exv99w1

Exhibit 99.1

MARTIN MIDSTREAM GP LLC
CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands)


	September 30,			December 31,
	2007			2006
	(Unaudited)			(Audited)
Assets

Cash	$	6,600		$	3,675
Accounts and other receivables, less allowance for doubtful accounts of $207 and $394		65,872			56,712
Product exchange receivables		11,143			7,076
Inventories		39,847			33,019
Due from affiliates		3,117			1,330
Other current assets		1,164			2,049

Total current assets		127,743			103,861


Property, plant and equipment, at cost		413,619			323,967
Accumulated depreciation		(92,032	)		(76,122	)

Property, plant and equipment, net		321,587			247,845


Goodwill		37,405			27,600
Investment in unconsolidated entities		74,042			70,651
Other assets, net		9,510			7,512

	$	570,287		$	457,469

Liabilities and Members’ Equity

Current installments of long-term debt	$	40		$	74
Trade and other accounts payable		79,492			53,450
Product exchange payables		12,349			14,737
Due to affiliates		7,720			12,612
Income taxes payable		963			—
Other accrued liabilities		6,300			3,876

Total current liabilities		106,864			84,749


Long-term debt		210,000			174,021
Deferred income taxes		9,301			407
Other long-term obligations		3,774			2,219

Total liabilities		329,939			261,396


Minority interests		239,036			195,302
Members’ equity		1,312			771

		240,348			196,073


Commitments and contingencies	$	570,287		$	457,469

See accompanying notes to the consolidated and condensed balance sheets.

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

(1) ORGANIZATION AND DESCRIPTION OF BUSINESS

Martin Midstream GP LLC (the “General Partner”) is a single member Delaware limited liability company formed on September 21, 2002 to become the general partner of Martin Midstream Partners L.P. (the “Company”). The General Partner owns a 2% general partner interest and incentive distribution rights in the Company. The General Partner is a wholly owned subsidiary of Martin Resource Management Corporation (“MRMC”).

In September 2005 the FASB ratified EITF Issue 04-5, a framework for addressing when a limited company should be consolidated by its general partner. The framework presumes that a sole general partner in a limited company controls the limited company, and therefore should consolidate the limited company. The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited company or (b) substantive participating rights. The EITF reached a conclusion on the circumstances in which either kick-out rights or participating rights would be considered substantive and preclude consolidation by the general partner. Based on the guidance in the EITF, the General Partner concluded that the Company should be consolidated. As such, the accompanying balance sheets have been consolidated to include the General Partner and the Company.

The Company is a publicly traded limited partnership which provides terminalling and storage services for petroleum products and by-products, natural gas services, marine transportation services for petroleum products and by-products, sulfur gathering, processing and distribution and fertilizer manufacturing and distribution.

On November 10, 2005, the Company acquired Prism Gas Systems I, L.P. (“Prism Gas”) which is engaged in the gathering, processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana. Through the acquisition of Prism Gas, the Company also acquired 50% ownership interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), and the Panther Interstate Pipeline Energy LLC (“Panther”) each accounted for under the equity method of accounting.

The petroleum products and by-products the Company collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Company, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, the Company’s primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Company operates primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry.

(2) SIGNIFICANT ACCOUNTING POLICIES

(a) Principles of Presentation and Consolidation

The consolidated balance sheets include the financial position of the General Partner and the Company and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. As the General Partner only has a 2% interest in the Company, the remaining 98% not owned is shown as minority interests in the consolidated balance sheets. In addition, the Company evaluates its relationships with other entities to identify whether they are variable interest entities as defined by FASB Interpretation No 46(R) Consolidation of Variable Interest Entities (“FIN 46R”) and to assess whether they are the primary beneficiary of such entities. If the determination is made that the Company is the primary beneficiary, then that entity is included in the consolidated balance sheet in accordance with FIN 46(R). No such variable interest entities exist as of September 30, 2007 and December 31, 2006.

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

(b) Product Exchanges

Product exchange balances due to other companies under negotiated agreements are recorded at quoted market product prices while balances due from other companies are recorded at the lower of cost (determined using the first-in, first-out method) or market.

(c) Inventories

Inventories are stated at the lower of cost or market. Cost is determined by using the first-in, first-out method for all inventories.

(d) Revenue Recognition

Revenue for the Company’s five 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 the Company’s terminals at the contracted rate. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

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

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.

Sulfur and Fertilizer – Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership based on specific contract terms at either the shipping or delivery point.

(e) Equity Method Investments

The Company uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Company’s share of accumulated earnings less capital withdrawals and dividends. Any excess of cost over the underlying equity in net assets is recognized as goodwill. Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock.

(f) Property, Plant, and Equipment

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

Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

accounts and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.

(g) Goodwill and Other Intangible Assets

Goodwill represents the excess of costs over fair value of net assets of businesses acquired. Goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. Intangible assets with estimated useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with FASB Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible assets primarily consists of covenants not-to-compete obtained through business combinations and are being amortized over the life of the respective agreements.

(h) Debt Issuance Costs

In connection with the Company’s multi-bank credit facility, on November 10, 2005, it incurred debt issuance costs of $3,258. In connection with the amendment and expansion of the Company’s multi-bank credit facility on September 30, 2006, it incurred debt issuance costs of $372. These debt issuance costs, along with the remaining unamortized deferred issuance costs relating to the line of credit facility as of November 10, 2005 which remain deferred, are amortized over the 60 month term of the new debt arrangement. The unamortized balance of debt issuance costs, classified as other assets amounted to $3,359 at September 30, 2007 and $4,169 at December 31, 2006.

(i) Impairment of Long-Lived Assets

In accordance with SFAS No. 144, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. Goodwill is tested annually for impairment, and is tested for impairment more frequently if events and circumstances indicate that the asset might be impaired. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value. This determination is made at the reporting unit level and consists of two steps. First, the Company determines the fair value of a reporting unit and compares it to its carrying amount. Second, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation, in accordance with FASB Statement No. 141, Business Combinations. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. The Company performed its annual test in the third quarters of 2007 and 2006 with no indication of impairment.

(j) Asset Retirement Obligation

Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143”), an Asset Retirement Obligation (“ARO”) which consists of costs associated with legal obligations to retire tangible, long-lived assets is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. Financial Accounting

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143, clarifies that the recognition and measurement provisions of SFAS 143 apply to asset retirement obligations in which the timing or method of settlement may be conditional on a future event that may or may not be within the control of the entity. The Company’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment.

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

(k) Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities—SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established accounting and reporting standards for derivative instruments and hedging activities. It requires that all derivatives be included on the balance sheet as an asset or liability measured at fair value and that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If such hedge accounting criteria are met, the change is deferred in shareholders’ equity as a component of accumulated other comprehensive income. The deferred items are recognized in the period the derivative contract is settled.

(l) Allowance for Doubtful Accounts

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

(m) Unit Grants

The Company issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in January 2006. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010.

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

The Company issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in May 2007. These units vest in 25% increments beginning in January 2008 and will be fully vested in January 2011.

The Company accounts for these transactions under EITF Issue 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.”

(n) Incentive Distribution Rights

The General Partner holds a 2% general partner interest and certain incentive distribution rights in the Company. Incentive distribution rights represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved. The Company is required to distribute all of its available cash from operating surplus, as defined in the Company agreement. The target distribution levels entitle the General Partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unit holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three and nine months ended September 30, 2007, the General Partner received incentive distributions. Such distributions have been eliminated in the accompanying consolidated balance sheet.

(o) 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 their consolidated balance sheets in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

(p) Environmental Liabilities

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

(q) Income Taxes

The General Partner is a disregarded entity for federal income tax purposes. Its activity is included in the consolidated federal income tax return of MRMC; however, for financial reporting purposes, current federal income taxes are computed and recorded as if the General Partner filed a separate federal income tax return. The Company’s subsidiary, Woodlawn Pipeline Company Inc. (“Woodlawn”), is subject to income taxes. In connection with the Woodlawn acquisition, a deferred tax liability of $8,964 was established associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment.

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. Deferred tax liabilities relating primarily to book and tax basis differences of the acquired assets of Woodlawn, and the timing of recognizing

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

partnership earnings and insurance expense totaled $9,313 ($12 of which is included in other accrued liabilities) and $407 at September 30, 2007 and December 31, 2006, respectively.

The operations of the Company are generally not subject to income taxes and as a result, the Company’s income is taxed directly to its owners, except for the Texas Margin Tax as described below and the taxes associated with Woodlawn as previously discussed.

On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Company has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change and subsequent changes in deferred tax assets and liabilities are immaterial. At September 30, 2007, the Company has recorded a liability attributable to the Texas Margin tax of $445.

(3) ACQUISITIONS

(a) Lubricants Terminal. In June 2007, the Company acquired all of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) located in Channelview, Texas. The terminal is located on 5.6 acres of land, includes 38 tanks with a storage capacity of approximately 600,000 gallons, pump and piping infrastructure for lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an administrative office.

The purchase price of $4,738, including two three-year non-competition agreements totaling $530 and goodwill of $1,020, was allocated as follows:


Current assets	$	446
Property, plant and equipment, net		3,042
Other assets		530
Goodwill		1,020
Other liabilities		(300	)

Total	$	4,738

In connection with the acquisition on, the Company borrowed approximately $4,600 under its credit facility.

(b) Woodlawn Pipeline Company Inc. On May 2, 2007, the Company, through its subsidiary Prism Gas, acquired 100% of the outstanding stock of Woodlawn. The results of Woodlawn’s operations have been included in the consolidated financial statements beginning May 2, 2007. Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 160 miles of natural gas gathering pipe, approximately 40 miles of condensate transport pipe and a 30 Mcf/day processing plant. Prism Gas acquired, from a Woodlawn related party, a 9-mile pipeline that delivers residue gas from Woodlawn to the Texas Eastern Transmission pipeline system.

The selling parties in this transaction were Lantern Resources, L.P., David P. Deison, and Peak Gas Gathering L.P. The final purchase price of $32,606 was funded by borrowings under the Company’s credit facility.

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

The purchase price of $32,606, including four two-year non-competition agreements and other intangibles reflected as other assets, was allocated as follows:


Current assets	$	4,297
Property, plant and equipment, net		29,101
Goodwill		8,785
Other assets		3,339
Current liabilities		(3,889	)
Deferred income taxes		(8,964	)
Other liabilities		(63	)

Total	$	32,606

The identifiable intangible assets of $3,339 are subject to amortization over a weighted-average useful life of approximately ten years. The intangible assets include four non-competition agreements totaling $40, customer contracts associated with the gathering and processing assets of $3,002, and a transportation contract associated with the residue gas pipeline of $297.

In connection with the acquisition, the Company borrowed approximately $33,000 under its credit facility.

(c) Asphalt Terminals. In August 2006 and October 2006, respectively, the Company acquired the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (“Prime”) for $4,842 which was allocated to property, plant and equipment. The assets are located in Houston, Texas and Port Neches, Texas. The Company entered into an agreement with MRMC, pursuant to which MRMC will operate the facilities through a terminalling service agreement based upon throughput rates and will assume all additional expenses to operate the facility.

(d) Corpus Christi Barge Terminal. In July 2006, the Company acquired a marine terminal located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6,200 which was allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land, and includes three tanks with a combined shell capacity of approximately 240,000 barrels, pump and piping infrastructure for truck unloading and product delivery to two oil docks, and there are several pumps, controls, and an office building on site for administrative use.

(e) Marine Vessels. In November 2006, the Company acquired the La Force, an offshore tug, for $6,001 from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 and new engines were installed in 2005.

In January 2006, the Company acquired the Texan, an offshore tug, and the Ponciana, an offshore NGL barge, for $5,850 from MRMC. The acquisition price was based on a third-party appraisal. In March 2006, these vessels went into service under a long term charter with a third party. In February 2006, the Company acquired the M450, an offshore barge, for $1,551 from a third party. In March 2006, this vessel went into service under a one-year evergreen charter with an affiliate of MRMC.

(4) INVENTORIES

Components of inventories at September 30, 2007 and December 31, 2006 were as follows:


	September 30,		December 31,
	2007		2006
Natural Gas Liquids	$	22,680	$	17,061
Sulfur		4,687		4,397
Fertilizer — raw materials and packaging		1,899		2,412

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)


	September 30,		December 31,
	2007		2006
Fertilizer — finished goods		4,566		4,807
Lubricants		4,556		2,592
Other		1,459		1,750

	$	39,847	$	33,019

(5) PROPERTY, PLANT AND EQUIPMENT

At September 30, 2007 and December 31, 2006, property, plant, and equipment consisted of the following:


		September		December 31,
		30, 2007		2006
	Depreciable Lives	(Unaudited)		(Audited)
Land	—	$	14,345	$	12,559
Improvements to land and buildings	10-39 years		31,888		26,868
Transportation equipment	3- 7 years		615		531
Storage equipment	5-20 years		31,775		22,343
Marine vessels	4-30 years		142,010		124,323
Operating equipment	3-30 years		138,337		103,929
Furniture, fixtures and other equipment	3-20 years		1,519		1,450
Construction in progress			53,130		31,964

		$	413,619	$	323,967

(6) RELATED PARTY TRANSACTIONS

Amounts due to and due from affiliates in the consolidated balance sheets as of September 30, 2007 (unaudited) and December 31, 2006, are primarily with MRMC and its affiliates and Waskom Gas Processing Company (“Waskom”).

The General Partner’s balances are primarily related to (1) Company cash distributions that were paid to a related party on behalf of the General Partner and (2) director fees that were paid by a related party on behalf of the General Partner. The Company contributions and distributions have been eliminated in the accompanying consolidated balance sheet.

The Company’s balances are related to transactions involving the purchase and sale of NGL products, lube oil products, sulfur and sulfuric acid products, fertilizer products; land and marine transportation services; terminalling and storage services, and other purchases of products and services representing operating expenses.

(7) INVESTMENT IN UNCONSOLIDATED COMPANIES AND JOINT VENTURES

The Company, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom, Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). Each of these interests is accounted for under the equity method of accounting.

On June 30, 2006, the Company, through its Prism Gas subsidiary, acquired for approximately $196 a 20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). BCP is an approximate 67 mile pipeline located in the Barnett Shale extension. The pipeline traverses four counties with the most concentrated drilling occurring in Bosque County. BCP is operated by Panther Pipeline Ltd. which is the 42.5% interest owner. This interest is accounted for under the equity method of accounting.

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

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

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 $147 and $444 for the three months and nine months ended September 30, 2007, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $10,834 and $11,279 at September 30, 2007 and December 31, 2006, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in the first nine months of 2007 or the year ended December 31, 2006.

As a partner in Waskom, the Company receives distributions in kind of natural gas liquids that are retained according to Waskom’s contracts with certain producers. The natural gas liquids 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 is as follows:


	Waskom			PIPE			Matagorda			BCP			Total
Investment in unconsolidated entities, December 31, 2006	$	64,937		$	1,718		$	3,786		$	210		$	70,651

Distributions in kind		(6,628	)		—			—			—			(6,628	)
Cash contributions		6,023			—			—			107			6,130
Cash distributions		(2,625	)		(565	)		(125	)		—			(3,315	)
Equity in earnings:
Equity in earnings from operations		7,205			464			78			(99	)		7,648
Amortization of excess investment		(412	)		(11	)		(21	)		—			(444	)


Investment in unconsolidated entities, September 30, 2007	$	68,500		$	1,606		$	3,718		$	218		$	74,042


	Waskom			PIPE			Matagorda			BCP			Total
Investment in unconsolidated entities, December 31, 2005	$	54,087		$	1,723		$	4,069		$	—		$	59,879

Distributions in kind		(6,710	)		—			—			—			(6,710	)
Cash contributions		7,148			—			—			196			7,344
Cash distributions		(150	)		(177	)		(510	)		—			(837	)
Equity in earnings:
Equity in earnings from operations		7,044			96			330			(27	)		7,443


Investment in unconsolidated entities, September 30, 2006	$	61,419		$	1,642		$	3,889		$	169		$	67,119

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


					Three Months Ended				Nine months ended
	As of September 30,				September 30,				September 30,
	Total		Partner’s				Net				Net
	Assets		Capital		Revenues		Income		Revenues		Income
2007
Waskom	$	64,191	$	53,400	$	21,293	$	5,808	$	54,466	$	14,410


	As of December 31,
2006
Waskom	$	53,260	$	45,450	$	18,654	$	5,453	$	52,924	$	14,533

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

(8) LONG-TERM DEBT

At September 30, 2007 and December 31, 2006, long-term debt consisted of the following:


	September 30,		December 31,
	2007		2006
*$120,000 Revolving loan facility at variable interest rate (6.91% weighted average at September 30, 2007), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries	$	80,000	$	44,000
**$130,000 Term loan facility at variable interest rate (7.16% at September 30, 2007), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries		130,000		130,000

Other secured debt maturing in 2008, 7.25%		40		95

Total long-term debt		210,040		174,095
Less current installments		40		74

Long-term debt, net of current installments	$	210,000	$	174,021


*		Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing borrowings is 2.00%. Effective October 1, 2007, the applicable margin for existing borrowings will decrease to 1.75%. As a result of our leverage ratio test, effective January 1, 2008, the applicable margin for existing borrowings will increase to 2.00%. We incur a commitment fee on the unused portions of the credit facility.

**		Effective September, 2007, the Company entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in September, 2010.

**		Effective November 2006, the Company entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 4.82% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in December, 2009.

***		The $130,000 term loan has $105,000 hedged. Effective March, 2006, the Company entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Company’s applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010. Effective November, 2006, the Company entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This cash flow hedge matures in March, 2010.

On August 18, 2006, the Company purchased certain terminalling assets and assumed associated long term debt of $113 with a fixed rate cost of 7.25%.

On November 10, 2005, the Company entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders,

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the Company increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general company purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of September 30, 2007, the Company had $80,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of September 30, 2007, the Company had $39,880 available under its revolving credit facility.

On July 14, 2005, the Company issued a $120 irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program.

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

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

The credit facility also contains covenants, which, among other things, require the Company to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (x) 5.5 to 1.0 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter thereafter. The Company was in compliance with the debt covenants contained in credit facility for the year ended December 31, 2006 and as of September 30, 2007.

On November 10 of each year, commencing with November 10, 2006, the Company must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made under the term loan through September 30, 2007. If the Company receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Company must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Company must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

Draws made under the Company’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Company’s credit facility have ranged from a low of $170,600 to a high of $226,850. As of September 30, 2007, the Company had $39,880 available for working capital, internal expansion and acquisition activities under the Company’s credit facility.

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

On July 15, 2005, the Company assumed $9,400 of U.S. Government Guaranteed Ship Financing Bonds, maturing in 2021, relating to the acquisition of CF Martin Sulphur, L.P. (“CF Martin Sulphur”). The outstanding balance as of December 31, 2005 was $9,104. These bonds were payable in equal semi-annual installments of $291, and were secured by certain marine vessels owned by CF Martin Sulphur. Pursuant to the terms of an amendment to the Company’s credit facility that it entered into in connection with the acquisition of CF Martin Sulphur, the Company was obligated to repay these bonds by March 31, 2006. The Company redeemed these bonds on March 6, 2006 with available cash and borrowings from its credit facility. Also, at redemption, a pre-payment premium was paid in the amount of $1,160.

The Company paid cash interest in the amount of $2,777 and $2,874 for the three months ended September 30, 2007 and 2006, respectively, and $8,722 and $9,135 for the nine months ended September 30, 2007 and 2006, respectively. Capitalized interest was $826 and $300 for the three months ended September 30, 2007 and 2006, respectively, and $2,171 and $970 for the nine months ended September 30, 2007 and 2006, respectively.

In connection with the Company’s Mega Lubricants acquisition on June 13, 2007, the Company borrowed approximately $4,600 under its revolving credit facility.

In connection with the Company’s Woodlawn acquisition on May 2, 2007, the Company borrowed approximately $33,000 under its revolving credit facility.

(9) INTEREST RATE CASH FLOW HEDGES

In September 2007, the Company entered into a cash flow hedge agreement with a notional amount of $25,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate term loan credit facility. This interest rate swap matures in September 2010. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 4.605% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.

In November 2006, the Company entered into a cash flow hedge agreement with a notional amount of $40,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facility. This interest rate swap matures in December 2009. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 4.82% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.

In November 2006, the Company entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Company’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006; therefore, hedge accounting was not utilized. The swap has been recorded at fair value at September 30, 2007 with an offset to current operations.

In March 2006, the Company entered into a cash flow hedge agreement with a notional amount of $75,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate term loan credit facility. This interest rate swap matures in November 2010. The Company designated this swap agreement as a cash flow hedge. Under the swap agreement, the Company pays a fixed rate of interest of 5.25% and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this is designated as a cash flow hedge, the changes in fair

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of the hedge, the swap was identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and the swap remain equal. This condition results in a 100% effective swap.

For the three months ended September 30, 2007, the Company recognized an increase in interest expense of $387 and for the nine months ended September 30, 2007, the Company recognized a decrease in interest expense of $44, 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 hedges. The net fair value of the interest rate swap agreements was recorded as an asset (liability) of approximately $(1,464) and $(83) at September 30, 2007 and December 31, 2006, respectively.

The fair value of derivative assets and liabilities are as follows:


	September 30,			December 31,
	2007			2006
Fair value of derivative assets — current	$	110		$	377
Fair value of derivative assets — long term		—			112
Fair value of derivative liabilities — current		(168	)		—
Fair value of derivative liabilities — long term		(1,406	)		(572	)

Net fair value of derivatives	$	(1,464	)	$	(83	)

(10) COMMODITY CASH FLOW HEDGES

The Company is exposed to market risks associated with commodity prices, counterparty credit and interest rates. Until December 2005, the Company had not engaged in commodity contract trading or hedging activities. However, in connection with the acquisition of Prism Gas at that time, the Company has established a hedging policy and monitors and manages the commodity market risk associated with the commodity risk exposure of the Prism Gas acquisition. In addition, the Company is focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

The Company uses derivatives to manage the risk of commodity price fluctuations. Additionally, the Company manages interest rate exposure by targeting a ratio of fixed and floating interest rates it deems prudent and using hedges to attain that ratio.

In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, 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 other comprehensive income until such time as the hedged item is recognized in earnings. In early 2006, the Company adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges.

Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of September 30, 2007, the Company has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity. During the nine months ended September 30, 2007, certain of the Company’s derivative instruments which were designated as hedges became ineffective due to fluctuations in the basis difference between the hedged item and the hedging instrument. As a result, these hedges are now marked to market through the statement of operations.

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

The fair value of derivative assets and liabilities are as follows:


	September 30,			December 31,
	2007			2006
Fair value of derivative assets — current	$	104		$	882
Fair value of derivative assets — long term		1			221
Fair value of derivative liabilities — current		(1,336	)		—
Fair value of derivative liabilities — long term		(567	)		(74	)

Net fair value of derivatives	$	(1,798	)	$	1,029

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2007 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of September 30, 2007, the remaining term of the contracts extend no later than December 2010, with no single contract longer than one year. The Company’s counterparties to the derivative contracts include Coral Energy Holding LP, Morgan Stanley Capital Group Inc. and Wachovia Bank. For three and nine months ended September 30, 2007, changes in the fair value of the Company’s derivative contracts were recorded in both earnings and in other comprehensive income as a component of equity since the Company has designated a portion of its derivative instruments as hedges as of September 30, 2007.

September 30, 2007

Total

Transaction

Volume

Remaining Terms

Type

Per Month

Pricing Terms

of Contracts

Fair Value

Mark to Market Derivatives::

Ethane Swap

8,000 BBL

Fixed price of $28.04 settled against Mt. Belvieu Purity Ethane average monthly postings

October 2007 to December 2007

(232

)

Crude Oil swap

5,000 BBL

Fixed price of $65.95 settled against WTI NYMEX average monthly closings

October 2007 to December 2007

(219

)

Natural Gas swap and Natural Gas basis swap

20,000 MMBTU

Combined fixed price of $8.54 settled against Henry Hub Centerpoint Energy Gas Transmission Co.

October 2007 to December 2007

104

Natural Gas swap

30,000 MMBTU

Fixed price of $8.12 settled against Houston Ship Channel first of the month

January 2008 to December 2008

(41

)

Crude Oil Swap

3,000 BBL

Fixed price of $70.75 settled against WTI NYMEX average monthly closings

January 2008 to December 2008

(211

)

Crude Oil Swap

3,000 BBL

Fixed price of $69.08 settled against WTI NYMEX average monthly closings

January 2009 to December 2009

(148

)

Crude Oil Swap

3,000 BBL

Fixed price of $70.90 settled against WTI NYMEX average monthly closings

January 2009 to December 2009

(91

)

Total swaps not receiving hedge accounting

(838

)

Cash Flow Hedges:

Crude Oil Swap

4,000 BBL

Fixed price of $72.35 settled against WTI NYMEX average monthly closings

October 2007 to December 2007

(35

)

Crude Oil Swap

5,000 BBL

Fixed price of $66.20 settled against WTI NYMEX average monthly closings

January 2008 to December 2008

(609

)

Ethane Swap

5,000 BBL

Fixed price of $27.30 settled against Mt. Belvieu Purity Ethane average monthly postings

January 2008 to December 2008

(222

)

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

Total

Transaction

Volume

Remaining Terms

Type

Per Month

Pricing Terms

of Contracts

Fair Value

Crude Oil Swap

1,000 BBL

Fixed price of $70.45 settled against WTI NYMEX average monthly closings

January 2009 to December 2009

(35

)

Crude Oil Swap

2,000 BBL

Fixed price of $69.15 settled against WTI NYMEX average monthly closings

January 2010 to December 2010

(60

)

Crude Oil Swap

3,000 BBL

Fixed price of $72.25 settled against WTI NYMEX average monthly closings

January 2010 to December 2010

Total swaps receiving hedge accounting

(960

)

Total net fair value of derivatives

(1,798

)

On all transactions where the Company is exposed to counterparty risk, the Company analyzes the counterparty’s financial condition prior to entering into an agreement, and has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Company has incurred no losses associated with the counterparty non-performance on derivative contracts.

Through its Prism Gas subsidiary, the Company is exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales activities. Prism Gas 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 (POL) and percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 2010 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas and ethane.

Based on estimated volumes, as of September 30, 2007, Prism Gas had hedged approximately 50%, 50%, 22% and 16% of its commodity risk by volume for 2007, 2008, 2009 and 2010, respectively. The Company 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 Company will be able to do so or that the terms thereof will be similar to the Company’s existing hedging arrangements. In addition, the Company will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil.

Hedging Arrangements in Place


Year	Commodity Hedged	Volume	Type of Derivative	Basis Reference
2007	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($65.95)	NYMEX
2007	Natural Gasoline	4,000 BBL/Month	Crude Oil Swap ($72.35)	NYMEX
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Swap ($9.14)	Henry Hub
2007	Natural Gas	20,000 MMBTU/Month	Natural Gas Basis Swap (-$0.60)	Henry Hub to Centerpoint East
2007	Ethane	8,000 BBL/Month	Ethane Swap ($28.04)	Mt. Belvieu
2008	Condensate & Natural Gasoline	5,000 BBL/Month	Crude Oil Swap ($66.20)	NYMEX
2008	Natural Gas	30,000 MMBTU/Month	Natural Gas Swap ($8.12)	Houston Ship Channel
2008	Ethane	5,000 BBL/Month	Ethane Swap ($27.30)	Mt. Belvieu
2008	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($70.75)	NYMEX
2009	Condensate & Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($69.08)	NYMEX
2009	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($70.90)	NYMEX
2009	Condensate	1,000 BBL/Month	Crude Oil Swap ($70.45)	NYMEX
2010	Natural Gasoline	3,000 BBL/Month	Crude Oil Swap ($72.25)	NYMEX
2010	Condensate	2,000 BBL/Month	Crude Oil Swap ($69.15)	NYMEX

The Company’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

MARTIN MIDSTREAM GP LLC.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2007
(Unaudited)

the Company’s natural gas and NGL sales are made at market-based prices. The Company’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or continuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Company.

(11) Public Equity Offering

In May 2007, the Company completed a public offering of 1,380,000 common units at a price of $42.25 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 64.3% limited partnership interest in the Company. Total proceeds from the sale of the 1,380,000 common units, net of underwriters’ discounts, commissions and offering expenses were $55,933. The General Partner contributed $1,190 in cash to the Company in conjunction with the issuance in order to maintain its 2% general partner interest in the Company. The net proceeds were used to pay down revolving debt under the Company’s credit facility and to provide working capital.

A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows (all amounts are in thousands):


*Proceeds received:*
Sale of common units	$	58,305
General partner contribution		1,190

Total proceeds received	$	59,495


*Use of Proceeds:*
Underwriter’s fees	$	2,107
Professional fees and other costs		265
Repayment of debt under revolving credit facility		55,850
Working capital		1,273

Total use of proceeds	$	59,495

(12) COMMITMENTS AND CONTINGENCIES

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