Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2011

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

For the transition period from ____________ to ____________

Commission File Number

000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

05-0527861
(IRS Employer

Identification No.)

4200 Stone Road

Kilgore, Texas 75662

(Address of principal executive offices, zip code)

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

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

Yes x No o

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

Yes x No o

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

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

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

Yes o No x

The number of the registrant’s Common Units outstanding at August 9, 2011 was 19,582,332. The number of the registrant’s subordinated units outstanding at August 9, 2011 was 889,444.

Table of Contents

	Page

PART I – FINANCIAL INFORMATION	2

Item 1. Financial Statements	2
Consolidated and Condensed Balance Sheets as of June 30, 2011 (unaudited) and December 31, 2010 (audited)	2
Consolidated and Condensed Statements of Operations for the Three and Six Months ended June 30, 2011 and 2010 (unaudited)	3
Consolidated and Condensed Statements of Capital for the Six Months Ended June 30, 2011 and 2010 (unaudited)	4
Consolidated and Condensed Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2011 and 2010 (unaudited)	5
Consolidated and Condensed Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010 (unaudited)	6
Notes to Consolidated and Condensed Financial Statements	7

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk	60

Item 4. Controls and Procedures	62

PART II. OTHER INFORMATION	63

Item 1. Legal Proceedings	63

Item 1A. Risk Factors	63

Item 5. Other Information	63

Item 6. Exhibits	65

SIGNATURE
CERTIFICATIONS

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	June 30, 2011 (Unaudited)			December 31, 2010 (Audited)
Assets
Cash	$	67		$	11,380
Accounts and other receivables, less allowance for doubtful accounts of $2,705 and $2,528, respectively		99,119			95,276
Product exchange receivables		16,641			9,099
Inventories		63,560			52,616
Due from affiliates		19,122			6,437
Fair value of derivatives		2,258			2,142
Other current assets		1,209			2,784
Total current assets		201,976			179,734

Property, plant and equipment, at cost		677,785			632,456
Accumulated depreciation		(219,291	)		(200,276	)
Property, plant and equipment, net		458,494			432,180

Goodwill		37,268			37,268
Investment in unconsolidated entities		160,898			98,217
Fair value of derivatives		39			—
Deferred debt costs		14,531			13,497
Other assets, net		25,073			24,582
	$	898,279		$	785,478
Liabilities and Partners’ Capital
Current portion of capital lease obligations	$	1,173		$	1,121
Trade and other accounts payable		90,685			82,837
Product exchange payables		27,609			22,353
Due to affiliates		17,227			6,957
Income taxes payable		601			811
Fair value of derivatives		387			282
Other accrued liabilities		9,669			10,034
Total current liabilities		147,351			124,395

Long-term debt and capital leases, less current maturities		428,442			372,862
Deferred income taxes		7,782			8,213
Fair value of derivatives		2,603			4,100
Other long-term obligations		1,753			1,102
Total liabilities		587,931			510,672

Partners’ capital		309,728			273,387
Accumulated other comprehensive income		620			1,419
Total partners’ capital		310,348			274,806
Commitments and contingencies
	$	898,279		$	785,478

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per unit amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues:
Terminalling and storage *	$	19,327		$	16,664		$	37,450		$	32,705
Marine transportation *		17,376			18,113			36,775			35,990
Sulfur services		2,850			—			5,700			—
Product sales: *
Natural gas services		159,198			124,784			326,409			290,013
Sulfur services		74,083			42,878			130,991			77,287
Terminalling and storage		19,371			9,505			37,916			18,625
		252,652			177,167			495,316			385,925
Total revenues		292,205			211,944			575,241			454,620

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *		153,417			119,282			311,621			276,946

Sulfur services *		59,892			31,615			104,334			56,350
Terminalling and storage		17,395			8,962			33,955			17,408
		230,704			159,859			449,910			350,704
Expenses:
Operating expenses *		34,712			28,102			69,061			57,297
Selling, general and administrative *		5,012			4,838			10,040			10,108
Depreciation and amortization		11,309			9,986			22,251			19,891
Total costs and expenses		281,737			202,785			551,262			438,000

Other operating income		98			(57	)		98			45
Operating income		10,566			9,102			24,077			16,665

Other income (expense):
Equity in earnings of unconsolidated entities		2,793			2,342			5,169			4,518
Interest expense		(4,403	)		(8,194	)		(12,805	)		(16,197	)
Other, net		44			23			104			83
Total other income (expense)		(1,566	)		(5,829	)		(7,532	)		(11,596	)
Net income before taxes		9,000			3,273			16,545			5,069
Income tax benefit (expense)		( 230	)		( 198	)		(453	)		(223	)

Net income	$	8,770		$	3,075		$	16,092		$	4,846

General partner’s interest in net income	$	1,415		$	969		$	2,644		$	1,832
Limited partners’ interest in net income	$	7,078		$	1,829		$	12,894		$	2,460

Net income per limited partner unit - basic and diluted	$	0.37		$	0.10		$	0.67		$	0.14

Weighted average limited partner units - basic		19,158,507			17,702,321			19,162,963			17,702,442
Weighted average limited partner units - diluted		19,158,901			17,703,945			19,163,960			17,704,293

See accompanying notes to consolidated and condensed financial statements.

*Related Party Transactions Included Above

Revenues:
Terminalling and storage	$	12,897	$	11,593	$	25,835	$	22,287
Marine transportation		6,306		6,920		12,871		12,980
Product Sales		3,321		3,074		8,721		3,382

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services		25,754		22,662		48,959		41,368
Sulfur services		4,492		3,919		8,645		7,236
Expenses:
Operating expenses		13,702		12,309		25,744		23,771
Selling, general and administrative		2,893		3,634		5,924		5,436

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)


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

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

Net income		—			3,014			—		—		1,832			—			4,846

Recognition of beneficial conversion feature		—			(554	)		—		554		—			—			—

Follow-on public offering		1,650,000			50,530			—		—		—			—			50,530

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

Cash distributions		—			(25,324	)		—		—		(2,350	)		—			(27,674	)

Unit-based compensation		3,000			38			—		—		—			—			38

Purchase of treasury units		(3,000	)		(92	)		—		—		—			—			(92	)

Adjustment in fair value of derivatives		—			—			—		—		—			3,452			3,452

Balances – June 30, 2010		17,707,832		$	273,295			889,444	$	17,167	$	5,302		$	1,376		$	297,140

Balances – January 1, 2011		17,707,832		$	250,785			889,444	$	17,721	$	4,881		$	1,419		$	274,806

Net income		—			13,448			—		—		2,644			—			16,092

Recognition of beneficial conversion feature		—			(554	)		—		554		—			—			—

Follow-on public offering		1,874,500			70,330			—		—		—			—			70,330

General partner contribution		—			—			—		—		1,505			—			1,505

Cash distributions		—			(28,390	)		—		—		(3,025	)		—			(31,415	)

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

Unit-based compensation		15,350			96			—		—		—			—			96

Purchase of treasury units		(14,850	)		(582	)		—		—		—			—			(582	)

Unit-based compensation grant forfeitures		(500	)		—			—		—		—			—			—

Adjustment in fair value of derivatives		—			—			—		—		—			(799	)		(799	)

Balances – June 30, 2011		19,582,332		$	285,448			889,444	$	18,275	$	6,005		$	620		$	310,348

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010

Net income	$	8,770		$	3,075		$	16,092		$	4,846
Changes in fair values of commodity cash flow hedges		843			246			(65	)		745
Commodity cash flow hedging gains (losses) reclassified to earnings		(318	)		(268	)		(752	)		(386	)
Changes in fair value of interest rate cash flow hedges		—			—			—			(241	)
Interest rate cash flow hedging losses reclassified to earnings		—			963			18			3,334

Comprehensive income	$	9,295		$	4,016		$	15,293		$	8,298

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)


	Six Months Ended June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	16,092		$	4,846
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		22,251			19,891
Amortization of deferred debt issuance costs		2,390			2,663
Amortization of debt discount		175			93
Deferred taxes		(32	)		(289	)
(Gain) loss on sale of property, plant and equipment		714			(45	)
Equity in earnings of unconsolidated entities		(5,169	)		(4,518	)
Distributions in-kind from equity investments		7,034			4,531
Non-cash mark-to-market on derivatives		(2,346	)		(2,650	)
Other		96			38
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables		(3,843	)		8,013
Product exchange receivables		(7,542	)		677
Inventories		(10,944	)		(13,647	)
Due from affiliates		(12,685	)		(7,385	)
Other current assets		1,176			(1,183	)
Trade and other accounts payable		7,848			(4,223	)
Product exchange payables		5,257			8,295
Due to affiliates		10,270			392
Income taxes payable		(210	)		(63	)
Other accrued liabilities		(365	)		3,400
Change in other non-current assets and liabilities		(92	)		(3,864	)
Net cash provided by operating activities		30,075			14,972
Cash flows from investing activities:
Payments for property, plant and equipment		(30,169	)		(7,716	)
Acquisitions		(16,815	)		—
Payments for plant turnaround costs		(2,044	)		(1,062	)
Proceeds from sale of property, plant and equipment		—			968
Investment in unconsolidated entities		(59,319	)		(20,110	)
Return of investments from unconsolidated entities		1,285			740
Distributions from (contributions to) unconsolidated entities for operations		(6,512	)		881
Net cash used in investing activities		(113,574	)		(26,299	)
Cash flows from financing activities:
Payments of long-term debt		(301,500	)		(331,693	)
Payments of notes payable and capital lease obligations		(543	)		(49	)
Proceeds from long-term debt		357,500			330,682
Net proceeds from follow on offering		70,330			50,530
General partner contribution		1,505			1,089
Distribution to parent		(19,685	)		—
Payments of debt issuance costs		(3,424	)		(7,327	)
Purchase of treasury units		(582	)		(92	)
Cash distributions paid		(31,415	)		(27,674	)
Net cash provided by financing activities		72,186			15,466
Net increase (decrease) in cash		(11,313	)		4,139
Cash at beginning of period		11,380			5,956
Cash at end of period	$	67		$	10,095

See accompanying notes to consolidated and condensed financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

(1) General

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

The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and United States generally accepted accounting principles for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by generally accepted accounting principles for annual audited financial statements of the type contained in the Partnership’s annual reports on Form 10-K. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for such interim periods are not necessarily indicative of the results of operations for the full year. These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission (the “SEC”) on March 2, 2011.

(a) Use of Estimates

Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States. Actual results could differ from those estimates.

(b) Unit Grants

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

In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for $347. These units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015.

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

The cost resulting from share-based payment transactions was $59 and $11 for the three months ended June 30, 2011 and 2010, respectively, and $96 and $38 for the six months ended June 30, 2011 and 2010, respectively.

The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights (“IDRs”) in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the partnership agreement of the Partnership (the “Partnership Agreement”), and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

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

For the three months ended June 30, 2011 and 2010 the general partner received $1,265 and $926, respectively, in incentive distributions. For the six months ended June 30, 2011 and 2010, the general partner received $2,370 and $1,771, respectively, in incentive distributions.

(d) Net Income per Unit

The Partnership follows the provisions of ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. To the extent the Partnership Agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the Partnership Agreement. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement.

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

For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the beneficial conversion feature is added back to net income available to common limited partners, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net income attributable to Martin Midstream Partners L.P.	$	8,770		$	3,075		$	16,092		$	4,846
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs		1,265			926			2,370			1,771
Distributions payable on behalf of general partner interest		345			304			655			580
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest		(195	)		(261	)		(381	)		(519	)
Less beneficial conversion feature		277			277			554			554
Limited partners’ interest in net income	$	7,078		$	1,829		$	12,894		$	2,460

The weighted average units outstanding for basic net income per unit were 19,158,507 and 19,162,963 for the three months and six months ended June 30, 2011, respectively, and 17,702,321 and 17,702,442 for the three months and six months ended June 30, 2010, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 394 and 997 for the three and six months ended June 30, 2011, respectively, and 1,624 and 1,851 for the three and six months ended June 30, 2010, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

(e) Income Taxes

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

(2) New Accounting Pronouncements

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

(3) Acquisitions

Redbird Gas Storage

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

Terminalling Facilities

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

These terminalling assets were acquired by Martin Resource Management in its acquisition of L&L Holdings LLC (“L&L”) on January 31, 2011. During the second quarter, Martin Resource Management finalized the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the terminalling assets acquired by the Partnership. The Partnership recorded an adjustment in the amount of $19,685 to reduce property, plant and equipment and partners’ capital for the difference between the purchase price and the fair value of the terminalling assets acquired based on Martin Resource Management’s final purchase price allocation. The impact on first quarter depreciation expense as a result of the finalization of the purchase price allocation is accounted for retrospectively and was a reduction of $241.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

Harrison Gathering System

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

(4) Inventories

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

	June 30, 2011		December 31, 2010
Natural gas liquids	$	24,331	$	19,775
Sulfur		14,917		15,933
Sulfur Based Products		9,816		9,027
Lubricants		11,867		5,267
Other		2,629		2,614
	$	63,560	$	52,616

(5) Investments in Unconsolidated Entities and Joint Ventures

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

In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity-method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $148 and $297 for the three and six months ended June 30, 2011 and 2010, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated entities. The remaining unamortized excess investment relating to property and equipment was $8,606 and $8,903 at June 30, 2011 and December 31, 2010, respectively. The equity-method goodwill is not amortized; however, it is analyzed for impairment annually or when changes in circumstance indicate that a potential impairment exists. No impairment was recognized for the six months ended June 30, 2011 or 2010.

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

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


	Waskom			PIPE			Matagorda			Redbird		Total

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

Distributions in kind		(7,034	)		—			—			—		(7,034	)
Contributions to unconsolidated entities:
Cash contributions (See Note 3)		—			—			—			59,319		59,319
Contributions to unconsolidated entities for operations		6,342			—			170			—		6,512
Return of investments		(1,200	)		—			(85	)		—		(1,285	)
Equity in earnings:
Equity in earnings (losses) from operations		5,287			(21	)		47			153		5,466
Amortization of excess investment		(275	)		(8	)		(14	)		—		(297	)

Investment in unconsolidated entities, June 30, 2011	$	96,888		$	1,282		$	3,256		$	59,472	$	160,898

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NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)


	Waskom			PIPE			Matagorda			Redbird		Total

Investment in unconsolidated entities, December 31, 2009	$	75,844		$	1,401		$	3,337			—	$	80,582

Distributions in kind		(4,531	)		—			—			—		(4,531	)
Contributions to unconsolidated entities:
Cash contributions (See Note 3)		20,110			—			—			—		20,110
Contributions to unconsolidated entities for operations		(881	)		—			—			—		(881	)
Return of investments		(500	)		(30	)		(210	)		—		(740	)
Equity in earnings:
Equity in earnings (losses) from operations		4,857			(166	)		124			—		4,815
Amortization of excess investment		(275	)		(8	)		(14	)		—		(297	)

Investment in unconsolidated entities, June 30, 2010	$	94,624		$	1,197		$	3,237		$	—	$	99,058

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

	As of June 30				Three Months Ended June 30				Six Months Ended June 30
	Total Assets		Partner’s Capital		Revenues		Net Income		Revenues		Net Income
2011
Waskom	$	134,249	$	114,300	$	34,072	$	5,672	$	65,578	$	10,574

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

As of June 30, 2011 and December 31, 2010, the amount of the Partnership’s consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity-method investees is $44,239 and $36,964, respectively. There are no material restrictions to transfer funds in the form of dividends, loans or advances related to the equity-method investees.

As of June 30, 2011 and December 31, 2010, the Partnership’s interest in cash of the unconsolidated equity-method investees was $930 and $1,145, respectively.

(6) Derivative Instruments and Hedging Activities

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

The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of its hedge contracts, including assessing the possibility of counterparty default. If the Partnership determines that a derivative is no longer expected to be highly effective, the Partnership discontinues hedge accounting prospectively and recognizes subsequent changes in the fair value of the hedge in earnings. As a result of its effectiveness assessment at June 30, 2011, the Partnership believes certain hedge contracts will continue to be effective in offsetting changes in cash flow or fair value attributable to the hedged risk.

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NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

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

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

(a) Commodity Derivative Instruments

The Partnership is exposed to market risks associated with commodity prices and uses derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. The Partnership has entered into hedging transactions through 2012 to protect a portion of its commodity exposure. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership is focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

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

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

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2011 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of June 30, 2011, the remaining term of the contracts extend no later than December 2012, with no single contract longer than one year. For the three months and six months ended June 30, 2011 and 2010, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in AOCI as a component of partners’ capital.

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NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

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

Mark to Market Derivatives::

Crude Oil Swap	2,000 BBL	Fixed price of $91.20 settled against WTI NYMEX average monthly closings	July 2011 to December 2011		(56	)
Total commodity swaps not designated as hedging instruments				$	(56	)

Cash Flow Hedges:

Natural Gas Swap	10,000 Mmbtu	Fixed price of $6.1250 settled against IF_ANR_LA first of the month posting	July 2011 to December 2011		102

Natural Gas Swap	20,000 Mmbtu	Fixed price of $4.3225 settled against IF_ANR_LA first of the month posting	July 2011 to December 2011		(12	)

Natural Gasoline Swap	2,000 BBL	Fixed price of $87.10 settled against WTI NYMEX average monthly closings	July 2011 to December 2011		(105	)

Natural Gasoline Swap	1,000 BBL	Fixed price of $88.85 settled against WTI NYMEX average monthly closings	July 2011 to December 2011		(42	)

Natural Gasoline Swap	1,000 BBL	Fixed price of $2.383 settled against Mont Belvieu Non-TET OPIS Average	July 2011 to December 2011		81

Crude Oil Swap	1,000 BBL	Fixed price of $101.90 settled against WTI NYMEX average monthly closings	July 2011 to December 2011		36

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

Natural Gas Swap	20,000 Mmbtu	Fixed price of $4.9600 settled against IF_ANR_LA first of the month posting	January 2012 to December 2012		42

Natural Gasoline Swap	1,000 BBL	Fixed price of $90.20 settled against WTI NYMEX average monthly closings	January 2012 to December 2012		(111	)

Natural Gasoline Swap	1,000 BBL	Fixed price of $2.340 settled against Mont Belvieu Non-TET OPIS Average	January 2012 to December 2012		64

Crude Oil Swap	2,000 BBL	Fixed price of $88.63 settled against WTI NYMEX average monthly closings	January 2012 to December 2012		(258	)

Total commodity swaps designated as hedging instruments				$	(193	)

Total net fair value of commodity derivatives				$	(249	)

Based on estimated volumes, as of June 30, 2011, the Partnership had hedged approximately 47% and 35% of its commodity risk by volume for 2011 and 2012, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.

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

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

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

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

(b) Impact of Commodity Cash Flow Hedges

Crude Oil. For the three months ended June 30, 2011 and 2010, net gains on swap hedge contracts increased crude revenue by $357 and $256, respectively. For the six months ended June 30, 2011 and 2010, net gains on swap hedge contracts increased crude revenue by $297 and $253, respectively. As of June 30, 2011 an unrealized derivative fair value gain of $147, related to current and terminated cash flow hedges of crude oil price risk, was recorded in AOCI. Fair value gains of $404 and fair value losses of $257 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at June 30, 2011, adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

Natural Gas. For the three months ended June 30, 2011 and 2010, net gains on swap hedge contracts increased gas revenue by $69 and $192, respectively. For the six months ended June 30, 2011 and 2010, net gains on swap hedge contracts increased gas revenue $143 and $257, respectively. As of June 30, 2011 an unrealized derivative fair value gain of $131 related to cash flow hedges of natural gas was recorded in AOCI. Fair value gains of $81 and $50 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

Natural Gas Liquids. For the three months ended June 30, 2011 and 2010, net gains on swap hedge contracts increased natural gas liquids revenue by $60 and $226, respectively. For the six months ended June 30, 2011 and 2010, net gains and losses on swap hedge contracts increased or decreased natural gas liquids revenue $222 and $189, respectively. As of June 30, 2011 an unrealized derivative fair value gain of $342 related to cash flow hedges of natural gas was recorded in AOCI. Fair value gains of $383 and fair value losses of $41 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.

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

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

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

The Partnership has entered into interest rate swap agreements with an aggregate notional amount of $100,000 to hedge its exposure to changes in the fair value of Senior Notes as described in Note 10. The Partnership believes the interest rate hedge contracts will be effective in offsetting changes in fair value attributable to the hedged risk; however, the contracts were not designated as fair value hedges and therefore, are not receiving hedge accounting but being marked to market through earnings.

Under the following swap agreements, the Partnership pays a floating rate of interest and receives a fixed rate based on a three-month U.S. Dollar LIBOR rate to match the fixed rate of the Senior Notes:

Date of Hedge	Notional Amount		Paying Floating Rate	Receiving Fixed Rate			Maturity Date
September 2010	$	40,000	3 Month LIBOR		2.3150	%	April 2018
September 2010	$	60,000	3 Month LIBOR		2.3150	%	April 2018

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

The Partnership recognized decreases in interest expense of $3,167 and $2,535 for the three and six months ended June 30, 2011, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges. The Partnership recognized increases in interest expense of $963 and $3,524 for the three and six months ended June 30, 2010, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges.

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

(d)

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

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

Fair Values of Derivative Instruments in the Consolidated Balance Sheet

Derivative Assets

Derivative Liabilities

Fair Values

Balance Sheet Location

June 30,

2011

December 31,

2010

Balance Sheet Location

June 30,

2011

December 31, 2010

Derivatives designated as hedging instruments

Current:

Interest rate contracts

Fair value of derivatives

—

Fair value of derivatives

—

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

June 30, 2011

(Unaudited)

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet

	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	June 30, 2011		December 31, 2010		Balance Sheet Location	June 30, 2011		December 31, 2010
Commodity contracts	Fair value of derivatives		296		201	Fair value of derivatives		331		230
			296		201			331		230

	Non-current:					Non-current:

Interest rate contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		—
Commodity contracts	Fair value of derivatives		39		—	Fair value of derivatives		197		171
			39		—			197		171

Total derivatives designated as hedging instruments		$	335	$	201		$	528	$	401

Derivatives not designated as hedging instruments

	Current:					Current:

Interest rate contracts	Fair value of derivatives	$	1,962	$	1,941	Fair value of derivatives	$	—	$	—
Commodity contracts	Fair value of derivatives		—		—	Fair value of derivatives		56		51
			1,962		1,941			56		51

	Non-current:					Non-current:

Interest rate contracts	Fair value of derivatives		—		—	Fair value of derivatives		2,406		3,930
Commodity contracts	Fair value of derivatives		—		—	Fair value of derivatives		—		—
			—		—			2,406		3,930
Total derivatives not designated as hedging instruments		$	1,962	$	1,941		$	2,462	$