MARTIN MIDSTREAM PARTNERS L.P. - FORM 8-K - EX-99.2 - PART II, ITEM 7. MD&A

Attached files

file	filename
8-K - 10-K - MARTIN MIDSTREAM PARTNERS L.P.	form8-k.htm
EX-23.1 - CONSENT OF INDPENDENT REGISTERED ACCOUNTING FIRM - MARTIN MIDSTREAM PARTNERS L.P.	exhibit23-1.htm
EX-99.3 - PART II, ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATE, UPDATED - MARTIN MIDSTREAM PARTNERS L.P.	exhibit99-3.htm
EX-99.1 - PART II, ITEM 6. SELECTED FINANCIAL DATA, UPDATED - MARTIN MIDSTREAM PARTNERS L.P.	exhibit99-1.htm

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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%.

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.

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 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.

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.

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.

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.

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.

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.

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.

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.

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

—

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.

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