	$	182,848	$	168,413		$	232,316
Operating Income		8,159		9,113		8,266			16,766
Equity in earnings of unconsolidated entities		—		—		—			—
Income from continuing operations		50		608		2,065			5,238
Income from discontinued operations		1,721		2,469		2,572			1,299
Net income		1,771		3,077		4,637			6,537
Net income per limited partner unit	$	0.04	$	0.10	$	0.19		$	0.30

35

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

(22)  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 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 and is set for trial in May of 2012 but is currently 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 and such appeal is still pending.

36

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)

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. 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, 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. 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.

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

(23)  CONSOLIDATING FINANCIAL STATEMENTS

            In connection with the Partnership’s filing of a shelf registration statement on Form S-3 with the Securities and Exchange Commission (the “Registration Statement”), Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, may issue unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time under the Registration Statement. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities under the Registration Statement 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.

(24)  SUBSEQUENT EVENTS

Public 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 $91,391.  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.

Divestiture of Natural Gas Gathering and Processing Assets.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 to CenterPoint as described in Note 6 for net cash proceeds of $273,300.  The asset sale includes the Partnership’s 50% operating interest in Waskom.  A subsidiary of CenterPoint currently owns the other 50% interest.