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EX-32.2 - EX-32.2 - MARTIN MIDSTREAM PARTNERS LPd69910exv32w2.htm
EX-10.3 - EX-10.3 - MARTIN MIDSTREAM PARTNERS LPd69910exv10w3.htm
EX-31.2 - EX-31.2 - MARTIN MIDSTREAM PARTNERS LPd69910exv31w2.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2009
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number
000-50056
MARTIN MIDSTREAM PARTNERS L.P.
(Exact name of registrant as specified in its charter)
     
Delaware   05-0527861
(State or other jurisdiction of   (IRS Employer
incorporation or organization)   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 þ     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 o     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 þ    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 þ
          The number of the registrant’s Common Units outstanding at November 4, 2009 was 13,688,152. The number of the registrant’s subordinated units outstanding at November 4, 2009 was 850,674.
 
 

 


 

         
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CERTIFICATIONS
       
 EX-10.1
 EX-10.2
 EX-10.3
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2

 


Table of Contents

PART I — FINANCIAL INFORMATION
Item 1.   Financial Statements
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Dollars in thousands)
                 
    September 30,     December 31,  
    2009     2008  
    (Unaudited)     (Audited)  
Assets
               
Cash
  $ 5,924     $ 7,983  
Accounts and other receivables, less allowance for doubtful accounts of $829 and $481, respectively
    60,727       68,117  
Product exchange receivables
    8,136       6,924  
Inventories
    40,298       42,461  
Due from affiliates
    2,904       555  
Fair value of derivatives
    2,572       3,623  
Other current assets
    1,365       1,079  
 
           
Total current assets
    121,926       130,742  
 
           
 
               
Property, plant and equipment, at cost
    544,389       537,381  
Accumulated depreciation
    (146,906 )     (125,256 )
 
           
Property, plant and equipment, net
    397,483       412,125  
 
           
 
               
Goodwill
    37,268       37,405  
Investment in unconsolidated entities
    80,603       79,843  
Fair value of derivatives
    240       1,469  
Other assets, net
    6,126       7,332  
 
           
 
  $ 643,646     $ 668,916  
 
           
 
               
Liabilities and Partners’ Capital
               
 
               
Trade and other accounts payable
  $ 62,352     $ 87,382  
Product exchange payables
    19,086       10,924  
Due to affiliates
    13,178       13,420  
Income taxes payable
          414  
Fair value of derivatives
    8,031       6,478  
Current portion of capital lease obligations
    107        
Other accrued liabilities
    5,387       6,077  
 
           
Total current liabilities
    108,141       124,695  
 
               
Long-term debt and capital leases, less current maturities
    306,204       295,000  
Deferred income taxes
    8,608       8,538  
Fair value of derivatives
    931       4,302  
Other long-term obligations
    1,481       1,667  
 
           
Total liabilities
    425,365       434,202  
 
           
 
               
Partners’ capital
    221,346       239,649  
Accumulated other comprehensive income (loss)
    (3,065 )     (4,935 )
 
           
Total partners’ capital
    218,281       234,714  
 
           
Commitments and contingencies
  $ 643,646     $ 668,916  
 
           
See accompanying notes to consolidated and condensed financial statements.

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Table of Contents

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars in thousands, except per unit amounts)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Revenues:
                               
Terminalling and storage *
  $ 9,103     $ 8,527     $ 28,684     $ 26,347  
Marine transportation *
    17,785       20,116       49,222       55,828  
Product sales:*
                               
Natural gas services
    103,061       188,200       268,749       577,317  
Sulfur services
    15,100       133,276       61,029       289,528  
Terminalling and storage
    6,314       14,267       28,853       36,525  
 
                       
 
    124,475       335,743       358,631       903,370  
 
                       
Total revenues
    151,363       364,386       436,537       985,545  
 
                       
 
                               
Costs and expenses:
                               
Cost of products sold: (excluding depreciation and amortization)
                               
Natural gas services *
    96,358       178,996       248,693       562,170  
Sulfur services *
    7,716       121,158       34,742       253,462  
Terminalling and storage
    5,535       11,031       25,558       31,222  
 
                       
    109,609       311,185       308,993       846,854  
 
                       
Expenses:
                               
Operating expenses *
    22,762       26,093       70,169       76,505  
Selling, general and administrative *
    4,088       3,726       12,354       10,672  
Depreciation and amortization
    8,741       7,979       25,657       22,933  
 
                       
Total costs and expenses
    145,200       348,983       417,173       956,964  
 
                       
 
                               
Other operating income
    125       17       5,198       143  
 
                       
Operating income
    6,288       15,420       24,562       28,724  
 
                       
 
                               
Other income (expense):
                               
Equity in earnings of unconsolidated entities
    2,139       3,503       5,227       11,385  
Interest expense
    (4,058 )     (4,971 )     (12,910 )     (13,609 )
Other, net
    68       87       139       334  
 
                       
Total other income (expense)
    (1,851 )     (1,381 )     (7,544 )     (1,890 )
 
                       
Net income before taxes
    4,437       14,039       17,018       26,834  
Income tax benefit (expense)
    80       (292 )     294       (753 )
 
                       
Net income
  $ 4,517     $ 13,747     $ 17,312     $ 26,081  
 
                       
 
                               
General partner’s interest in net income
  $ 800     $ 941     $ 2,475     $ 2,257  
Limited partners’ interest in net income
  $ 3,717     $ 12,806     $ 14,837     $ 23,824  
 
                               
Net income per limited partner unit — basic and diluted
  $ 0.26     $ 0.88     $ 1.02     $ 1.64  
 
                               
Weighted average limited partner units — basic
    14,532,826       14,532,826       14,532,826       14,532,826  
Weighted average limited partner units — diluted
    14,538,231       14,534,972       14,536,792       14,535,025  
 
                               
See accompanying notes to consolidated and condensed financial statements.
 
                               
 
 
                               
*     Related Party Transactions Included Above
                               
 
                               
Revenues:
                               
Terminalling and storage
  $ 4,363     $ 5,142     $ 13,134     $ 13,374  
Marine transportation
    4,776       6,383       14,529       18,826  
Product Sales
    1,340       10,769       4,384       21,782  
Costs and expenses:
                               
Cost of products sold: (excluding depreciation and amortization)
                               
Natural gas services
    17,211       28,051       38,552       77,033  
Sulfur services
    2,756       3,203       9,106       9,919  
Expenses:
                               
Operating expenses
    8,942       9,578       26,850       28,989  
Selling, general and administrative
    1,637       1,329       4,822       3,969  
 
                               

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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL
(Unaudited)
(Dollars in thousands)
                                                         
                                            Accumulated        
    Partners’ Capital     Other        
                                    General     Comprehensive        
    Common     Subordinated     Partner     Income        
    Units     Amount     Units     Amount     Amount     Amount     Total  
Balances — January 1, 2008
    12,837,480     $ 244,520       1,701,346     $ (6,022 )   $ 4,112     $ (6,762 )   $ 235,848  
 
                                                       
Net income
          21,532             2,292       2,257             26,081  
 
                                                       
Cash distributions
          (27,729 )           (3,675 )     (2,448 )           (33,852 )
 
                                                       
Unit-based compensation
          57                               57  
 
                                                       
Purchase of treasury units
          (93 )                             (93 )
 
                                                       
Adjustment in fair value of derivatives
                                  (1,733 )     (1,733 )
 
                                         
 
                                                       
Balances — September 30, 2008
    12,837,480     $ 238,287       1,701,346     $ (7,405 )   $ 3,921     $ (8,495 )   $ 226,308  
 
                                         
 
                                                       
Balances — January 1, 2009
    13,688,152     $ 239,333       850,674     $ (3,688 )   $ 4,004     $ (4,935 )   $ 234,714  
 
                                                       
Net income
          13,969             868       2,475             17,312  
 
                                                       
Cash distributions
          (30,799 )           (1,914 )     (2,884 )           (35,597 )
 
                                                       
Unit-based compensation
          59                               59  
 
                                                       
Purchase of treasury units
          (77 )                             (77 )
 
                                                       
Adjustment in fair value of derivatives
                                  1,870       1,870  
 
                                         
 
                                                       
Balances — September 30, 2009
    13,688,152     $ 222,485       850,674     $ (4,734 )   $ 3,595     $ (3,065 )   $ 218,281  
 
                                         
          See accompanying notes to consolidated and condensed financial statements.

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Table of Contents

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(Dollars in thousands)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Net income
  $ 4,517     $ 13,747     $ 17,312     $ 26,081  
Changes in fair values of commodity cash flow hedges
    115       6,834       103       (1,654 )
Cash flow hedging gains (losses) reclassified to earnings
    (733 )     1,097       (2,078 )     473  
Changes in fair value of interest rate cash flow hedges
    (774 )     (124 )     (1,714 )     (552 )
Interest rate cash flow hedging gains reclassified to earnings
    1,860             5,559        
 
                       
 
                               
Comprehensive income
  $ 4,985     $ 21,554     $ 19,182     $ 24,348  
 
                       
          See accompanying notes to consolidated and condensed financial statements.

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Table of Contents

MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Dollars in thousands)
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Cash flows from operating activities:
               
Net income
  $ 17,312     $ 26,081  
 
               
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    25,657       22,933  
Amortization of deferred debt issuance costs
    842       840  
Deferred taxes
    70       (222 )
Gain on sale of property, plant and equipment
    (5,198 )     (143 )
Equity in earnings of unconsolidated entities
    (5,227 )     (11,385 )
Distributions from unconsolidated entities
    650        
Distributions in-kind from equity investments
    3,990       8,392  
Non-cash mark-to-market on derivatives
    2,332       (1,499 )
Other
    59       57  
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
               
Accounts and other receivables
    7,359       (17,295 )
Product exchange receivables
    (1,212 )     (21,411 )
Inventories
    2,163       (26,204 )
Due from affiliates
    1,707       (5,604 )
Other current assets
    (286 )     (1,548 )
Trade and other accounts payable
    (25,362 )     54,306  
Product exchange payables
    8,162       22,744  
Due to affiliates
    9,202       9,957  
Income taxes payable
    (414 )     (204 )
Other accrued liabilities
    (1,097 )     959  
Change in other non-current assets and liabilities
    (497 )     (111 )
 
           
Net cash provided by operating activities
    40,212       60,643  
 
           
 
               
Cash flows from investing activities:
               
Payments for property, plant and equipment
    (31,684 )     (72,185 )
Acquisitions, net of cash acquired
          (5,983 )
Proceeds from sale of property, plant and equipment
    21,713       419  
Return of investments from unconsolidated entities
    660       995  
Distributions from (contributions to) unconsolidated entities for operations
    (833 )     (1,999 )
 
           
Net cash used in investing activities
    (10,144 )     (78,753 )
 
           
 
               
Cash flows from financing activities:
               
Payments of long-term debt and capital lease obligations
    (84,953 )     (180,391 )
Proceeds from long-term debt
    88,500       235,370  
Purchase of treasury units
    (77 )     (93 )
Payments of debt issuance costs
          (18 )
Cash distributions paid
    (35,597 )     (33,852 )
 
           
Net cash provided by (used in) financing activities
    (32,127 )     21,016  
 
           
 
               
Net increase (decrease) in cash
    (2,059 )     2,906  
 
               
Cash at beginning of period
    7,983       4,113  
 
           
Cash at end of period
  $ 5,924     $ 7,019  
 
           
See accompanying notes to consolidated and condensed financial statements.

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Table of Contents

MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(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, marine transportation services for petroleum products and by-products, and sulfur and sulfur based products processing, manufacturing, marketing and distribution.
          The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and U.S. 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, 2008 filed with the Securities and Exchange Commission (the “SEC”) on March 4, 2009.
          (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 U.S. generally accepted accounting principles. Actual results could differ from those estimates.
          (b) Unit Grants
          The Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in August 2009 from treasury units purchased by the Partnership in the open market for $77. These units vest in 25% increments beginning in January 2010 and will be fully vested in January 2013. The Partnership’s general partner did not make a contribution attributable to the restricted units issued to its three independent, non-employee directors in August 2009, as such units were purchased in the open market by the Partnership.
          The Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan in May 2008 from treasury units purchased by the Partnership in the open market for $93. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012. The Partnership’s general partner did not make a contribution attributable to the restricted units issued to its three independent, non-employee directors in May 2008, as such units were purchased in the open market by the Partnership.
          The Partnership 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 Partnership’s general partner contributed cash of $3 in May 2007 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.
          The Partnership 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. The Partnership’s

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
general partner contributed cash of $2 in January 2006 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.
          The Partnership accounts for the transactions under certain provisions of FASB ASC 505-50-55 related to equity-based payments to non-employees. The cost resulting from the share-based payment transactions was $28 and $28 for the three months ended September 30, 2009 and 2008, respectively, and $59 and $58 for the nine months ended September 30, 2009 and 2008, respectively.
          (c) Incentive Distribution Rights
          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, 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. The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months ended September 30, 2009 and 2008 the general partner received $724 and $680, respectively, in incentive distributions. For the nine months ended September 30, 2009 and 2008 the general partner received $2,172 and $1,771, respectively, in incentive distributions.
          (d) Net Income per Unit
          In March 2008, the FASB amended 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. ASC 260-10 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.
          The Partnership adopted the amended provisions of ASC 260-10 on January 1, 2009. Adoption did not impact the Partnership’s computation of earnings per limited partner unit as cash distributions exceeded earnings for the three and nine months ended September 30, 2009 and 2008, and the IDRs do not share in losses under the partnership agreement. In the event the Partnership’s earnings exceed cash distributions, ASC 260-10 will have an impact on the computation of the Partnership’s earnings per limited partner unit. The Partnership agreement does not explicitly limit distributions to the general partner; therefore, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the Partnership agreement. For the three and nine months ended September 30, 2009 and 2008, 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.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
          The following table reconciles net income to limited partners’ interest in net income:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Net income
  $ 4,517     $ 13,747     $ 17,312     $ 26,081  
Less:
                               
Distributions payable on behalf of IDRs
    (724 )     (680 )     (2,172 )     (1,771 )
Distributions payable on behalf of general partner interest
    (237 )     (233 )     (712 )     (677 )
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest
    161       (28 )     409       191  
 
                       
Limited partners’ interest in net income
  $ 3,717     $ 12,806     $ 14,837     $ 23,824  
 
                       
          The weighted average units outstanding for basic net income per unit was 14,532,826 for both the three and nine months ended September 30, 2009 and 2008. For diluted net income per unit, the weighted average units outstanding were increased by 5,405 and 2,146 for the three months ended September 30, 2009 and 2008, respectively, and 3,966 and 2,199 for the nine months ended September 30, 2009 and 2008, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.
          (e) Income taxes
          With respect to the Partnership’s taxable subsidiary (Woodlawn Pipeline Co., Inc.), 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 2009, the “Financial Accounting Standards Board (“FASB”) issued the Accounting Standards Codification (“ASC”), “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (the “Codification”), which authorized the Codification as the sole source for authoritative U.S. GAAP. Following the Codification, FASB will not issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”) which will serve to update the Codification, provide background information about the guidance and provide the basis for conclusions on the changes to the Codification. The Partnership adopted the Codification for the quarter ended September 30, 2009.
          In May 2009, the FASB amended the provisions of ASC 855 related to subsequent events, to be effective for interim or annual financial periods ending after June 15, 2009. ASC 855 does not materially change the existing guidance but introduces the concept of financial statements being “available to be issued.” It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. This disclosure is intended to alert all users of financial statements that an entity has not evaluated subsequent events after that date in the set of financial statements being presented. ASC 855 became effective for the Partnership on April 1, 2009, and the adoption did not have an impact on its financial statements. The Partnership has evaluated subsequent events through November 4, 2009, which is the date of the filing of its quarterly report on Form 10-Q. (See Note 16 for more information regarding subsequent events).
          In April 2009, the FASB amended the provisions of ASC 820-10-65-4 related to determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly, which provides additional guidance for estimating fair value in accordance with ASC 820 related to fair value measurements, when the volume and level of activity for the asset or liability have significantly decreased. This pronouncement also includes guidance on identifying circumstances that indicate a transaction is not orderly. The Partnership adopted this pronouncement on

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
April 1, 2009. The adoption did not have a material effect on the Partnership’s financial position or results of operations.
          In April 2009, FASB amended the provisions of ASC 825-10-65 related to interim disclosures about fair value of financial instruments, which requires disclosures about fair value of financial instruments for interim reporting periods as well as in annual financial statements for interim reporting periods ending after June 15, 2009. The Company adopted certain provisions of ASC 825-10-65 effective April 1, 2009.
          In April 2009, the FASB amended the provisions of ASC 805-10, 805-20 and 805-30 related to accounting for assets acquired and liabilities assumed in a business combination that arise from contingencies, to amend the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under ASC. Under the new guidance, assets acquired and liabilities assumed in a business combination that arise from contingencies should be recognized at fair value on the acquisition date if fair value can be determined during the measurement period. If fair value cannot be determined, companies should typically account for the acquired contingencies using existing guidance. The Partnership adopted this guidance on January 1, 2009. As the provisions of this guidance are applied prospectively to business combinations with an acquisition date on or after the guidance became effective, the impact to the Partnership cannot be determined until the transactions occur. No such transactions have occurred during 2009.
          In March 2008, the FASB amended 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. ASC 260-10 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Partnership adopted this guidance on January 1, 2009. See Note 1(d) for more information.
          In March 2008, FASB amended the provisions of ASC 815-10-65 related to disclosures about derivative instruments and hedging activities, which requires enhanced disclosures concerning (1) the manner in which an entity uses derivatives (and the reasons it uses them), (2) the manner in which derivatives and related hedged items are accounted for and (3) the effects that derivatives and related hedged items have on an entity’s financial position, financial performance and cash flows. ASC 815-10-65 is effective for financial statements issued for fiscal years and interim periods beginning on or after November 15, 2008. The Partnership adopted this guidance on January 1, 2009, and the adoption did not have a material impact on the Partnership’s financial position or results of operations.
          In December 2007, the FASB amended the provisions of ASC 810-10-65 related to noncontrolling interests in consolidated financial statements, which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. ASC 810-10-65 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, ASC 810-10-65 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. The amendments to ASC 810-10-65 were effective for the Partnership on January 1, 2009. The adoption of certain provisions of ASC 810-10-65 had no impact on the Partnership’s consolidated financial statements. However, it could impact accounting for future transactions.
          In December 2007, FASB amended the provisions of ASC 805-10-65 related to business combinations, which establishes principles and requirements for how an acquiror in a business combination (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase price and (3) determines what information to disclose to enable users of the consolidated financial statements to evaluate the nature and financial effects of the business combination. ASC 805-10-65 applies prospectively to business combinations for which the

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Partnership adopted certain provisions of ASC 805-10-65 on January 1, 2009. The application of ASC 805-10-65 will cause management to evaluate future transactions under different conditions than previously completed significant acquisitions, particularly related to the near-term and long-term economic impact of expensing transaction costs. No such transactions have occurred during 2009.
          In September 2006, the FASB amended the provisions of ASC Topic 820 related to fair value measurements and disclosures, which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value and expanding disclosures about fair value measurements. ASC 820 does not require any new fair value measurements. The Partnership adopted ASC 820 as of January 1, 2008, with the exception of the application of the statement to non-recurring nonfinancial assets and nonfinancial liabilities, which was delayed to fiscal years beginning after November 15, 2008, which the Partnership therefore adopted as of January 1, 2009. As of September 30, 2009, the Partnership does not have any significant non-recurring measurements of nonfinancial assets and nonfinancial liabilities. See Note 7 — Fair Value Measurements for further information.
          Accounting Standards Not Yet Adopted
          In August 2009, the FASB issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 provides clarification regarding valuation techniques when a quoted price in an active market for an identical liability is not available in addition to treatment of the existence of restrictions that prevent the transfer of a liability. Update 2009-05 also clarifies that both a quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market (when no adjustments to the quoted price of the asset are required) are Level 1 fair value measurements. This update is effective for the first reporting period, including interim periods, beginning after August 27, 2009. The Partnership is currently assessing the impact Update 2009-05 will have on its financial statements.
          In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS 167”). As of September 30, 2009, SFAS 167 has not been incorporated within the FASB ASC. SFAS 167 amends previous accounting related to the Consolidation of Variable Interest Entities to require an enterprise to qualitatively assess the determination of the primary beneficiary of a variable interest entity (VIE) based on whether the entity (1) has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and (2) has the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the VIE. Also, SFAS 167 requires an ongoing reconsideration of the primary beneficiary, and amends the events that trigger a reassessment of whether an entity is a VIE. Enhanced disclosures are also required to provide information about an enterprise’s involvement in a VIE. This guidance is effective as of the beginning of the first fiscal year that begins after November 15, 2009. The Partnership is currently assessing the impact SFAS 167 will have on its financial statements.
(3) Acquisitions
          Stanolind Assets — In January 2008, the Partnership acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management for $5,983 which was allocated to property, plant and equipment. Martin Resource Management entered into a lease agreement with the Partnership for use of the sulfuric acid tanks. In connection with the acquisition, the Partnership borrowed approximately $6,000 under its credit facility.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
(4) Inventories
          Components of inventories at September 30, 2009 and December 31, 2008 were as follows:
                 
    September 30,     December 31,  
    2009     2008  
Natural gas liquids
  $ 22,014     $ 10,530  
Sulfur
    249       6,522  
Sulfur based products
    10,573       14,879  
Lubricants
    4,875       8,110  
Other
    2,587       2,420  
 
           
 
  $ 40,298     $ 42,461  
 
           
(5) Investments in Unconsolidated Entities and Joint Ventures
          The Partnership’s Prism Gas Systems I, L.P. (“Prism Gas”) subsidiary owns an unconsolidated 50% interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these assets are accounted for by the equity method.
          On June 30, 2006, the Partnership’s Prism Gas subsidiary, acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). The lease contract terminated in June 2009, and, as such, the investment was fully amortized as of June 30, 2009.
          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 for both the three months ended September 30, 2009 and 2008, respectively and $444 for both the nine months ended September 30, 2009 and 2008, 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 $9,646 and $10,092 at September 30, 2009 and December 31, 2008, respectively. The equity-method goodwill is not amortized; however, it is analyzed for impairment annually or if changes in circumstance indicate that a potential impairment exists. No impairment was recognized for the nine months ended September 30, 2009 or 2008.
          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 nine months ended September 30, 2009 and 2008 is as follows:
                                         
    Waskom     PIPE     Matagorda     BCP     Total  
Investment in unconsolidated entities, December 31, 2008
  $ 74,978     $ 1,214     $ 3,559     $ 92     $ 79,843  
 
                                       
Distributions in kind
    (3,990 )                       (3,990 )
Distributions from unconsolidated entities
    (650 )                       (650 )
Contributions to unconsolidated entities:
                                       
Cash contributions
          90                   90  
Contributions to unconsolidated entities for operations
    743                         743  
Return of investments
          (395 )     (265 )           (660 )
Equity in earnings:
                                       
Equity in earnings (losses) from operations
    5,071       573       119       (92 )     5,671  
Amortization of excess investment
    (412 )     (11 )     (21 )           (444 )
 
                             
Investment in unconsolidated entities, September 30, 2009
  $ 75,740     $ 1,471     $ 3,392     $ -—     $ 80,603  
 
                             

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
                                         
    Waskom     PIPE     Matagorda     BCP     Total  
Investment in unconsolidated entities, December 31, 2007
  $ 70,237     $ 1,582     $ 3,693     $ 178     $ 75,690  
 
                                       
Distributions in kind
    (8,392 )                       (8,392 )
Contributions to (distributions from) unconsolidated entities:
                                       
Cash contributions
    1,250                   80       1,330  
Contributions to (distributions from) unconsolidated entities for operations
    669                         669  
 
                                       
Return of investments
    (300 )     (180 )     (515 )           (995 )
Equity in earnings:
                                       
Equity in earnings from operations
    11,451       17       485       (124 )     11,829  
Amortization of excess investment
    (412 )     (11 )     (21 )           (444 )
 
                             
 
                                       
Investment in unconsolidated entities, September 30, 2008
  $ 74,503     $ 1,408     $ 3,642     $ 134     $ 79,687  
 
                             
          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     Partners’             Net             Net  
    Assets     Capital     Revenues     Income     Revenues     Income  
2009
                                               
Waskom
  $ 83,280     $ 70,079     $ 21,027     $ 4,158     $ 48,645     $ 10,142  
 
                                   
                                                 
    As of December 31                                  
2008
                                               
Waskom
  $ 78,661     $ 67,730     $ 34,113     $ 7,154     $ 96,653     $ 22,902  
 
                                   
          As of September 30, 2009 and December 31, 2008 the amount of the Partnership’s consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity method investees is $31,127 and $27,208, 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 September 30, 2009 and December 31, 2008, the Partnership’s interest in cash of the unconsolidated equity method investees was $880 and $1,956, respectively.
(6) Derivative Instruments and Hedging Activities
          The Partnership’s results of operations are materially impacted by changes in crude oil, natural gas and natural gas liquids prices and interest rates. In an effort to manage our exposure to these risks, we periodically enter into various derivative instruments, including commodity and interest rate hedges. We are required to recognize all derivative instruments as either assets or liabilities at fair value on our Consolidated Balance Sheets and to recognize certain changes in the fair value of derivative instruments on our Consolidated Statements of Operations.
          The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of our hedge contracts, including assessing the possibility of counterparty default. If we determine that a derivative is no longer expected to be highly effective, we discontinue hedge accounting prospectively and recognize subsequent changes in the fair value of the hedge in earnings. As a result of our effectiveness assessment at September 30, 2009, we believe certain hedge contracts will continue to be effective in offsetting changes in cash flow or fair value attributable to the hedged risk.
          All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings. The Partnership is exposed to the risk that periodic changes in the fair value of derivatives qualifying for hedge accounting will not be effective, as defined, or that derivatives will no longer qualify for hedge accounting. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is recorded to earnings. Likewise, if a hedge ceases to qualify for hedge accounting, any change in the fair value of derivative instruments since the last period is recorded to earnings; however, any amounts previously recorded to AOCI would remain there until such time as the original forecasted

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
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 accumulated other comprehensive income 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.
          In March 2008, the FASB amended the provisions of ASC Topic 820 related to fair value measurements and disclosures, which changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted this guidance on January 1, 2009.
          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 2010 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 September 30, 2009 and 2008, the Partnership has both derivative instruments qualifying for hedge accounting with fair value changes being recorded in AOCI as a component of partners’ capital and derivative instruments not designated as hedges being marked to market with all market value adjustments being recorded in earnings.
          Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2009 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of September 30, 2009, the remaining term of the contracts extend no later than December 2010, with no single contract longer than one year. For the three and nine months ended September 30, 2009, 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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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
                     
    Total                
    Volume       Remaining Terms        
Transaction Type   Per Month   Pricing Terms   of Contracts        
 
Mark to Market Derivatives::
                   
 
                   
Crude Oil Swap
  3,000 BBL   Fixed price of $69.08 settled against WTI NYMEX average monthly closings   October 2009 to December 2009   $ (8 )
 
                   
Crude Oil Swap
  3,000 BBL   Fixed price of $70.90 settled against WTI NYMEX average monthly closings   October 2009 to December 2009     9  
 
                   
Crude Oil Swap
  1,000 BBL   Fixed price of $70.45 settled against WTI NYMEX average monthly closings   October 2009 to December 2009     2  
 
                   
Crude Oil Swap
  3,000 BBL   Fixed price of $72.25 settled against WTI NYMEX average monthly closings   January 2010 to December 2010     (54 )
 
                   
Crude Oil Swap
  2,000 BBL   Fixed price of $69.15 settled against WTI NYMEX average monthly closings   January 2010 to December 2010     (106 )
 
                   
Crude Oil Swap
  1,000 BBL   Fixed price of $104.80 settled against WTI NYMEX average monthly closings   January 2010 to December 2010     370  
 
                   
Total swaps not designated as cash flow hedges           $ 213  
 
                   
Cash Flow Hedges:
                   
 
                   
Natural Gas swap
  30,000 MMBTU   Fixed price of $9.025 settled against Inside Ferc Columbia Gulf daily average   October 2009 to December 2009   $ 389  
 
                   
Natural Gasoline Swap
  2,000 BBL   Fixed price of $86.42 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.   October 2009 to December 2009     160  
 
                   
Natural Gasoline Swap
  1,000 BBL   Fixed price of $94.14 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings   January 2010 to December 2010     379  
 
                   
 
                   
Total swaps designated as cash flow hedges       $ 928    
 
                   
Total net fair value of commodity derivatives       $ 1,141  
          Based on estimated volumes, as of September 30, 2009, the Partnership had hedged approximately 56% and 27% of its commodity risk by volume for 2009 and 2010, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.
          The Partnership’s credit exposure related to commodity cash flow hedges is represented by the positive fair value of contracts to the Partnership at September 30, 2009. These outstanding contracts expose the Partnership to credit loss in the event of nonperformance by the counterparties to the agreements. The Partnership has incurred no losses associated with counterparty nonperformance on derivative contracts.
          On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, 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 three counterparties containing collateral provisions. Based on

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
those current agreements, cash deposits are required to be posted whenever the net fair value of derivatives associated with the individual counterparty exceed a specific threshold. If this threshold is exceeded, cash is posted by the Partnership if the value of derivatives is a liability to the Partnership. As of September 30, 2009 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.
Impact of Commodity Cash Flow Hedges
          Crude Oil
          For the three months ended September 30, 2009 and 2008, gains on swap hedge contracts increased crude revenue by $145 and $4,079, respectively. For the nine months ended September 30, 2009 and 2008, losses on swap hedge contracts decreased crude revenue by $541 and $1,958, respectively. As of September 30, 2009 an unrealized derivative fair value gain of $811 related to current and terminated cash flow hedges of crude oil price risk was recorded in AOCI. Fair value gains of $40, $148 and $623 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at September 30, 2009 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 September 30, 2009 and 2008, gains on swap hedge contracts increased gas revenue by $511 and $811, respectively. For the nine months ended September 30, 2009 and 2008, net gains and losses on swap hedge contracts increased gas revenue by $1,383 and decreased gas revenue by $515, respectively. As of September 30, 2009 an unrealized derivative fair value gain of $389 related to cash flow hedges of natural gas was recorded in AOCI. This fair value gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.
          Natural Gas Liquids
          For the three months ended September 30, 2009 and 2008, net gains and losses on swap hedge contracts increased liquids revenue by $232 and decreased liquids revenue by $81, respectively. For the nine months ended September 30, 2009 and 2008, net gains and losses on swap hedge contracts increased liquids revenue by $36 and decreased liquids revenue by $827, respectively. As of September 30, 2009, an unrealized derivative fair value gain of $1,369 related to current and terminated cash flow hedges of natural gas liquids price risk was recorded in AOCI. Fair value gains of $160, $317 and $892 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at September 30, 2009 adjusted for any impairment, 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)
September 30, 2009
(Unaudited)
Interest Rate Derivative Instruments
          The Partnership is exposed to market risks associated with interest rates. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate debt and term loan credit facilities. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings.
          The Partnership has entered into several cash flow hedge agreements with an aggregate notional amount of $205,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities.
          The Partnership designated the following swap agreements as cash flow hedges. Under these swap agreements, the Partnership pays a fixed rate of interest and receives a floating rate based on a one-month or three-month U.S. Dollar LIBOR rate to match the floating rates of the bank facility at which the Partnership periodically elects to borrow. Because these swaps are 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 these hedges, these swaps were 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 these swaps remain equal. This condition results in a 100% effective swap for the following hedges:
                         
            Paying   Receiving    
Date of Hedge   Notional Amount   Fixed Rate   Floating Rate   Maturity Date
April 2009
  $ 40,000       1.000 %   1 Month LIBOR   October 2010
April 2009
  $ 25,000       0.720 %   1 Month LIBOR   January 2010
March 2009
  $ 25,000       1.290 %   1 Month LIBOR   September 2010
March 2009
  $ 40,000       0.970 %   1 Month LIBOR   December 2009
February 2009
  $ 75,000       1.295 %   1 Month LIBOR   November 2010
          The following interest rate swaps have been de-designated as cash flow hedges by the Partnership:
                         
            Paying   Receiving    
Date of Hedge   Notional Amount   Fixed Rate   Floating Rate   Maturity Date
September 2007
  $ 25,000       4.605 %   3 Month LIBOR   September 2010
November 2006
  $ 40,000       4.820 %   3 Month LIBOR   December 2009
March 2006
  $ 75,000       5.250 %   3 Month LIBOR   November 2010
October 2008
  $ 40,000       2.820 %   3 Month LIBOR   October 2010
January 2008
  $ 25,000       3.400 %   3 Month LIBOR   January 2010
          The following interest rate swaps have not been designated as cash flow hedges by the Partnership:
                         
            Paying   Receiving    
Date of Hedge   Notional Amount   Fixed Rate   Floating Rate   Maturity Date
November 2006
  $ 30,000       4.765 %   3 Month LIBOR   March 2010
                         
            Receiving   Paying    
Date of Hedge   Notional Amount   Fixed Rate   Floating Rate   Maturity Date
April 2009
  $ 25,000       1.070 %   3 Month LIBOR   January 2010
April 2009
  $ 40,000       1.240 %   3 Month LIBOR   October 2010
March 2009
  $ 40,000       1.420 %   3 Month LIBOR   December 2009
March 2009
  $ 25,000       1.590 %   1 Month LIBOR   September 2010
February 2009
  $ 75,000       1.445 %   1 Month LIBOR   November 2010
          These swaps have been recorded at fair value with an offset to current earnings.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
          The Partnership recognized increases in interest expense of $1,959 and $5,559 for the three and nine months ended September 30, 2009, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate hedges.
          The Partnership recognized increases in interest expense of $916 and $1,882 for the three and nine months ended September 30, 2008, 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 hedges.
          The net effective fixed rate for the Partnership’s hedged portion of long-term debt is 4.20% as of September 30, 2009. See Note 10 for more information on the Partnership’s long-term debt and related interest rates.
          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” within this Note.
Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items
          The following table summarizes the fair values and classification of our derivative instruments in our Condensed and Consolidated Balance Sheet:
                                                 
    Fair Values of Derivative Instruments in the Consolidated Balance Sheet
    Derivative Assets     Derivative Liabilities  
            Fair Values             Fair Values  
            September 30,     December 31,             September 30,     December 31,  
    Balance Sheet Location     2009     2008     Balance Sheet Location     2009     2008  
Derivatives designated as hedging instruments:
  Current:                   Current:                
Interest rate contracts
  Fair value of derivatives   $     $     Fair value of derivatives   $ 1,104     $ 5,427  
Commodity contracts
  Fair value of derivatives     838       2,430     Fair value of derivatives            
 
                                       
 
            838       2,430               1,104       5,427  
 
                                       
 
                                               
 
  Non-current:                   Non-current:                
Interest rate contracts
  Fair value of derivatives     6           Fair value of derivatives           4,050  
Commodity contracts
  Fair value of derivatives     90       716     Fair value of derivatives            
 
                                       
 
            96       716                     4,050  
 
                                       
 
                                               
Total derivatives designated as hedging instruments
          $ 934     $ 3,146             $ 1,104     $ 9,477  
 
                                       
 
                                               
Derivatives not designated as hedging instruments:
  Current:                   Current:                
Interest rate contracts
  Fair value of derivatives   $ 1,441     $     Fair value of derivatives   $ 6,824     $ 1,051  
Commodity contracts
  Fair value of derivatives     293       1,193     Fair value of derivatives     103        
 
                                       
 
            1,734       1,193               6,927       1,051  
 
                                       

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
                                                 
    Derivative Assets     Derivative Liabilities  
            Fair Values             Fair Values  
            September 30,     December 31,             September     December 31,  
    Balance Sheet Location     2009     2008     Balance Sheet Location     30, 2009     2008  
 
  Non-current:                   Non-current:                
Interest rate contracts
  Fair value of derivatives     57           Fair value of derivatives     867       252  
Commodity contracts
  Fair value of derivatives     87       753     Fair value of derivatives     64        
 
                                       
 
            144       753               931       252  
 
                                       
 
                                               
Total derivatives not designated as hedging instruments
          $ 1,878     $ 1,946             $ 7,858     $ 1,303  
 
                                       
Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Three Months Ended September 30, 2009 and 2008
                                                                 
                                            Ineffective Portion and Amount  
    Effective Portion     Excluded from Effectiveness Testing  
                    Location of Gain     Amount of Gain or     Location of     Amount of Gain or  
    Amount of Gain or     or (Loss)     (Loss) Reclassified     Gain or (Loss)     (Loss) Recognized  
    (Loss) Recognized in     Reclassified from     from Accumulated     Recognized in     in Income on  
    OCI on Derivatives     Accumulated OCI     OCI into Income     Income on     Derivatives  
    2009     2008     into Income     2009     2008     Derivatives     2009     2008  
Derivatives designated as hedging instruments
                                                               
 
                                                               
 
Interest rate contracts
  $ (774 )   $ (124 )   Interest Expense   $ (1,860 )   $     Interest Expense   $     $  
 
                                                               
Commodity contracts
    115       6,834     Natural Gas Services Revenues     733       (3,188 )   Natural Gas Services Revenues           2,091  
 
                                                   
 
                                                               
Total derivatives designated as hedging instruments
  $ (659 )   $ 6,710             $ (1,127 )   $ 3,188             $     $ 2,091  
 
                                                   
                     
        Amount of Gain or  
    Location of Gain or (Loss)   (Loss) Recognized in  
    Recognized in Income on   Income on Derivatives  
    Derivatives   2009     2008  
Derivatives not designated as hedging instruments
                   
 
Interest rate contracts
  Interest Expense   $ (99 )   $ (916 )
Commodity contracts
  Natural Gas Services Revenues     155       5,906  
 
               
Total derivatives not designated as hedging instruments
      $ 56     $ 4,990  
 
               

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Nine Months Ended September 30, 2009 and 2008
                                                                 
                                            Ineffective Portion and Amount  
    Effective Portion     Excluded from Effectiveness Testing  
                    Location of Gain     Amount of Gain or     Location of     Amount of Gain or  
    Amount of Gain or     or (Loss)     (Loss) Reclassified     Gain or (Loss)     (Loss) Recognized  
    (Loss) Recognized in     Reclassified from     from Accumulated     Recognized in     in Income on  
    OCI on Derivatives     Accumulated OCI     OCI into Income     Income on     Derivatives  
    2009     2008     into Income     2009     2008     Derivatives     2009     2008  
Derivatives designated as hedging instruments
                                                               
 
                                                               
Interest rate contracts
  $ (1,714 )   $ (552 )   Interest Expense   $ (5,559 )   $     Interest Expense   $     $  
 
                                                               
Commodity contracts
    103       (1,654 )   Natural Gas Services Revenues     2,099       (2,601 )   Natural Gas Services Revenues     (21 )     2,128  
 
                                                   
 
                                                               
Total derivatives designated as hedging instruments
  $ (1,611 )   $ (2,206 )           $ 3,460     $ (2,601 )           $ (21 )   $ 2,128  
 
                                                   
                     
        Amount of Gain or  
    Location of Gain or (Loss)   (Loss) Recognized in  
    Recognized in Income on   Income on Derivatives  
    Derivatives   2009     2008  
Derivatives not designated as hedging instruments
                   
 
                   
Interest rate contracts
  Interest Expense   $ (306 )   $ (1,882 )
Commodity contracts
  Natural Gas Services Revenues     (1,200 )     (2,827 )
 
               
Total derivatives not designated as hedging instruments
      $ (1,506 )   $ (4,709 )
 
               
          Amounts expected to be reclassified into earnings for the subsequent twelve month period are losses of $5,998 for interest rate cash flow hedges and gains of $1,018 for commodity cash flow hedges.
(7) Fair Value Measurements
          During the first quarter of 2008, the Partnership adopted certain provisions of ASC 820 related to fair value measurements and disclosures, which established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of this guidance had no impact on the Partnership’s financial position or results of operations.
          ASC 820 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value into one of the following categories:

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
     Level 1: Quoted market prices in active markets for identical assets or liabilities.
     Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.
     Level 3: Unobservable inputs that are not corroborated by market data.
          The Partnership’s derivative instruments, which consist of commodity and interest rate swaps, are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets, which is considered Level 2. Refer to Note 6 for further information on the Partnership’s derivative instruments and hedging activities.
          The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at September 30, 2009:
                                 
    Fair Value Measurements at Reporting Date Using  
            Quoted Prices in     Significant        
            Active Markets     Other     Significant  
            for     Observable     Unobservable  
    September     Identical Assets     Inputs     Inputs  
Description   30, 2009     (Level 1)     (Level 2)     (Level 3)  
Assets
                               
Interest rate derivatives
  $ 1,504     $     $ 1,504     $  
Commodity derivatives
    1,308             1,308        
 
                       
Total assets
  $ 2,812     $     $ 2,812     $  
 
                       
Liabilities
                               
Interest rate derivatives
  $ (8,795 )   $     $ (8,795 )   $  
Commodity derivatives
    (167 )           (167 )      
 
                       
Total liabilities
  $ (8,962 )   $     $ (8,962 )   $  
 
                       
 
                               
          The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at December 31, 2008:
                                 
    Fair Value Measurements at Reporting Date Using  
            Quoted Prices in     Significant        
            Active Markets     Other     Significant  
        for     Observable     Unobservable  
    December 31,     Identical Assets     Inputs     Inputs  
Description   2008     (Level 1)     (Level 2)     (Level 3)  
Assets
                               
Commodity derivatives
  $ 5,092     $     $ 5,092     $  
 
                       
 
                               
Liabilities
                               
Interest rate derivatives
  $ (10,780 )   $     $ (10,780 )   $  
 
                       
          During the second quarter of 2009, the Partnership adopted certain provisions of ASC 825-10-65, which requires disclosures about fair value of financial instruments for interim reporting periods as well as in annual financial statements for interim reporting periods ending after June 15, 2009. The basis for fair value estimates are set forth below for the Partnership’s financial instruments.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
          The following methods and assumptions were used to estimate the fair value of each class of financial instrument:
    Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable and due from/to affiliates — The carrying amounts approximate fair value because of the short maturity of these instruments.
 
    Long-term debt including current installments — The carrying amount of the revolving and term loan facilities approximates fair value due to the debt having a variable interest rate.
(8) Related Party Transactions
          Martin Resource Management owns 4,334,143 of the Partnership’s common units and 850,674 subordinated units collectively representing approximately 35.7% of the Partnership’s outstanding limited partnership units. The Partnership’s general partner is a wholly-owned subsidiary of Martin Resource Management. The Partnership’s general partner owns a 2.0% general partner interest in the Partnership and the Partnership’s incentive distribution rights. The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership of approximately 35.7% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.
          The following is a description of the Partnership’s material related party transactions:
          Omnibus Agreement. The Partnership and its general partner are parties to an omnibus agreement with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain of Martin Resource Management’s trade names and trademarks. The omnibus agreement contains certain non-competition provisions applicable to Martin Resource Management as long as Martin Resource Management controls the Partnership’s general partner. Under the omnibus agreement, Martin Resource Management provides the Partnership with corporate staff and support services that are substantially identical in nature and quality to the services previously provided by Martin Resource Management in connection with its management and operation of the Partnership’s assets during the one-year period prior to the date of the agreement. The omnibus agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of its business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, Martin Resource Management, is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses. Under the omnibus agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2,000 through November 1, 2007 when the cap expired. For the years ended December 31, 2009 and 2008, the conflicts committee of the Partnership’s general partner approved reimbursement amounts of $3,542 and $2,694, respectively, reflecting the Partnership’s allocable share of such expenses. The conflicts committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses cover all of the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management’s retained businesses. The provisions of the omnibus agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the Partnership’s general partner. The omnibus agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the conflicts committee of the Partnership’s general partner’s board of directors. For purposes of the omnibus agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of the then-applicable limitation on the reimbursable amount of indirect general and administrative expenses. Under the omnibus agreement, Martin Resource Management has granted the Partnership a nontransferable,

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates. The omnibus agreement may be amended by written agreement of the parties; provided, however that it may not be amended without the approval of the conflicts committee of the Partnership’s general partner if such amendment would adversely affect the Partnership’s unitholders. The omnibus agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on behalf of the Partnership, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.
          Motor Carrier Agreement. The Partnership is a party to a motor carrier agreement effective January 1, 2006 with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. This agreement replaced a prior agreement between the Partnership and Martin Transport, Inc. for land transportation services. Under the agreement, Martin Transport agreed to ship the Partnership’s NGL shipments as well as other liquid products. This agreement was amended in November 2006, January 2007, April 2007 and January 2008 to add additional point-to-point rates and to lower certain fuel and insurance surcharges being charged to the Partnership. The agreement has an initial term that expired in December 2007 but which automatically renewed through December 2008. This agreement will continue to automatically renew for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice. Under this agreement, Martin Transport transports the Partnership’s NGL shipments as well as other liquid products. The Partnership’s shipping rates were fixed for the first year of the agreement, subject to certain cost adjustments. These rates are subject to any adjustment to which the parties mutually agree or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list. Under this Agreement, Martin Transport has indemnified the Partnership against all claims arising out of the negligence or willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. The Partnership indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of the Partnership and its officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport and the Partnership, indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.
          Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which it provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. This agreement replaced a prior agreement between the Partnership and Martin Resource Management covering marine transportation services which expired November 2005. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.
          Product Storage Agreement. The Partnership is a party to a product storage agreement with Martin Resource Management under which it leases storage space at Martin Resource Management’s underground storage facility located in Arcadia, Louisiana. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The Partnership’s per-unit cost under this agreement may be adjusted annually based on a price index. The Partnership indemnified Martin Resource Management from any damages resulting from the Partnership’s delivery of products that are contaminated or otherwise fail to conform to the product specifications established in the agreement, as well as any damages resulting from its transportation, storage, use or handling of products.
          Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management under which Martin Resource Management provides it with marine fuel at its docks located in Mobile, Alabama,

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
Theodore, Alabama, Pascagoula, Mississippi and Tampa, Florida. The Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by these docks under this agreement. Martin Resource Management provides fuel at an established margin above its cost on a spot-contract basis. This agreement had an initial term that expired in October 2005 and automatically renews for consecutive one- year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Effective January 1, 2006 a new agreement was entered into under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate over the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil.
          Throughput Agreement. The Partnership was a party to an agreement under which Martin Resource Management agreed to provide it with sole access to and use of a NGL truck loading and unloading and pipeline distribution terminal located at Mont Belvieu, Texas. This agreement automatically renewed each November 1 for consecutive one-year periods unless either party terminated the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The Partnership’s throughput fee was adjusted annually based on a price index. This agreement was terminated in April 2009 as a result of the sale of the Mt. Belvieu railcar unloading facility described in Note 13.
          Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement. The Partnership entered into a Purchaser Use Easement, Ingress-Egress Easement and Utility Facilities Easement with Martin Resource Management under which it has complete, non-exclusive access to, and use of, all marine terminal facilities, all loading and unloading facilities for vessels, barges and trucks and other common use facilities located at the Stanolind terminal. This easement has a perpetual duration. The Partnership did not incur any expenses, costs or other financial obligations under the easement. Martin Resource Management is obligated to maintain, and repair all common use areas and facilities located at this terminal. The Partnership shares the use of these common use areas and facilities only with Martin Resource Management who also have tanks located at the Stanolind facility.
          Terminal Services Agreements. The Partnership entered into terminal services agreements under which it provides terminalling services to Martin Resource Management. These agreements automatically renew on a month-to-month basis until either party terminates the agreements by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term. The per gallon throughput fee the Partnership charges under these agreements may be adjusted annually based on a price index.
          Specialty Terminal Services Agreement. The Partnership entered into an agreement under which Martin Resource Management provides certain specialty terminal services to it. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The fees the Partnership charges under this agreement are adjusted annually based on a price index.
          Lubricants and Drilling Fluids Terminal Services Agreement. The Partnership is a party to a Lubricants and Drilling Fluids Terminal Services Agreement under which Martin Resource Management provides terminal services to the Partnership. Effective each January 1 this agreement, which was amended in July 2004, automatically renews for successive one-year terms until either party terminates the agreement by giving written notice to the other party at least 60 days prior to the end of the then-applicable term. The per gallon handling fee and the percentage of the Partnership’s commissions it is charged under this agreement may be adjusted annually based on a price index.
          Cross Terminalling Agreement. The Partnership is party to the Cross Terminalling Agreement under which it provides terminalling services to Cross Oil Refining & Marketing, Inc., an affiliate of Martin Resource Management. This agreement expired on October 27, 2008 and the Partnership entered into a new five-year agreement which expires October 31, 2013. The per gallon throughput fee the Partnership charges under this agreement may be adjusted during each year of the agreement.
          Sulfuric Acid Sales Agency Agreement. The Partnership is party to a Sulfuric Acid Sales Agency Agreement under which Martin Resource Management purchases and markets the sulfuric acid produced by

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
the Partnership’s sulfuric acid production plant at Plainview, Texas, and which is not consumed by the Partnership’s internal operations. This agreement, which was amended and restated in August 2008 and further amended in July 2009, will remain in place until the Partnership terminates it by providing 180 days’ written notice. Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third-parties.
          Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.
          Waskom Agreements. Prism Gas is a party to a product purchase agreement and a gas processing agreement with Waskom whereby Prism Gas purchases product from and supplies product to Waskom. These intercompany transactions totaled approximately $14,450 and $31,499 for the three and nine months ended September 30, 2009. In addition, Prism Gas provides certain administrative services for Waskom pursuant to Waskom’s partnership agreement.
          The tables below summarize the related party transactions that are included in the related financial statement captions on the face of the Partnership’s Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the consolidated financial statement and do not reflect a statement of profits and losses for related party transactions.
          The impact of related party revenues from sales of products and services is reflected in the consolidated financial statement as follows:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Revenues:
                               
Terminalling and storage
  $ 4,363     $ 5,142     $ 13,134     $ 13,374  
Marine transportation
    4,776       6,383       14,529       18,826  
Product sales:
                               
Natural gas services
    36       1,876       190       3,950  
Sulfur services
    1,236       8,867       4,115       17,788  
Terminalling and storage
    68       26       79       44  
 
                       
 
    1,340       10,769       4,384       21,782  
 
                       
 
  $ 10,479     $ 22,294     $ 32,047     $ 53,982  
 
                       
          The impact of related party cost of products sold is reflected in the consolidated financial statement as follows:
                                 
Cost of products sold:
                               
Natural gas services
  $ 17,211     $ 28,051     $ 38,552     $ 77,033  
Sulfur services
    2,756       3,203       9,106       9,919  
Terminalling and storage
    29       25       258       322  
 
                       
 
  $ 19,996     $ 31,279     $ 47,916     $ 87,274  
 
                       
          The impact of related party operating expenses is reflected in the consolidated financial statement as follows:
                                 
Expenses:
                               
Operating expenses
                               
Marine transportation
  $ 5,065     $ 5,755     $ 14,718     $ 17,956  
Natural gas services
    302       391       1,116       1,164  
Sulfur services
    1,296       1,040       3,309       2,909  
Terminalling and storage
    2,279       2,392       7,707       6,960  
 
                       
 
  $ 8,942     $ 9,578     $ 26,850     $ 28,989  
 
                       

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
          The impact of related party selling, general and administrative expenses is reflected in the consolidated financial statement as follows:
                                 
Selling, general and administrative:
                               
Natural gas services
  $ 261     $ 176     $ 654     $ 561  
Sulfur services
    501       479       1,542       1,387  
Terminalling and storage
                       
Indirect overhead allocation, net of reimbursement
    875       674       2,626       2,021  
 
                       
 
  $ 1,637     $ 1,329     $ 4,822     $ 3,969  
 
                       
(9) Business Segments
          The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.
          The accounting policies of the operating segments are the same as those described in Note 2 in the Partnership’s annual report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 4, 2009. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.
                                                 
                    Operating             Operating        
            Intersegment     Revenues     Depreciation     Income (loss)        
    Operating     Revenues     after     and     after     Capital  
    Revenues     Eliminations     Eliminations     Amortization     eliminations     Expenditures  
Three months ended September 30, 2009
                                               
Terminalling and storage
  $ 16,440     $ (1,023 )   $ 15,417     $ 2,741     $ 1,538     $ 2,726  
Natural gas services
    103,061             103,061       1,130       1,922       1,819  
Marine transportation
    18,659       (874 )     17,785       3,301       2,090       447  
Sulfur services
    15,102       (2 )     15,100       1,569       2,169       1,264  
Indirect selling, general and administrative
                            (1,431 )      
 
                                   
 
                                               
Total
  $ 153,262     $ (1,899 )   $ 151,363     $ 8,741     $ 6,288     $ 6,256  
 
                                   
 
Three months ended September 30, 2008
                                               
Terminalling and storage
  $ 23,847     $ (1,053 )   $ 22,794     $ 2,342     $ 1,961     $ 7,167  
Natural gas services
    188,200             188,200       1,028       4,928       4,368  
Marine transportation
    21,129       (1,013 )     20,116       3,159       1,972       7,357  
Sulfur services
    133,660       (384 )     133,276       1,450       7,973       537  
Indirect selling, general and administrative
                            (1,414 )      
 
                                   
 
                                               
Total
  $ 366,836     $ (2,450 )   $ 364,386     $ 7,979     $ 15,420     $ 19,429  
 
                                   
                                                 
                    Operating             Operating        
                    Revenues     Depreciation     Income (loss)        
    Operating     Intersegment     after     and     after     Capital  
    Revenues     Eliminations     Eliminations     Amortization     eliminations     Expenditures  
Nine months ended September 30, 2009
                                               
Terminalling and storage
  $ 60,703       (3,166 )   $ 57,537     $ 7,837     $ 11,053     $ 15,446  
Natural gas services
    268,756       (7 )     268,749       3,364       5,284       4,047  
Marine transportation
    51,929       (2,707 )     49,222       9,868       1,152       4,546  
Sulfur services
    61,031       (2 )     61,029       4,588       11,360       7,645  
Indirect selling, general and administrative
                            (4,287 )      
 
                                   
Total
  $ 442,419     $ (5,882 )   $ 436,537     $ 25,657     $ 24,562     $ 31,684  
 
                                   

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
                                                 
                    Operating             Operating        
                    Revenues     Depreciation     Income (loss)        
    Operating     Intersegment     after     and     after     Capital  
    Revenues     Eliminations     Eliminations     Amortization     eliminations     Expenditures  
Nine months ended September 30, 2008
                                               
Terminalling and storage
  $ 66,004     $ (3,132 )   $ 62,872     $ 6,784     $ 5,293     $ 16,993  
Natural gas services
    577,317             577,317       2,966       2,303       8,127  
Marine transportation
    58,418       (2,590 )     55,828       8,901       4,757       43,901  
Sulfur services
    290,346       (818 )     289,528       4,282       20,427       3,164  
Indirect selling, general and administrative
                            (4,056 )      
 
                                   
 
                                               
Total
  $ 992,085     $ (6,540 )   $ 985,545     $ 22,933     $ 28,724     $ 72,185  
 
                                   
          The following table reconciles operating income to net income:
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2009     2008     2009     2008  
Operating income
  $ 6,288     $ 15,420     $ 24,562     $ 28,724  
Equity in earnings of unconsolidated entities
    2,139       3,503       5,227       11,385  
Interest expense
    (4,058 )     (4,971 )     (12,910 )     (13,609 )
Other, net
    68       87       139       334  
Income tax benefit (expense)
    80       (292 )     294       (753 )
 
                       
Net income
  $ 4,517     $ 13,747     $ 17,312     $ 26,081  
 
                       
          Total assets by segment are as follows:
                 
    September 30,     December 31,  
    2009     2008  
Total assets:
               
Terminalling and storage
  $ 142,946     $ 157,598  
Natural gas services
    253,412       232,161  
Marine transportation
    138,614       150,733  
Sulfur services
    108,674       128,424  
 
           
Total assets
  $ 643,646     $ 668,916  
 
           

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
(10) Long-term Debt and Capital Leases
          At September 30, 2009 and December 31, 2008, long-term debt consisted of the following:
                 
    September 30,     December 31,  
    2009     2008  
**   $195,000 Revolving loan facility at variable interest rate (4.77%* weighted average at September 30, 2009), due November 2010 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees
  $ 170,000     $ 165,000  
***   $130,000 Term loan facility at variable interest rate (6.08%* at September 30, 2009), due November 2010, secured by substantially all of the Partnership assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in Partnership’s operating subsidiaries
    130,000       130,000  
Capital lease obligations
    6,311        
 
           
Total long-term debt and capital lease obligations
    306,311       295,000  
Less current installments
    107        
 
           
Long-term debt and capital lease obligations, net of current installments
  $ 306,204     $ 295,000  
 
           
 
*   Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 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 LIBOR borrowings is 2.00%. Effective October 1, 2009, the applicable margin for existing LIBOR borrowings will remain at 2.00%. As a result of the Partnership’s leverage ratio test as of September 30, 2009, effective January 1, 2010, the applicable margin for existing LIBOR borrowings will increase to 2.50% under the current credit facility.
 
**   Effective October 2008, the Partnership entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 2.820% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 2.580% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges mature in October 2010.
 
**   Effective January 2008, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 3.400% plus the Partnership’s applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 3.050% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges mature in January 2010.
 
**   Effective September 2007, the Partnership 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 Partnership’s applicable LIBOR borrowing spread. Effective March 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 4.305% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges mature in September 2010.
 
**   Effective November 2006, the Partnership 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 Partnership’s applicable LIBOR borrowing spread. Effective March 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 4.37% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges mature in December 2009.
 
***   The $130,000 term loan has $105,000 hedged. Effective March 2006, the Partnership 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 Partnership’s applicable LIBOR borrowing spread. Effective February 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 5.10% plus the Partnership’s applicable LIBOR borrowing spread. These cash flow hedges mature in November 2010. Effective November 2006, the Partnership 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 Partnership’s applicable LIBOR borrowing spread. This cash flow hedge matures in March 2010.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
          On November 10, 2005, the Partnership 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, 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 Partnership increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. Effective December 28, 2007, the Partnership increased its revolving credit facility $75,000 resulting in a committed $195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of September 30, 2009, the Partnership had $170,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of September 30, 2009, irrevocable letters of credit issued under the Partnership’s credit facility totaled $2,120. As of September 30, 2009, the Partnership had $22,880 available under its revolving credit facility.
          The Partnership’s obligations under the credit facility are secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time without penalty.
          In addition, the credit facility contains various covenants, which, among other things, limit the Partnership’s ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell all or substantially all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) incur indebtedness or grant certain liens through its joint ventures.
          The credit facility also contains covenants, which, among other things, require the Partnership 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) trailing four quarters of Earnings Before Interest, Taxes, Depreciation and Amortization as defined in the credit facility, (“EBITDA”) 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 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. The Partnership was in compliance with the covenants contained in the credit facility as of September 30, 2009 and for the year ended December 31, 2008.
          The Partnership is a party to certain pending cash and asset contributions from Martin Resource Management, the owner of its General Partner. In exchange for these contributions the Partnership will issue common and subordinated units to Martin Resource Management (See Note 16 for a discussion of these transactions). Unless the Partnership is able to consummate these pending transactions prior to December 31, 2009, it is possible that it will be out of compliance with the debt to EBITDA leverage ratio covenant contained in the credit facility on such date, thereby resulting in a default thereunder and the need to seek a waiver of such default from the Partnership’s lenders and negatively impacting its ability to extend, amend or replace the credit facility. Should the Partnership fail to obtain a waiver of such default, the lenders would be entitled to demand immediate payment of all outstanding amounts under the credit facility. The leverage ratio is calculated by dividing the Partnership’s total secured funded debt at the end of the December 31, 2009 quarter by its EBITDA for the year then ended. However, the Partnership believes that such pending transactions will be consummated prior to the end of November 2009 and that, and as a result, the Partnership will be in compliance with such leverage ratio on December 31, 2009.
          The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls the Partnership’s general partner, the lenders under the Partnership’s credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under the Partnership’s credit facility if it is deemed to have a

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
material adverse effect on the Partnership. Any event of default and corresponding acceleration of outstanding balances under the Partnership’s credit facility could require the Partnership to refinance such indebtedness on unfavorable terms and would have a material adverse effect on the Partnership’s financial condition and results of operations as well as its ability to make distributions to unitholders.
          On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay the term loan 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 or required under the term loan through September 30, 2009. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loan under the credit facility. The Partnership must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by 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 Partnership’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Partnership’s credit facility have ranged from a low of $285,000 to a high of $315,000. As of September 30, 2009, the Partnership had $22,880 available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility.
          In connection with the Partnership’s Stanolind asset acquisition on January 22, 2008, the Partnership borrowed approximately $6,000 under its revolving credit facility.
          The Partnership paid cash interest in the amount of $4,179 and $5,335 for the three months ended September 30, 2009 and 2008, respectively, and $13,622 and $13,262 for the nine months ended September 30, 2009 and 2008, respectively. Capitalized interest was $9 and $287 for the three months ended September 30, 2009 and 2008, respectively and $247 and $1,100 for the nine months ended September 30, 2009 and 2008, respectively.
(11) Income Taxes
          The operations of a partnership are generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. Effective January 1, 2007, the Partnership is subject to the Texas margin tax as described below. Woodlawn, a subsidiary of the Partnership, is subject to income taxes due to its corporate structure. A current federal income tax benefit of $477 and $799 and a current federal income tax expense of $174 and $421, related to the operation of the subsidiary, were recorded for the three and nine months ended September 30, 2009 and 2008, respectively In connection with the Woodlawn acquisition, the Partnership also established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment.
          A deferred tax expense related to these basis differences of $284 and $70 was recorded for the three and nine months ended September 30, 2009, respectively. A deferred tax benefit (related to these basis differences) of $67 and $222 was recorded for the three and nine months ended September 30, 2008, respectively. A deferred tax liability of $8,608 and $8,538 related to the basis differences existed at September 30, 2009 and at December 31, 2008, respectively.
          In 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

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the new margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $113 and $435 were recorded in current income tax expense for the three and nine months ended September 30, 2009 and $185 and $554 for the three and nine months ended September 30, 2008, respectively.
          An income tax receivable of $724 (which is included in other current assets) and an income tax liability of $414 existed at September 30, 2009 and December 31, 2008, respectively.
          The components of income tax expense (benefit) from operations recorded for the three and nine months ended September 30, 2009 and 2008 are as follows:
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2009     2008     2009     2008  
Current:
                               
Federal
  $ (477 )   $ 174     $ (799 )   $ 421  
State
    113       185       435       554  
 
                       
 
    (364 )     359       (364 )     975  
 
                               
Deferred:
                               
Federal
    284       (67 )     70       (222 )
 
                       
 
  $ (80 )   $ 292     $ (294 )   $ 753  
 
                       
(12) Hurricane Damage
          During the third quarter of 2008, several of the Partnership’s facilities in the Gulf of Mexico were in the path of two major hurricanes, Hurricane Gustav and Hurricane Ike. Physical damage to the Partnership’s assets caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a deductible. Losses incurred as a result of a single hurricane (an “occurrence”) are limited to a maximum aggregate deductible of $250 for flood damage and $1,000 minimum plus 2% of total insured value at each location for wind damage. The partnership’s total flood coverage is $15,000 and total wind coverage is $100,000.
          The most significant damage to the Partnership’s assets was sustained at the Neches location. Property damage also occurred at the Partnership’s Galveston, Sabine Pass, Intracoastal City, Cameron East, Cameron West, Freeport, Venice, Port Fourchon, Stanolind, Mont Belvieu, and Spindletop locations. Based on an analysis of the damage as performed by the Partnership, the Partnership has estimated its non-cash charge as $1,269 for all locations which is equal to the net-book value of the damaged assets. A receivable of $2,540 has been recorded for the expected insurance recovery equal to the impairment charge and for all expenditures related to water damage less the aforementioned deductible. This receivable was also reduced by the advanced insurance proceeds received of $5,027. Insurance proceeds received as a result of the aforementioned claims could exceed net book value of the Partnership’s assets determined to be impaired, which will result in the recognition of a gain equal to the amount of the excess. No net gain or loss has been recognized from the impairment of these damaged assets at September 30, 2009. This potential gain would not be recognized until proceeds are received.
(13) Gain on Disposal of Assets
          On April 30, 2009, the Partnership sold certain assets comprising the Mont Belvieu railcar unloading facility, which yielded net proceeds from the sale in the amount of $19,610. The assets sold related to twenty railcar spaces and Phase I of a newly constructed major expansion that had not been placed in operation. This disposition was separated into two phases because of the contractual requirement to complete the two phases of construction in progress prior to final closing of the transaction. The disposition related to Phase I, which was completed in April 2009, was comprised of property, plant and equipment and allocated goodwill included in the Partnership’s terminalling segment with an aggregate carrying value of

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
$14,329. This transaction yielded a gain on the sale of property, plant, and equipment in the amount of $5,281, a portion which was deferred in the amount of $200 for expected future warranty costs associated with the sale. The gain is included in “other operating income” in the consolidated statement of operations. As of September 30, 2009, the remaining portion of the property, plant and equipment in Phase II is under construction and the Partnership is expected to make additional expenditures which will increase the carrying value of the disposed assets by approximately $600. The Partnership received $2,500 during the third quarter for funds previously held in escrow relating to the completion of Phase II. The Partnership will receive an additional $250 upon final completion of Phase II, which is expected to occur during the fourth quarter. The current balance related to Phase II construction is $1,493 and was offset against the escrow monies received resulting in a current liability of $1,007. The balance is included in other current liabilities on the Company’s consolidated balance sheet at September 30, 2009. The Partnership expects to recognize a gain in the amount of approximately $650 during the fourth quarter of 2009. Additionally, the Partnership expects to receive payments of $375 in April 2010 and April 2012, respectively, which represent payments from an indemnity escrow resulting from the sale. The Partnership expects to record these amounts as gains in each respective quarter. The Partnership paid down the outstanding revolving loans under its credit facility with the net cash proceeds from this sale of assets. The amount paid down is available for future borrowings under the revolving credit facility.
(14) Commitments and Contingencies
          On November 4, 2009, the Partnership entered into a Contribution Agreement with MRMC and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of MRMC to acquire certain specialty lubricants processing assets (“Assets”) from Cross for total consideration of $45,000 (the “Contribution”). In consideration for the Cross Assets, the Partnership will issue 804,721 common units and 894,134 subordinated units to MRMC at a price of $27.96 and $25.16 per limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February 2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the Contribution. At the end of such second anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units. The pricing of the units is based on the average closing price of the Partnership’s common units during the ten trading days ending November 3, 2009, with a 10% discount applied to the average in the case of the subordinated units. In connection with the Contribution, the general partner of the Partnership, will make a capital contribution of $918 to the Partnership in order to maintain its 2% general partner interest in the Partnership.
          In connection with the closing of the Contribution, MRMC and the Partnership have agreed to enter into a long-term, fee for services-based Tolling Agreement whereby MRMC agrees to pay the Partnership for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, MRMC has generally agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a price of $4.00 per barrel. Any additional barrels will refined at a price of $4.28 per barrel. In addition, MRMC has agreed to pay a monthly reservation fee of $1,300 and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. The Tolling Agreement will have a 12 year term, subject to certain termination rights specified therein. MRMC will continue to market and distribute all finished products under the Cross brand name. In addition, MRMC will continue to own and operate the Cross packaging business. The closing of the Contribution is subject to standard closing conditions, including the approval of the lenders under MRMC’s credit facility and the approval of the assignment of various regulatory licenses and permits. Closing is anticipated prior to the end of November 2009.
          In addition, on November 4, 2009, the Partnership entered into a separate Unit Purchase Agreement with MRMC, under which MRMC will invest $20,000 in cash in the Partnership in exchange for

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
715,308 newly-issued common units (the “Investment”). In connection with the Investment, the general partner of the Partnership will make a capital contribution to the Partnership of $408 in order to maintain its 2% general partner interest in the Partnership. The closing of the Investment is subject to standard closing conditions, including the approval of the lenders under MRMC’s credit facility. Closing is anticipated prior to the end of November 2009. Proceeds from the Investment will be used by the Partnership to repay a portion of indebtedness under its credit facility.
          The Partnership is committed to purchase certain assets during 2010 for an aggregate notional amount of $23,280.
          As a result of a routine inspection by the U.S. Coast Guard of the Partnership’s tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, the Partnership has been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two employees of Martin Resource Management who provide services to the Partnership were served with grand jury subpoenas during the fourth quarter of 2007. In addition, in April 2009, an additional grand jury subpoena was issued pertaining to the provision of certain documents relating to the Martin Explorer and its crew. The Partnership is cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against the Partnership.
          In addition to the foregoing, from time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.
          On May 2, 2008, the Partnership received a copy of a petition filed in the District Court of Gregg County, Texas (the “Court”) by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management. The Plaintiff and the Defendant are executive officers of Martin Resource Management and the general partner of the Partnership, the Defendant is a director of both Martin Resource Management and the general partner of the Partnership, and the Plaintiff is a director of Martin Resource Management. The lawsuit alleged that the Defendant breached a settlement agreement with the Plaintiff concerning certain Martin Resource Management matters and that the Defendant breached fiduciary duties allegedly owed to the Plaintiff in connection with their respective ownership and other positions with Martin Resource Management. Prior to the trial of this lawsuit, the Plaintiff dropped his claims against the Defendant relating to the breach of fiduciary duty allegations. The Partnership is not a party to the lawsuit and the lawsuit does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations or (iii) against the Defendant with respect to his service as an officer or director of the general partner of the Partnership.
          In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment (the “Judgment”) with respect to the lawsuit as further described below. In connection with the Judgment, the Defendant has advised the Partnership that he has filed a motion for new trial, a motion for judgment notwithstanding the verdict and a notice of appeal. In addition, on June 22, 2009, the Plaintiff filed a notice of appeal with the Court indicating his intent to appeal the Judgment. The Defendant has further advised the Partnership that on June 30, 2009 he posted a cash deposit in lieu of a bond and the judge has ruled that as a result of such deposit, the enforcement of any of the provisions in the Judgment is stayed until the matter is resolved on appeal. Accordingly, during the pendancy of the of the appeal process, no change in the makeup of the Martin Resource Management Board of Directors is expected.
          The Judgment awarded the Plaintiff monetary damages in the approximate amount of $3.2 million, attorney’s fees of approximately $1.6 million and interest. In addition, the Judgment grants specific performance and provides that the Defendant is to (i) transfer one share of his Martin Resource Management common stock to the Plaintiff, (ii) take such actions, including the voting of any Martin Resource Management shares which the Defendant owns, controls or otherwise has the power to vote, as are necessary to change the composition of the Board of Directors of Martin Resource Management from a five-person board, currently consisting of the Defendant and the Plaintiff as well as Wes Skelton, Don Neumeyer, and

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
Bob Bondurant (executive officers of Martin Resource Management and the Partnership), to a four-person board to consist of the Defendant and his designee and the Plaintiff and his designee, and (iii) take such actions as are necessary to change the trustees of the Martin Resource Management Employee Stock Ownership Trust (the “MRMC ESOP Trust”), currently consisting of the Defendant, the Plaintiff and Wes Skelton, to just the Defendant and the Plaintiff. The Judgment is directed solely at the Defendant and is not binding on any other officer, director or shareholder of Martin Resource Management or any trustee of a trust owning Martin Resource Management shares. The Judgment with respect to (ii) above will terminate on February 17, 2010, and with respect to (iii) above on the 30th day after the election by the Martin Resource Management shareholders of the first successor Martin Resource Management board after February 17, 2010. However, any enforcement of the Judgment is stayed pending resolution of the appeal relating to it.
          On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of the general partner of the Partnership. The Partnership is not a party to this lawsuit, and it does not assert any claims (i) against the Partnership, (ii) concerning the Partnership’s governance or operations or (iii) against the MRMC Director Defendants or Other MRMC Defendants with respect to their service to the Partnership.
          The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares. The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The Court abated this lawsuit on July 13, 2009 until a mandamus pending before the Texas Supreme Court dealing with matters at issue in the lawsuit is resolved.
          The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, and who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached the fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, it should be noted that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above, Angela Jones Alexander has amended her claims to include her grandmother, Margaret Martin, as a party. The lawsuit referenced in (i) above is currently set for trial on November 30, 2009.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
          On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which the Board of Directors of Martin Resource Management determined were detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of the general partner of the Partnership. The position on the board of directors of the general partner of the Partnership vacated by the Plaintiff may be filled in accordance with the existing procedures for replacement of a departing director utilizing the Nominations Committee of the board of directors of the general partner of the Partnership. This position on the board of directors has not been filled as of November 4, 2009.
(15) Consolidating Financial Statements
          In connection with the Partnership’s filing of a shelf registration statement on Form S-3 with the Securities and Exchange Commission (the “Registration Statement”), Martin Operating Partnership L.P. (the “Operating Partnership”), the Partnership’s wholly-owned subsidiary, may issue unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time under the registration statement. If issued, the guarantees will be full, irrevocable and unconditional. In addition, the Operating Partnership may also issue senior or subordinated debt securities under the Registration Statement which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. The Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has no independent assets or operations, the guarantees are full and unconditional and the other subsidiary of the Partnership is minor. There are no significant restrictions on the ability of the Partnership or the Operating Partnership to obtain funds from any of their respective subsidiaries by dividend or loan.
(16) Subsequent Events
          On November 4, 2009, the Partnership entered into a Contribution Agreement with MRMC and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of MRMC, to acquire certain specialty lubricants processing assets (“Assets”) from Cross for total consideration of $45,000 (the “Contribution”). In consideration for the Cross Assets, the Partnership will issue 804,721 common units and 894,134 subordinated units to MRMC at a price of $27.96 and $25.16 per limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February 2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the Contribution. At the end of such second anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units. The pricing of the units is based on the average closing price of the Partnership’s common units during the ten trading days ending November 3, 2009, with a 10% discount applied to the average in the case of the subordinated units. In connection with the Contribution, the general partner of the Partnership, will make a capital contribution of $918 to the Partnership in order to maintain its 2% general partner interest in the Partnership.
          In connection with the closing of the Contribution, MRMC and the Partnership have agreed to enter into a long-term, fee for services-based Tolling Agreement whereby MRMC agrees to pay the Partnership for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, MRMC has generally agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a price of $4.00 per barrel. Any additional barrels will refined at a price of $4.28 per barrel. In addition, MRMC has agreed to pay a monthly reservation fee of $1,300 and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. The Tolling Agreement will have a 12 year term, subject to certain termination rights specified therein. MRMC will continue to market and distribute all finished products under the Cross

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2009
(Unaudited)
brand name. In addition, MRMC will continue to own and operate the Cross packaging business. The closing of the Contribution is subject to standard closing conditions, including the approval of the lenders under MRMC’s credit facility and the approval of the assignment of various regulatory licenses and permits. Closing is anticipated prior to the end of November 2009.
          In addition, on November 4, 2009, the Partnership entered into a separate Unit Purchase Agreement with MRMC, under which MRMC will invest $20,000 in cash in the Partnership in exchange for 715,308 newly-issued common units (the “Investment”). In connection with the Investment, the general partner of the Partnership will make a capital contribution to the Partnership of $408 in order to maintain its 2% general partner interest in the Partnership. The closing of the Investment is subject to standard closing conditions, including the approval of the lenders under MRMC’s credit facility. Closing is anticipated prior to the end of November 2009. Proceeds from the Investment will be used by the Partnership to repay a portion of indebtedness under its credit facility.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
          References in this quarterly report to “Martin Resource Management” refers to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires. You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated and condensed financial statements and the notes thereto included elsewhere in this quarterly report.
Forward-Looking Statements
          This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this quarterly report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.
          These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.
          Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission (the “SEC”) on March 4, 2009 and in this report.
Overview
          We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Our four primary business lines include:
    Terminalling and storage services for petroleum and by-products;
 
    Natural gas services;
 
    Marine transportation services for petroleum products and by-products; and
 
    Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution.
          The petroleum products and by-products we collect, transport, store and market are produced primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the Gulf Coast region of the United States. This region is a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry.
          We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of hydrocarbon products and by-products and other bulk liquids. Martin Resource Management owns an approximate 34.9% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest in us and all of our incentive distribution rights.
          Martin Resource Management has operated our business for several years. Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the

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1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.
Recent Developments
          Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. Numerous events have severely restricted current liquidity in the capital markets throughout the United States and around the world. The ability to raise money in the debt and equity markets has diminished significantly and, if available, the cost of funds has increased substantially. One of the features driving investments in master limited partnerships, including us, over the past few years has been the distribution growth offered by master limited partnerships due to liquidity in the financial markets for capital investments to grow distributable cash flow through development projects and acquisitions. Growth opportunities have been and are expected to continue to be constrained by the lack of liquidity in the financial markets.
          Conditions in our industry have continued to be challenging in 2009. For example:
    Market prices of oil, natural gas, NGLs, and sulfur remain below the market prices realized throughout most of 2008.
 
    The decline in drilling activity by gas producers in our areas of operations that began during the fourth quarter of 2008 as a result of the global economic crisis has continued. Several gas producers in our areas of operation have substantially reduced drilling activity during 2009 as compared to their drilling levels during 2008.
 
    The decline in the demand for marine transportation services based on decreased refinery production resulting in an oversupply of equipment.
          Despite the weaker commodity price environment and reduced drilling activity, we are positioning ourselves to benefit from a recovering economy. In particular:
    We adjusted our business strategy for 2009 to focus on maximizing our liquidity, maintaining a stable asset base, and improving the profitability of our assets by increasing their utilization while controlling costs. We have also reduced our capital expenditures.
 
    We continue to evaluate opportunities to enter into commodity hedging transactions to further reduce our commodity price risk.
 
    We completed the disposition of certain non-strategic assets including the April 2009 sale of the Mont Belvieu Railcar Unloading Facility for $19.6 million, and we may consider marketing certain other non-strategic assets in the future.
 
    Our near-term focus is to ensure we that we have extended the maturity date of our existing credit facility (either through an amendment, extension or entering into a new credit facility) and that we have sufficient liquidity to fund our growth programs, while continuing the present distribution rate to our unitholders. The current economic crisis and the existing litigation at Martin Resource Management has created a challenging operating environment for us to maintain our liquidity and operating cash flows at levels consistent with the recent past while maintaining the present distribution rate to our unitholders.
 
    We entered into an agreement to acquire certain assets of a subsidiary of Martin Resource Management in exchange the issuance of new common and subordinated units to maintain appropriate financial ratios satisfactory to our lenders (See “Subsequent Events — Cross Transaction and Equity Transaction”).
Subsequent Events — Cross Transaction and Equity Transaction
          On November 4, 2009, we entered into a Contribution Agreement with Martin Resource Management and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of Martin Resource Management, the owner of our general partner, to acquire certain specialty lubricants processing assets

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(“Assets”) from Cross for total consideration of $45.0 million (the “Contribution”). In consideration for the Cross Assets, we will issue 804,721 common units and 894,134 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February 2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the Contribution. At the end of such second anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units. The pricing of the units is based on the average closing price of our common units during the ten trading days ending November 3, 2009, with a 10% discount applied to the average in the case of the subordinated units. In connection with the Contribution, our general partner, will make a capital contribution of $0.9 million to us in order to maintain its 2% general partner interest in us.
          In connection with the closing of the Contribution, Martin Resource Management and we have agreed to enter into a long-term, fee for services-based Tolling Agreement whereby Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, Martin Resource Management has generally agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a price of $4.00 per barrel. Any additional barrels will refined at a price of $4.28 per barrel. In addition, Martin Resource Management has agreed to pay a monthly reservation fee of $1.3 million and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. The Tolling Agreement will have a 12 year term, subject to certain termination rights specified therein. Martin Resource Management will continue to market and distribute all finished products under the Cross brand name. In addition, Martin Resource Management will continue to own and operate the Cross packaging business. The closing of the Contribution is subject to standard closing conditions, including the approval of the lenders under Martin Resource Management’s credit facility and the approval of the assignment of various regulatory licenses and permits. Closing is anticipated prior to the end of November 2009.
          In addition, on November 4, 2009, we entered into a separate Unit Purchase Agreement with Martin Resource Management, under which Martin Resource Management will invest $20.0 million in cash in us in exchange for 715,308 newly-issued common units (the “Investment”). In connection with the Investment, our general partner will make a capital contribution to us of $0.4 million in order to maintain its 2% general partner interest in us. The closing of the Investment is subject to standard closing conditions, including the approval of the lenders under Martin Resource Management’s credit facility. Closing is anticipated prior to the end of November 2009. Proceeds from the Investment will be used by us to repay a portion of indebtedness under its credit facility.
          The foregoing descriptions of the Contribution Agreement, Tolling Agreement and Unit Purchase Agreement do not purport to be complete and are qualified in their entirety by reference to the full text of such Contribution Agreement, form of Tolling Agreement and Unit Purchase Agreement, copies of which are filed herewith as Exhibits 10.1, 10.2 and 10.3, respectively.
Critical Accounting Policies
          Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated and condensed financial statements included elsewhere herein. We prepared these financial statements in conformity with generally accepted accounting principles. The preparation of these financial statements required us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Our results may differ from these estimates. Currently, we believe that our accounting policies do not require us to make estimates using assumptions about matters that are highly uncertain. However, we have described below the critical accounting policies that we believe could impact our consolidated and condensed financial statements most significantly.
          You should also read Note 1, “General” in Notes to Consolidated and Condensed Financial Statements contained in this quarterly report and the “Significant Accounting Policies” note in the consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 4, 2009 in conjunction with this Management’s Discussion and Analysis of Financial Condition and Results of Operations. Some of the more significant estimates in these financial statements include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units under ASC 350 related to intangibles-goodwill and other.
          Derivatives
          All derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge

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accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. Our hedging policy allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges or hedges that become ineffective are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of September 30, 2009, we have designated a portion of our derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of partners’ capital.
          Product Exchanges
          We enter into product exchange agreements with third parties whereby we agree to exchange natural gas liquids (“NGLs”) and sulfur with third parties. We record the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out method.
          Revenue Recognition
          Revenue for our four operating segments is recognized as follows:
          Terminalling and storage — Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through our terminals at the contracted rate. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.
          Natural gas services — Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, we recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.
          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 services — Revenue is recognized when the customer takes title to the product at our plant or the customer facility.
          Equity Method Investments
          We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. This goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment evaluation. No portion of the net income from these entities is included in our operating income.
          We own an unconsolidated 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”) and a 20% ownership interest in a partnership which owns the lease rights to Bosque County Pipeline (“BCP”). Each of these interests is accounted for under the equity method of accounting. The lease contract with respect to BCP terminated in June 2009, and the investment was fully amortized as of June 30, 2009.
          Goodwill
          Goodwill is subject to a fair-value based impairment test on an annual basis. We are required to identify our reporting units and determine the carrying value of each reporting unit by assigning the assets and

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liabilities, including the existing goodwill and intangible assets. We are required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, we would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.
          All four of our “reporting units”, terminalling and storage, marine transportation, natural gas services and sulfur services, contain goodwill.
          We have performed the annual impairment tests as of September 30, 2009, and we have determined fair value in each reporting unit based on the weighted average of three valuation techniques: (i) the discounted cash flow method, (ii) the guideline public company method, and (iii) the guideline transaction method.
          Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.
          Environmental Liabilities and Litigation
          We have not historically experienced circumstances requiring us to account for environmental remediation obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other related environmental studies that we may elect to perform. We would record changes to our estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related eventual liability.
          Because the outcomes of both contingent liabilities and litigation are difficult to predict, when accounting for these situations, significant management judgment is required. Amounts paid for contingent liabilities and litigation have not had a materially adverse effect on our operations or financial condition and we do not anticipate they will in the future.
          Allowance for Doubtful Accounts
          In evaluating the collectability of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and historical collection experience. Based on these assessments, we record specific and general reserves for bad debts to reduce the related receivables to the amount we ultimately expect to collect from customers.
          The Company’s management closely monitors potentially uncollectible accounts. Estimates of uncollectible amounts are revised each period, and changes are recorded in the period they become known. If there is a deterioration of a major customer’s creditworthiness or actual defaults are higher than the historical experience, management’s estimates of the recoverability of amounts due the Company could potentially be adversely affected. These charges have not had a materially adverse effect on our operations or financial condition.
          Asset Retirement Obligation
          We recognize and measure our asset and conditional asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset and based upon the estimate of the cost to settle the obligation at its anticipated future date. The obligation is accreted to its estimated future value and the asset retirement cost is depreciated over the estimated life of the asset.
          Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Such costs could differ significantly when they are incurred. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates due to surface repair, and labor and material costs, revisions to estimated inflation rates and changes in the estimated timing of abandonment. For example, the Company does not have access to natural gas reserves information related to our gathering systems to estimate when abandonment will occur.

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Our Relationship with Martin Resource Management
     Martin Resource Management is engaged in the following principal business activities:
    providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;
 
    distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids;
 
    providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Mississippi and Texas;
 
    operating a small crude oil gathering business in Stephens, Arkansas;
 
    operating a lube oil processing facility in Smackover, Arkansas, of which, as disclosed in this report, the refinery assets and operations are being contributed to us (see “Subsequent Events — Cross Transaction and Equity Transaction” above);
 
    operating an underground NGL storage facility in Arcadia, Louisiana;
 
    supplying employees and services for the operation of our business;
 
    operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal; and
 
    operating, solely for our account, the asphalt facilities in Omaha, Nebraska.
          We are and will continue to be closely affiliated with Martin Resource Management as a result of the following relationships.
          Ownership
          Martin Resource Management owns an approximate 34.9% limited partnership interest and a 2% general partnership interest in us and all of our incentive distribution rights.
          Management
          Martin Resource Management directs our business operations through its ownership and control of our general partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of management expertise and established relationships throughout the energy industry. We do not have employees. Martin Resource Management employees are responsible for conducting our business and operating our assets on our behalf.
          Related Party Agreements
          We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $15.2 million of direct costs and expenses for the three months ended September 30, 2009 compared to $16.8 million for the three months ended September 30, 2008. We reimbursed Martin Resource Management for $45.3 million of direct costs and expenses for the nine months ended September 30, 2009 compared to $50.6 million for the nine months ended September 30, 2008. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.
          In addition to the direct expenses, under the omnibus agreement, the reimbursement amount that we are required to pay to Martin Resource Management with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million. This cap expired on November 1, 2007. Effective October 1, 2008 through September 30, 2009, the conflicts committee of our general partner approved an annual reimbursement amount for indirect expenses of $3.5 million. We reimbursed Martin Resource

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Management for $0.9 and $0.7 million of indirect expenses for the three months ended September 30, 2009 and 2008, respectively. We reimbursed Martin Resource Management for $2.6 and $2.0 million of indirect expenses for the nine months ended September 30, 2009 and 2008, respectively. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The omnibus agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the omnibus agreement.
          In addition to the omnibus agreement, we and Martin Resource Management have entered into various other agreements. The agreements include, but are not limited to, a motor carrier agreement, a terminal services agreement, a marine transportation agreement, a product storage agreement, a product supply agreement, and a Purchaser Use Easement, Ingress-Egress Easement and Utility Facilities Easement. Pursuant to the terms of the omnibus agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the conflicts committee of our general partner’s board of directors.
          For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions — Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 4, 2009.
          Commercial
          We have been and anticipate that we will continue to be both a significant customer and supplier of products and services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is currently a key component of our integrated distribution network.
          We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.0 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.
          In the aggregate, our purchases of land transportation services, NGL storage services, sulfuric acid and lube oil product purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 18% and 9% of our total cost of products sold during the three months ended September 30, 2009 and 2008, respectively; and approximately 16% and 9% of our total cost of products sold during the nine months ended September 30, 2009 and 2008, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.
          Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for approximately 7% and 6% of our total revenues for the three months ended September 30, 2009 and 2008, respectively. Our sales to Martin Resource Management accounted for approximately 7% and 5% of our total revenues for the nine months ended September 30, 2009 and 2008, respectively. We provide terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel provides terminal services to us to handle lubricants, greases and drilling fluids.
          In April 2009, we sold our traditional lubricant business to Martin Resource Management in return for a service fee for lubricant volume moved through our terminals.
          For a more comprehensive discussion concerning the agreements that we have entered into with Martin Resource Management, please refer to “Item 13. Certain Relationships and Related Transactions —

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Agreements” set forth in our annual report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 4, 2009.
          Approval and Review of Related Party Transactions
          If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the approval process, it determines whether to refer the matter to the conflicts committee of our general partner’s board of directors, as constituted under our limited partnership agreement. If a matter is referred to the conflicts committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the conflicts committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.
Results of Operations
          The results of operations for the three and nine months ended September 30, 2009 and 2008 have been derived from the consolidated and condensed financial statements of the Partnership.
          We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating revenues and operating income by segment for the three and nine months ended September 30, 2009 and 2008. The results of operations for the first nine months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.
                                                 
                    Operating             Operating     Operating  
            Revenues     Revenues             Income     Income (loss)  
    Operating     Intersegment     after     Operating     Intersegment     after  
    Revenues     Eliminations     Eliminations     Income (loss)     Eliminations     Eliminations  
    (In thousands)  
Three months ended September 30, 2009
                                               
Terminalling and storage
  $ 16,440     $ (1,023 )   $ 15,417     $ 2,295     $ (757 )   $ 1,538  
Natural gas services
    103,061             103,061       1,669       253       1,922  
Marine transportation
    18,659       (874 )     17,785       2,963       (873 )     2,090  
Sulfur Services
    15,102       (2 )     15,100       792       1,377       2,169  
Indirect selling, general and administrative
                      (1,431 )           (1,431 )
 
                                   
 
                                               
Total
  $ 153,262     $ (1,899 )   $ 151,363     $ 6,288     $     $ 6,288  
 
                                   
 
Three months ended September 30, 2008
                                               
Terminalling and storage
  $ 23,847     $ (1,053 )   $ 22,794     $ 2,911     $ (950 )   $ 1,961  
Natural gas services
    188,200             188,200       4,685       243       4,928  
Marine transportation
    21,129       (1,013 )     20,116       2,576       (604 )     1,972  
Sulfur Services
    133,660       (384 )     133,276       6,662       1,311       7,973  
Indirect selling, general and administrative
                      (1,414 )           (1,414 )
 
                                   
 
                                               
Total
  $ 366,836     $ (2,450 )   $ 364,386     $ 15,420     $     $ 15,420  
 
                                   
 
                    Operating             Operating     Operating  
            Revenues     Revenues             Income     Income (loss)  
    Operating     Intersegment     after     Operating     Intersegment     after  
    Revenues     Eliminations     Eliminations     Income (loss)     Eliminations     Eliminations  
    (In thousands)  
Nine months ended September, 2009
                                               
Terminalling and storage
  $ 60,703     $ (3,166 )   $ 57,537     $ 13,385     $ (2,332 )   $ 11,053  
Natural gas services
    268,756       (7 )     268,749       4,498       786       5,284  
Marine transportation
    51,929       (2,707 )     49,222       3,807       (2,655 )     1,152  
Sulfur Services
    61,031       (2 )     61,029       7,159       4,201       11,360  
Indirect selling, general and administrative
                      (4,287 )           (4,287 )
 
                                   
 
                                               
Total
  $ 442,419     $ (5,882 )   $ 436,537     $ 24,562     $     $ 24,562  
 
                                   

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                    Operating             Operating     Operating  
            Revenues     Revenues             Income     Income (loss)  
    Operating     Intersegment     after     Operating     Intersegment     after  
    Revenues     Eliminations     Eliminations     Income (loss)     Eliminations     Eliminations  
    (In thousands)  
Nine months ended September, 2008
                                               
Terminalling and storage
  $ 66,004     $ (3,132 )   $ 62,872     $ 8,045     $ (2,752 )   $ 5,293  
Natural gas services
    577,317             577,317       1,596       707       2,303  
Marine transportation
    58,418       (2,590 )     55,828       6,428       (1,671 )     4,757  
Sulfur Services
    290,346       (818 )     289,528       16,711       3,716       20,427  
Indirect selling, general and administrative
                      (4,056 )           (4,056 )
 
                                   
 
                                               
Total
  $ 992,085     $ (6,540 )   $ 985,545     $ 28,724     $     $ 28,724  
 
                                   
          Our results of operations are discussed on a comparative basis below. There are certain items of income and expense which we do not allocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment.
Three Months Ended September 30, 2009 Compared to the Three Months Ended September 30, 2008
          Our total revenues before eliminations were $153.3 million for the three months ended September 30, 2009 compared to $366.8 million for the three months ended September 30, 2008, a decrease of $213.5 million, or 58%. Our operating income before eliminations was $6.3 million for the three months ended September 30, 2009 compared to $15.4 million for the three months ended September 30, 2008, a decrease of $9.1 million, or 59%.
          The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
          The following table summarizes our results of operations in our terminalling and storage segment.
                 
    Three Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues:
               
Services
  $ 10,126     $ 10,546  
Products
    6,314       13,301  
 
           
Total revenues
    16,440       23,847  
 
               
Cost of products sold
    5,535       11,031  
Operating expenses
    5,857       7,541  
Selling, general and administrative expenses
    12       22  
Depreciation and amortization
    2,741       2,342  
 
           
 
    2,295       2,911  
 
           
Other operating income
           
 
           
Operating income
  $ 2,295     $ 2,911  
 
           
          Revenues. Our terminalling and storage revenues decreased $7.4 million, or 31%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. Service revenue accounted for $0.4 million of this decrease. The service revenue decrease was primarily a result of decreased activity at our terminals of $1.5 million and lost revenues due to the sale of our Mont Belvieu terminal of $0.2 million. This decrease was offset by an increase due to new agreements entered into in 2008 and 2009, including a new lubricant terminalling fee of $1.3 million. Product sales revenue decreased $7.0 million. Of this decrease, $4.6 million was due to the sale of our traditional lubricants business, including inventory, to Martin Resource Management in April 2009 in return for a service fee for lubricant volumes moved through our terminals. The remaining $2.4 million decrease is due to a 4% decrease in sales volumes and a 26% decrease in average selling price at our Mega Lubricant facility.

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          Cost of products sold. Our cost of products sold decreased $5.5 million, or 50%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. $3.5 million of this decrease was due to the sale of our traditional lubricants business including inventory to Martin Resource Management in April 2009 in return for a service fee for lubricant volumes moved through our terminals. The remaining $2.0 million decrease is due to a 4% decrease in sales volumes and a 26% decrease in average selling price at our Mega Lubricant facility.
          Operating expenses. Operating expenses decreased $1.7 million, or 22%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. This decrease was primarily the result of $1.6 million of hurricane expenses that were recorded in 2008.
          Selling, general and administrative expenses. Selling, general and administrative expenses were relatively flat for both three month periods.
          Depreciation and amortization. Depreciation and amortization expenses increased $0.4 million, or 17%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. This increase was primarily a result of our recent capital expenditures.
          In summary, our terminalling operating income decreased $0.6 million, or 21%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008.
     Natural Gas Services Segment
          The following table summarizes our results of operations in our natural gas services segment.
                 
    Three Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues:
               
NGLs
  $ 96,806     $ 166,564  
Natural gas
    4,410       16,470  
Non-cash mark to market adjustment of commodity derivatives
    179       6,629  
Gain (loss) on cash settlements of commodity derivatives
    709       (1,820 )
Other operating fees
    957       357  
 
           
Total revenues
    103,061       188,200  
 
               
Cost of products sold (excluding depreciation and amortization):
               
NGLs
    92,375       162,718  
Natural gas
    4,236       16,519  
 
           
Total cost of products sold
    96,611       179,237  
 
               
Operating expenses
    2,005       2,070  
Selling, general and administrative expenses
    1,646       1,181  
Depreciation and amortization
    1,130       1,027  
 
           
Operating income
  $ 1,669     $ 4,685  
 
           
 
               
NGLs Volumes (Bbls)
    2,048       1,929  
 
           
Natural Gas Volumes (MMbtu)
    1,639       1,818  
 
           
 
               
Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments
               
 
               
Equity in Earnings of Unconsolidated Entities
  $ 2,139     $ 3,503  
 
           
 
Waskom:
               
Plant Inlet Volumes (MMcf/d)
    255       239  
 
           
Fractionated Volumes (Bbls/d)
    11,391       9,965  
 
           

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          Revenues. Our natural gas services revenues decreased $85.1 million, or 45%, for the three months ended September 30, 2009 compared to this same period of 2008. The decrease was primarily due to lower commodity prices.
          For the three months ended September 30, 2009, NGL revenues decreased $69.8 million, or 42%, and natural gas revenues decreased $12.1 million, or 73%. NGL and natural gas sales volumes remained relatively consistent for the third quarter of 2009 compared to the same period of 2008. During the third quarter of 2009, our NGL average sales price per barrel decreased $39.09 or 45% and our natural gas average sales price per MMbtu decreased $6.37, or 70% compared to the same period of 2008.
          Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the third quarter of 2009, 55% of our total natural gas volumes and 45% of our total NGL volumes were hedged as compared to 60% and 68%, respectively in the same quarter of 2008. The impact of price risk management and marketing activities increased total natural gas and NGL revenues $0.9 million during the third quarter of 2009 compared to a net increase of $4.8 million in the same quarter of 2008.
          Costs of product sold. Our cost of products decreased $82.6 million, or 46%, for the third quarter of 2009 compared to the same period of 2008. Of this decrease, $70.3 million relates to NGLs and $12.3 million relates to natural gas. The decrease of $70.3 million in NGL cost of products sold was slightly larger than our decrease in NGL revenues as our NGL margins increased $0.17 per barrel, or 9%. The percentage decrease relating to natural gas cost of products sold was higher than the percentage decrease in natural gas revenues causing our natural gas margins to increase by 496%. This is primarily a result of revisions to the terms of certain producer contracts.
          Operating expenses. Operating expenses decreased $0.1 million, or 3%, for the third quarter of 2009 compared to the same period of 2008.
          Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.5 million, or 39%, for the third quarter of 2009 compared to the same period of 2008. This increase was primarily the result of $0.2 million in salary expenses related to additional personnel and $0.1 million of expenses related to the write-off of an uncollectible trade receivable.
          Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 10%, for the third quarter of 2009 compared to the same period of 2008.
          In summary, our natural gas services operating income decreased $3.0 million, or 64%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008.
          Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $2.1 million and $3.5 million for the three months ended September 30, 2009 and 2008, respectively, a decrease of 39%. This decrease is primarily a result of significantly decreased commodity prices slightly offset by increased volumes due to the Waskom plant and Waskom fractionator expansion that was completed near the end of the second quarter of 2009.
Marine Transportation Segment
          The following table summarizes our results of operations in our marine transportation segment.
                 
    Three Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues
  $ 18,659     $ 21,129  
Operating expenses
    12,230       15,033  
Selling, general and administrative expenses
    290       376  
Depreciation and amortization
    3,301       3,159  
 
           
 
    2,838       2,561  
 
           
Other operating income
    125       15  
 
           
Operating income
  $ 2,963     $ 2,576  
 
           

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          Revenues. Our marine transportation revenues decreased $2.5 million, or 12%, for the three months ended September 30, 2009, compared to the three months ended September 30, 2008. Our inland marine revenues decreased $3.0 million primarily due to a decrease in ancillary charges of $2.0 million and $1.0 million decline due to the decreased charter contract rate and decreased utilization of our inland fleet. Our offshore revenues increased $0.5 million due to increased utilization of the offshore vessels.
          Operating expenses. Operating expenses decreased $2.8 million, or 19%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. This was primarily a result of decreases in operating costs from fuel expense of $1.7 million and outside charter expenses of $1.1 million.
          Selling, general, and administrative expenses. Selling, general and administrative expenses decreased $0.1 million, or 23%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008.
          Depreciation and Amortization. Depreciation and amortization increased $0.1 million, or 4%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. This increase was primarily a result of capital expenditures made in the last twelve months.
          In summary, our marine transportation operating income increased $0.4 million, or 15%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008.
Sulfur Services Segment
          The following table summarizes our results of operations in our sulfur segment.
                 
    Three Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues
  $ 15,102     $ 133,660  
Cost of products sold
    7,807       120,267  
Operating expenses
    4,225       4,547  
Selling, general and administrative expenses
    709       733  
Depreciation and amortization
    1,569       1,451  
 
           
Operating income
  $ 792     $ 6,662  
 
           
 
               
Sulfur (long tons)
    296.1       290.8  
Fertilizer (long tons)
    32.6       57.4  
 
           
Sulfur Services Volumes (long tons)
    328.7       348.2  
 
           
          Revenues. Our sulfur services revenues decreased $118.6 million, or 89%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. This decrease was primarily a result of an 88% decrease in our average sales price. The sales price decrease was primarily due to decreased market prices for our sulfur products, primarily driven by lower costs of sulfur and raw materials for sulfur-based products as compared to a year ago same period.
          Cost of products sold. Our cost of products sold decreased $112.5 million, or 94%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. Our margin per ton decreased 42% which was driven by an overall weaker demand for our products as a result of the decreased sulfur market prices.
          Operating expenses. Our operating expenses decreased $0.3 million, or 7%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. This decrease was a result of a decline in the cost of fuel.
          Selling, general, and administrative expenses. Selling, general, and administrative expenses remained relatively consistent for both periods September 30, 2009 and 2008.

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          Depreciation and amortization. Depreciation and amortization expense increased $0.1 million, or 8%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. This was a result of our new Neches Prillmax Priller coming online in March 2009.
          In summary, our sulfur operating income decreased $5.9 million, or 88%, for the three months ended September 30, 2009 compared to the three months ended September 30, 2008.
Nine Months Ended September 30, 2009 Compared to the Nine Months Ended September 30, 2008
          Our total revenues were $442.4 million for the nine months ended September 30, 2009 compared to $992.1 million for the nine months ended September 30, 2008, a decrease of $549.7 million, or 55%. Our operating income was $24.6 million for the nine months ended September 30, 2009 compared to $28.7 million for the nine months ended September 30, 2008, a decrease of $4.1 million, or 14%.
          The results of operations are described in greater detail on a segment basis below.
Terminalling and Storage Segment
          The following table summarizes our results of operations in our terminalling and storage segment.
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues:
               
Services
  $ 31,806     $ 29,378  
Products
    28,897       36,626  
 
           
Total revenues
    60,703       66,004  
 
               
Cost of products sold
    25,558       31,222  
Operating expenses
    18,833       19,883  
Selling, general and administrative expenses
    171       56  
Depreciation and amortization
    7,837       6,784  
 
           
 
    8,304       8,059  
 
           
Other operating income
    5,081       (14 )
 
           
Operating income
  $ 13,385     $ 8,045  
 
           
          Revenues. Our terminalling and storage revenues decreased $5.3 million, or 8%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. Service revenue increased $2.4 million, which was offset by decreased products revenues of $7.7 million. The service revenue increase was primarily a result of new agreements entered into in 2008 and 2009, including a new lubricant terminalling fee of $4.4 million. This increase was offset by decreased activity at our terminals of $1.6 million and lost revenues due to the sale of our Mont Belvieu terminal of $0.4 million. Product sales revenue decreased $7.7 million primarily due to the sale of the traditional lubricant business including inventory to Martin Resource Management in April 2009 in return for a service fee for lubricant volumes moved through our terminals.
          Cost of products sold. Our cost of products decreased $5.7 million, or 18%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This decrease was primarily due to the sale of the traditional lubricant including inventory to Martin Resource Management in April 2009 in return for a service fee for lubricant volumes moved through our terminals.
          Operating expenses. Operating expenses decreased $1.1 million, or 5%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This decrease was a result of $1.6 million from hurricane expenses that were recorded in 2008 and a decrease in utilities expense of $0.2 million. These decreases were offset by increases in salaries and related burden of $0.4 million and product hauling costs of $0.3 million.
          Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.1 million, or 205%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This increase was a result of bad debt that was recorded in 2009.

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          Depreciation and amortization. Depreciation and amortization increased $1.1 million, or 16% for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This increase was primarily a result of our recent capital expenditures.
          Other operating income. Other operating income for the nine months ended September 30, 2009 consisted solely of a gain on the sale of our Mont Belvieu terminal on April 30, 2009.
          In summary, terminalling and storage operating income increased $5.3 million, or 66%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008.
Natural Gas Services Segment
          The following table summarizes our results of operations in our natural gas services segment.
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues:
               
NGLs
  $ 250,584     $ 528,353  
Natural gas
    14,307       50,090  
Non-cash mark to market adjustment of commodity derivatives
    (1,977 )     1,517  
Gain (loss) on cash settlements of commodity derivatives
    2,855       (4,816 )
Other operating fees
    2,987       2,173  
 
           
Total revenues
    268,756       577,317  
 
               
Cost of products sold (excluding depreciation and amortization):
               
NGLs
    235,935       513,221  
Natural gas
    13,551       49,656  
 
           
Total cost of products sold
    249,486       562,877  
 
               
Operating expenses
    6,462       6,287  
Selling, general and administrative expenses
    4,946       3,594  
Depreciation and amortization
    3,364       2,966  
 
           
 
    4,498       1,593  
 
           
Other operating income
          3  
 
           
Operating income
  $ 4,498     $ 1,596  
 
           
 
               
NGLs Volumes (Bbls)
    5,899       6,457  
 
           
Natural Gas Volumes (MMbtu)
    4,651       5,517  
 
           
 
               
Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments
               
 
               
Equity in Earnings of Unconsolidated Entities
  $ 5,227     $ 11,385  
 
           
 
               
Waskom:
               
Plant Inlet Volumes (MMcf/d)
    242       256  
 
           
Fractionated Volumes (Bbls/d)
    10,011       10,317  
 
           
          Revenues. Our natural gas services revenues decreased $308.6 million, or 53%, for the nine months ended September 30, 2009 compared to this same period of 2008. The decrease was primarily due to lower commodity prices and decreased volumes.
          For the nine months ended September 30, 2009, NGL revenues decreased $277.8 million, or 53% and natural gas revenues decreased $35.8 million, or 71%. NGL sales volumes for the nine months of 2009 decreased 9% and natural gas volumes decreased 16% compared to the same period of 2008. During the first nine months of 2009, our NGL average sales price per barrel decreased $39.35 or 48% and our natural gas average sales price per MMbtu decreased $6.00, or 66% compared to the same period of 2008. The decrease in natural gas volumes is primarily a result of the Waskom plant being shut down for a plant and fractionator expansion during the first half of 2009.

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          Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the first nine months of 2009, 55% of our total natural gas volumes and 45% of our total NGL volumes were hedged as compared to 59% and 68%, respectively in the same quarter of 2008. The impact of price risk management and marketing activities increased total natural gas and NGL revenues $0.9 million during the first nine months of 2009 compared to a decrease of $3.3 million in the same period of 2008.
          Costs of product sold. Our cost of products decreased $313.4 million, or 56%, for the nine months ended September 30, 2009 compared to the same period of 2008. Of the decrease, $277.3 million relates to NGLs and $36.1 million relates to natural gas. The percentage decrease in NGL cost of products sold is more than our decrease in NGL revenues as we were able to expand our NGL margins by $0.14 per barrel, or 6%. The percentage decrease relating to natural gas cost of products sold is greater than the percentage decrease in natural gas revenues which caused our natural gas margins to increase by 107%. This is primarily a result of revisions to the terms of certain producer contracts.
          Operating expenses. Operating expenses increased $0.2 million, or 3%, for the nine months ended September 30, 2009 compared to the same period of 2008.
          Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.4 million, or 38%, for the nine months ended September 30, 2009 compared to the same period of 2008. This increase was primarily the result of increased salary expenses of $1.0 million related to additional personnel, $0.1 million related to business development activities and $0.1 million related to the write-off of an uncollectible receivable..
          Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 13%, for the nine months ended September 30, 2009 compared to the same period of 2008. This increase was primarily a result of capital expenditures made in the last twelve months.
          In summary, our natural gas services operating income increased $2.9 million, or 182%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008.
          Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $5.2 million and $11.4 million for the nine months ended September 30, 2009 and 2008, respectively, a decrease of $6.2 million, or 54%. This decrease is primarily a result of significantly decreased commodity prices and decreased volumes as a result of the Waskom plant being shut down for a plant and fractionator expansion during the first half of 2009.
Marine Transportation Segment
          The following table summarizes our results of operations in our marine transportation segment.
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues
  $ 51,929     $ 58,418  
Operating expenses
    37,725       42,350  
Selling, general and administrative expenses
    645       893  
Depreciation and amortization
    9,868       8,901  
 
           
 
    3,691       6,274  
 
           
Other operating income
    116       154  
 
           
Operating income
  $ 3,807     $ 6,428  
 
           
          Revenues. Our marine transportation revenues decreased $6.5 million, or 11%, for the nine months ended September 30, 2009, compared to the nine months ended September 30, 2008. Our inland marine revenues declined $5.7 million primarily due to decreases in ancillary charges of $5.2 million and a $0.4 million decrease due to reduced charter contract rates and slight decrease in utilization of our inland fleet. Our offshore revenues decreased $0.8 million primarily from decreased utilization of our offshore vessels.

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          Operating expenses. Operating expenses decreased $4.6 million, or 11%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This was primarily a result of a decrease in fuel costs of $5.0 million and outside charter expenses of $1.6 million, offset primarily by an increase in repairs and maintenance of $0.8 million, wage and burden costs of $0.6 million, and insurance premiums of $0.4 million.
          Selling, general, and administrative expenses. Selling, general and administrative expenses decreased $0.2 million, or 28%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This was primarily a result of the collection of certain bad debt expenses in 2009.
          Depreciation and Amortization. Depreciation and amortization increased $1.0 million, or 11%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This increase was primarily a result of capital expenditures made in the last twelve months.
          In summary, our marine transportation operating income decreased $2.6 million, or 41%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008.
Sulfur Services Segment
          The following table summarizes our results of operations in our sulfur segment.
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Revenues
  $ 61,031     $ 290,346  
Cost of products sold
    35,014       254,173  
Operating expenses
    11,966       13,107  
Selling, general and administrative expenses
    2,305       2,073  
Depreciation and amortization
    4,588       4,282  
 
           
 
    7,158       16,711  
Other Operating income
    1        
 
           
Operating income
  $ 7,159     $ 16,711  
 
           
 
               
Sulfur (long tons)
    835.4       814.0  
Fertilizer (long tons)
    130.3       213.5  
 
           
Sulfur Services Volumes (long tons)
    965.7       1,027.5  
 
           
          Revenues. Our sulfur services revenues decreased $229.3 million, or 79%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This decrease was primarily a result of a 78% decrease in our average sales price. The sales price decrease was due primarily to decreased market prices for our sulfur products, primarily driven by lower costs of sulfur and raw materials for sulfur-based products.
          Cost of products sold. Our cost of products sold decreased $219.2 million, or 86%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. Our margin per ton decreased 23% which was driven by an overall weaker demand for our products as a result of the decreased sulfur market prices.
          Operating expenses. Our operating expenses decreased $1.1 million, or 9%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2009. This was a result of fuel expenses decreasing $1.7 million due to a decline in the cost of fuel. Offsetting that decrease is an increase in outside charter expense of $0.4 million and property taxes of $0.2 million.
          Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased $0.2 million, or 11%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 as a result of a recognition of a bad debts expense relating to a customer filing for bankruptcy protection.

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          Depreciation and amortization. Depreciation and amortization expense increased $0.3 million, or 7%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This was a result of our new Neches Prillmax Priller coming online in March 2009.
          In summary, our sulfur operating income decreased $9.6 million, or 57%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008.
Statement of Operations Items as a Percentage of Revenues
          Our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization as a percentage of revenues for the three and nine months ended September 30, 2009 and 2008 are as follows:
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2009   2008   2009   2008
Revenues
    100 %     100 %     100 %     100 %
Cost of products sold
    72 %     85 %     71 %     86 %
Operating expenses
    15 %     8 %     16 %     8 %
Selling, general and administrative expenses
    3 %     1 %     3 %     1 %
Depreciation and amortization
    6 %     2 %     6 %     2 %
Equity in Earnings of Unconsolidated Entities
          We own an unconsolidated 50% interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these assets are accounted for by the equity method.
          On June 30, 2006, our Prism Gas subsidiary, acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). The lease contract terminated in June 2009, and, as such, the investment was fully amortized as of June 30, 2009.
          For the three and nine months ended September 30, 2009 and 2008 equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom, Matagorda, PIPE and BCP.
          Equity in earnings of unconsolidated entities was $2.1 million for the three months ended September 30, 2009 compared to $3.5 million for the three months ended September 30, 2008, a decrease of $1.4 million. This decrease is related to earnings received from Waskom, Matagorda, PIPE and BCP. This decrease is primarily a result of significantly decreased commodity prices slightly offset by increased volumes due to the Waskom plant and Waskom fractionator expansion that was completed near the end of the second quarter of 2009.
          Equity in earnings of unconsolidated entities was $5.2 million for the nine months ended September 30, 2009 compared to $11.4 million for the nine months ended September 30, 2008, a decrease of $6.2 million. This decrease is related to earnings received from Waskom, Matagorda, PIPE and BCP. This decrease is primarily a result of significantly decreased commodity prices and decreased volumes as a result of the Waskom plant being shut down for a plant and fractionator expansion during the first half of 2009.
Interest Expense
          Our interest expense for all operations was $4.1 million for the three months ended September 30, 2009, compared to the $5.0 million for the three months ended September 30, 2008, a decrease of $0.9 million, or 18%. This decrease was primarily due to recognized decreases in interest expense related to the difference between the fixed rate and the floating rate of interest on the mark-to-market interest rate swaps and a decrease in interest rates offset by an increase in average debt outstanding.
          Our interest expense for all operations was $12.9 million for the nine months ended September 30, 2009, compared to the $13.6 million for the nine months ended September 30, 2008, a decrease of $0.7 million, or 5%. This decrease was primarily due to recognized decreases in interest expense related to the difference

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between the fixed rate and the floating rate of interest on the mark-to-market interest rate swaps and a decrease in interest rates offset by an increase in average debt outstanding.
Indirect Selling, General and Administrative Expenses
          Indirect selling, general and administrative expenses were $1.4 million for both the three months ended September 30, 2009 and 2008.
          Indirect selling, general and administrative expenses were $4.3 million for the nine months ended September 30, 2009 compared to $4.1 million for the nine months ended September 30, 2008, an increase of $0.2 million, or 5%.
          Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based primarily on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income. Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million. This cap expired on November 1, 2007. Effective October 1, 2009, the Conflicts Committee of our general partner approved a reimbursement amount for indirect expenses of $3.5 million, annually. Martin Resource Management allocated indirect selling, general and administrative expenses of $0.9 million and $0.7 million for the three months ended September 30, 2009 and 2008, respectively, and $2.6 million and $2.0 million for the nine months ended September 30, 2009 and 2008, respectively.
Liquidity and Capital Resources
          Credit Facility Expiration Date; Impact of Current Economic Crisis and Existing Litigation at Martin Resource Management
          Our credit facility, with an outstanding balance of $300 million as of September 30, 2009, expires on November 9, 2010 and all outstanding balances thereunder will become due and payable on that date. As a result, we have engaged our existing administrative agent and another lender to act as lead arranging agents for the purpose of assisting us in securing an extension or amendment to the credit facility or a new replacement credit facility. We anticipate that the syndication process relating to such extension, amendment or new facility will commence following the consummation of certain pending cash and asset contributions from Martin Resource Management, the owner of our General Partner, in exchange for newly issued common and subordinated units in us, which consummation is anticipated prior to the end of November 2009, subject to certain conditions, including the approval of such transactions by the lender under Martin Resource Management’s credit facility. (See “Subsequent Events — Cross Transaction and Equity Transaction” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” set forth elsewhere herein for a description of such pending transactions). While we do not currently anticipate a problem obtaining an extension, amendment or a new facility, there can be no assurance, in light of the current credit market and the existing litigation at Martin Resource Management (See “Item 5. Other Information” set forth elsewhere herein for a description of such litigation), that we will successfully obtain an extension, amendment or a new facility. If we are unable to obtain an extension, amendment or a new credit facility, our ability to make scheduled debt payments, make quarterly distributions on our units, meet our working capital requirements and fund our expansion and maintenance capital expenditures will be adversely affected.
          In addition, unless we are able to consummate the pending cash and asset contributions described in the immediately preceding paragraph prior to December 31, 2009, it is possible that we will be out of compliance with the debt to EBITDA leverage ratio covenant contained in our credit facility on such date, thereby resulting in a default thereunder and the need to seek a waiver of such default from our lenders and negatively impacting our ability to extend, amend or replace our credit facility. Should we fail to obtain a

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waiver of such default, the lenders would be entitled to demand immediate payment of all outstanding amounts under the credit facility. The leverage ratio is calculated by dividing our total secured funded debt at the end of the December 31, 2009 quarter by our EBITDA for the year then ended. However, we believe that such pending cash and asset contributions will be consummated prior to the end of November 2009 and that, and as a result, we will be in compliance with such leverage ratio on December 31, 2009.
          Subject to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2009.
          Due to restrictions on liquidity within the capital markets and the existing litigation at Martin Resource Management our ability to access the capital markets may be constrained. Our near-term focus is to ensure we that we have extended the maturity date of our existing credit facility (either through an extension, amendment or entering into a new credit facility) and that we have sufficient liquidity to fund our growth programs, while continuing the present distribution rate to our unitholders. The current economic crisis and the existing litigation at Martin Resource Management has created a challenging operating environment for us to maintain our liquidity and operating cash flows at levels consistent with the recent past while maintaining the present distribution rate to our unitholders. We continue to evaluate our liquidity and capital resources and we have and will continue to consider sales of non-essential assets and other available options for additional liquidity. For example, in the second quarter of 2009 we sold the assets comprising the Mont Belvieu railcar unloading facility to Enterprise Products Operating LLC. (See Note 13 to our Financial Statements — Gain on Disposal of Assets).
          Within the constraints noted above, we intend to move forward with our commercially supported internal growth projects. We may revise the timing and scope of other projects as necessary to adapt to existing economic, capital market and litigation conditions affecting us.
          Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. For example, the impact of the current economic crisis may significantly affect our customers, including their ability to satisfy amounts due to us on a timely basis. Please read “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2008, filed with the SEC on March 4, 2009, as well as our updated risk factors contained in “Item 1A. Risk Factors” set forth elsewhere herein, for a discussion of such risks.
          Cash Flows and Capital Expenditures
          For the nine months ended September 30, 2009 cash decreased $2.0 million as a result of $40.2 million provided by operating activities, $10.1 million used in investing activities and $32.1 million used in financing activities. For the nine months ended September 30, 2008 cash increased $2.9 million as a result of $60.6 million provided by operating activities, $78.8 million used in investing activities and $21.0 million provided by financing activities.
          For the nine months ended September 30, 2009 our investing activities of $10.1 million consisted of capital expenditures, acquisitions, proceeds from sale of property, plant and equipment, return of investments from unconsolidated entities and investments in and distributions from unconsolidated entities. For the nine months ended September 30, 2008 our investing activities of $78.8 million consisted of capital expenditures, acquisitions, proceeds from sale of property, plant and equipment, return of investments from unconsolidated entities and investments in and distributions from unconsolidated entities.
          Generally, our capital expenditure requirements have consisted, and we expect that our capital requirements will continue to consist, of:
    maintenance capital expenditures, which are capital expenditures made to replace assets to maintain our existing operations and to extend the useful lives of our assets; and
 
    expansion capital expenditures, which are capital expenditures made to grow our business, to expand and upgrade our existing terminalling, marine transportation, storage and manufacturing facilities, and to construct new terminalling facilities, plants, storage facilities and new marine transportation assets.

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          For the nine months ended September 30, 2009 and 2008, our capital expenditures for property and equipment were $39.6 million and $78.2 million, respectively.
          As to each period:
    For the nine months ended September 30, 2009, we spent $32.9 million for expansion and $6.7 million for maintenance. Our expansion capital expenditures were made in connection with two marine vessel capital leases and construction projects associated with our terminalling and sulfur services segments. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements.
 
    For the nine months ended September 30, 2008, we spent $68.2 million for expansion and $10.0 million for maintenance. Our expansion capital expenditures were made in connection with assets acquired in the Stanolind acquisition, marine vessel purchases and conversions and construction projects associated with our terminalling business. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements.
          For the nine months ended September 30, 2009, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $35.6 million, payments of long term debt to financial lenders of $85.0 million, borrowings of long-term debt under our credit facility of $88.5 million and purchase of treasury units of $0.1 million.
          For the nine months ended September 30, 2008, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $33.9 million, payments of long term debt to financial lenders of $180.4 million, borrowings of long-term debt under our credit facility of $235.4 million and purchase of treasury units of $0.1 million.
          We made net investments in (received distributions from) unconsolidated entities of $0.8 million and $2.0 million during the nine months ended September 30, 2009 and 2008, respectively. The net investment in unconsolidated entities includes $3.3 million and $4.3 million of expansion capital expenditures in the nine months ended September 30, 2009 and 2008, respectively.
          Capital Resources
          Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity needs to be cash flows from operations and borrowings under our credit facility.
          As of September 30, 2009, we had $300.0 million of outstanding indebtedness, consisting of outstanding borrowings of $170.0 million under our revolving credit facility and $130.0 million under our term loan facility.
          Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2009 is as follows (dollars in thousands):

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    Payment due by period  
    Total     Less than     1-3     3-5     Due  
Type of Obligation   Obligation     One Year     Years     Years     Thereafter  
Long-Term Debt
                                       
Revolving credit facility
  $ 170,000     $     $ 170,000     $     $  
Term loan facility
    130,000             130,000              
Capital leases including current maturities
    6,311       107       278       455       5,471  
Non-competition agreements
    300       100       100       100        
Purchase obligations
    23,280       7,760       15,520              
Operating leases
    24,165       4,262       10,182       4,350       5,371  
Interest expense(1)
                                       
Revolving Credit Facility
    9,019       8,117       902              
Term loan facility
    8,784       7,906       878              
Capital leases
    6,321       995       1,933       1,819       1,574  
 
                             
 
                                       
Total contractual cash obligations
  $ 378,180     $ 29,247     $ 329,793     $ 6,724     $ 12,416  
 
                             
 
(1)   Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.
          Letter of Credit. At September 30, 2009, we had outstanding irrevocable letters of credit in the amount of $2.1 million which were issued under our revolving credit facility.
          Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.
          Description of Our Credit Facility
          On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of credit sub-limit. Our credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25.0 million resulting in a committed $120.0 million revolving credit facility. Effective December 28, 2007, we increased our revolving credit facility $75.0 million resulting in a committed $195.0 million revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of September 30, 2009, we had $170.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of September 30, 2009, irrevocable letters of credit issued under our credit facility totaled $2.1 million. As of September 30, 2009, we had $22.9 million available under our revolving credit facility.
          Draws made under our credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on our credit facilities have ranged from a low of $285.0 million to a high of $315.0 million. As of September 30, 2009, we had $22.9 million available for working capital, internal expansion and acquisition activities under our credit facility.
          Our obligations under the credit facility are secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, marine vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees. We may prepay all amounts outstanding under this facility at any time without penalty.
          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 LIBOR borrowings is 2.00%. Effective October 1, 2009, the applicable margin for existing LIBOR borrowings will remain at 2.00%. As a result of our leverage ratio test, effective January 1,

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2010, the applicable margin for existing LIBOR borrowings will increase to 2.50%. We incur a commitment fee on the unused portions of the credit facility.
          Effective October 2008, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 2.820% plus our applicable LIBOR borrowing spread. Effective April 2009, we entered into two subsequent swaps to lower our effective fixed rate to 2.580% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is accounted for using hedge accounting. Each of the swaps matures in October 2010.
          Effective January 2008, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed rate. The fixed rate cost is 3.400% plus our applicable LIBOR borrowing spread. Effective April 2009, we entered into two subsequent swaps to lower our effective fixed rate to 3.050% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is accounted for using hedge accounting. Each of the swaps matures in January 2010.
          Effective September 2007, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed rate. The fixed rate cost is 4.605% plus our applicable LIBOR borrowing spread. Effective March 2009, we entered into two subsequent swaps to lower our effective fixed rate to 4.305% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is accounted for using hedge accounting. Each of the swaps matures in September 2010.
          Effective November 2006, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing spread. Effective March 2009, we entered into two subsequent swaps to lower our effective fixed rate to 4.37% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is accounted for using hedge accounting. Each of the swaps matures in December 2009.
          Effective November 2006, we entered into an interest rate swap that swaps $30.0 million of floating rate to fixed rate. The fixed rate cost is 4.765% plus our applicable LIBOR borrowing spread. This interest rate swap, which matures in March 2010, is not accounted for using hedge accounting.
          Effective March 2006, we entered into an interest rate swap that swaps $75.0 million of floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. Effective February 2009, we entered into two subsequent swaps to lower our effective fixed rate to 5.10% plus our applicable LIBOR borrowing spread. The original swap and the first subsequent swap are accounted for using mark-to-market accounting. The second subsequent swap is accounted for using hedge accounting. Each of the swaps matures in November 2010.
          In addition, the credit facility contains various covenants, which, among other things, limit our ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless we are the survivor; (iv) sell all or substantially all of our assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) incur indebtedness or grant certain liens through our joint ventures.
          The credit facility also contains covenants, which, among other things, require us to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) ) trailing four quarters of Earnings Before Interest, Taxes, Depreciation and Amortization as defined in the credit facility, (“EBITDA”) 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 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. We are in compliance with the covenants contained in the credit facility as of September 30, 2009.
          The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding there under immediately due and payable. In addition, an event of default by

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Martin Resource Management under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us. Any event of default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations as well as our ability to make distributions to unitholders.
          We are a party to certain pending cash and asset contributions from Martin Resource Management, the owner of our General Partner. In exchange for these contributions we will issue common and subordinated units in us to Martin Resource Management (See “Subsequent Events — Cross Transaction and Equity Transaction” in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section for a description of such pending transactions). Unless we are able to consummate these pending transactions prior to December 31, 2009, it is possible that we will be out of compliance with the debt to EBITDA leverage ratio covenant contained in our credit facility on such date, thereby resulting in a default thereunder and the need to seek a waiver of such default from our lenders and negatively impacting our ability to extend, amend or replace the credit facility. Should we fail to obtain a waiver of such default, the lenders would be entitled to demand immediate payment of all outstanding amounts under the credit facility. The leverage ratio is calculated by dividing our total secured funded debt at the end of the December 31, 2009 quarter by our EBITDA for the year then ended. However, we believe that such pending transactions will be consummated prior to the end of November 2009 and that, and as a result, we will be in compliance with such leverage ratio on December 31, 2009.
          On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless the ratio of total funded debt to EBITDA is less than 3.00 to 1.00. No prepayments under the term loan were required to be made through September 30, 2009. If we receive greater than $15.0 million from the incurrence of indebtedness other than under the credit facility, we must prepay indebtedness under the credit facility with all such proceeds in excess of $15.0 million. Any such prepayments are first applied to the term loans under the credit facility. We must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. We 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.
          As of November 3, 2009, our outstanding indebtedness includes $301.0 million under our credit facility.
Seasonality
          A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season. The demand for fertilizers is strongest during the early spring planting season. However, our terminalling and storage and marine transportation businesses and the molten sulfur business are typically not impacted by seasonal fluctuations. We expect to derive a majority of our net income from our terminalling and storage, marine transportation and sulfur businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our terminalling and storage and marine transportation businesses. For example, Hurricanes Katrina and Rita in the third quarter of 2005 adversely impacted operating expenses and the four hurricanes that impacted the Gulf of Mexico and Florida in the third quarter of 2004 adversely impacted our terminalling and storage and marine transportation business’s revenues.
Impact of Inflation
          Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the nine months ended September 30, 2009 and 2008. However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot assure you that we will be able to pass along increased costs to our customers.

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          Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot assure you that we will be able to pass along increased operating expenses to our customers.
Environmental Matters
          Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the three and nine months ended September 30, 2009 or 2008.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk
          Commodity Price Risk. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Under our hedging policy, we monitor and manage the commodity market risk associated with the commodity risk exposure of Prism Gas. In addition, we are focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.
          We use derivatives to manage the risk of commodity price fluctuations. These outstanding contracts expose us to credit loss in the event of nonperformance by the counterparties to the agreements. We have incurred no losses associated with counterparty nonperformance on derivative contracts.
          On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, and have established a maximum credit limit threshold pursuant to our hedging policy, and monitor the appropriateness of these limits on an ongoing basis. We have agreements with three counterparties containing collateral provisions. Based on those current agreements, cash deposits are required to be posted whenever the net fair value of derivatives associated with the individual counterparty exceed a specific threshold. If this threshold is exceeded, cash is posted by us if the value of derivatives is a liability to us. As of September 30, 2009, we have no cash collateral deposits posted with counterparties.
          We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales activities. Our exposure to these fluctuations is primarily in the gas processing component of our business. Gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids and percent-of-proceeds bases.
  1)   Percent-of-liquids contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the NGLs recovered, and the producer bears all of the cost of natural gas shrink. Therefore, margins increase during periods of high NGL prices and decrease during periods of low NGL prices.
 
  2)   Percent-of-proceeds contracts: Under these contracts, the Partnership generally gathers and processes natural gas on behalf of certain producers, sells the resulting residue gas and NGLs at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed upon percentage of the residue gas and NGLs to the producer and sells the volumes kept to third parties at market prices. Under these types of contracts, revenues and gross margins increase as natural gas prices and NGL prices increase, and revenues and gross margins decrease as natural gas and NGL prices decease.
          Market risk associated with gas processing margins by contract type, and gathering and transportation margins as a percent of total gross margin remained consistent for the three and nine months ended September 30, 2009 and 2008 as the Partnership’s contract mix and volumes associated with those contracts did not differ materially.
          The aggregate effect of a hypothetical $1.00/MMbtu increase or decrease in the natural gas price index would result in an approximate annual gross margin change of $0.6 million. In addition, the aggregate effect of a hypothetical $10.00/Bbl increase or decrease in the crude oil price index would result in an approximate annual gross margin change of $0.6 million.
          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 natural gasoline.
          Based on estimated volumes, as of September 30, 2009, we had hedged approximately 56% and 27% of our commodity risk by volume for 2009 and 2010, respectively. We anticipate entering into additional commodity derivatives on an ongoing basis to manage our risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and

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options, although there is no assurance that we will be able to do so or that the terms thereof will be similar to our existing hedging arrangements.
The relevant payment indices for our various commodity contracts are as follows:
    Natural gas contracts — monthly posting for Columbia Gulf Transmission Co., Mainline as posted in Platts Inside FERC’s Gas Market Report;
 
    Crude oil contracts — WTI NYMEX average for the month of the daily closing prices; and
 
    Natural gasoline contracts — Mt. Belvieu Non-TET average monthly postings as reported by the Oil Price Information Service (OPIS).
Hedging Arrangements in Place
As of September 30, 2009
                                                 
                    Commodity   Commodity   Fair Value   Fair Value
                    Price   Price   Asset   Liability
Period   Underlying   Notional Volume   We Receive   We Pay   (In Thousands)   (In Thousands)
 
October 2009—December 2009
  Natural Gas   90,000 (MMbtu)   Index   $9.025/MMbtu   $ 389     $  
October 2009—December 2009
  Crude Oil   9,000 (BBL)   Index   $69.08/bbl           (8 )
October 2009—December 2009
  Crude Oil   9,000 (BBL)   Index   $70.90/bbl     9        
October 2009—December 2009
  Crude Oil   3,000 (BBL)   Index   $70.45/bbl     2        
October 2009—December 2009
  Natural Gasoline   6,000 (BBL)   Index   $86.42/bbl     160        
January 2010—December 2010
  Crude Oil   24,000 (BBL)   Index   $69.15/bbl           (106 )
January 2010—December 2010
  Crude Oil   36,000 (BBL)   Index   $72.25/bbl           (54 )
January 2010—December 2010
  Crude Oil   12,000 (BBL)   Index   $104.80/bbl     370        
January 2010—December 2010
  Natural Gasoline   12,000 (BBL)   Index   $94.14/bbl     378        
                                     
 
                                  $ 1,308     $ (168 )
                                     
          Our principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of our natural gas and NGL sales are made at market-based prices. Our standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to us.
          Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 5.74% as of September 30, 2009. We had a total of $301.0 million of indebtedness outstanding under our credit facility as of November 3, 2009 of which $66.0 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on September 30, 2009, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $0.7 million annually.
          We have entered into interest rate protection agreements to manage our interest rate risk exposure by fixing a portion of the interest expense we pay on our long-term debt under our credit facility. Continued disruption in the banking markets could affect whether our counterparties of interest rate protection agreements are able to honor their agreements. If the counterparties fail to honor their commitments, we could experience higher interest rates, which could have a material adverse effect on our business, financial condition and results of operations. In addition, if the counterparties fail to honor their commitments, we also may be required to replace such interest rate protection agreements with new interest rate protection agreements, and such replacement interest rate protection agreements may be at higher rates than our current interest rate protection agreements.

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          We manage a portion of our interest rate risk with interest rate swaps, which reduce our exposure to changes in interest rates by converting variable interest rates to fixed interest rates. Pursuant to the terms of the interest rate swap agreement, we pay a fixed rate and receive an interest payment based on the three-month LIBOR. The net difference to be paid or received under the interest rate swap agreement is settled quarterly and is recognized as an adjustment to interest expense.
          At September 30, 2009, we are party to interest rate swap agreements with Royal Bank of Canada as shown below:
Interest Rate Swaps
As of September 30, 2009
                                                 
                                    Fair Value   Fair Value
            Notional   Interest Rate   Interest Rate   Asset   Liability
Date of Swap   Maturity   Amount   We Pay   We Receive   (In Thousands)   (In Thousands)
 
April 2006
  November 2010   $ 75,000       5.250 %   3 MO LIBOR   $     $ 4,132  
December 2006
  December 2009   $ 40,000       4.820 %   3 MO LIBOR           451  
November 2006
  March 2010   $ 30,000       4.765 %   3 MO LIBOR           656  
September 2007
  September 2010   $ 25,000       4.605 %   3 MO LIBOR           987  
January 2008
  January 2010   $ 25,000       3.400 %   3 MO LIBOR           377  
October 2008
  October 2010   $ 40,000       2.820 %   3 MO LIBOR           1,087  
February 2009
  November 2010   $ 75,000       1.295 %   1 MO LIBOR           603  
March 2009
  December 2009   $ 40,000       .970 %   1 MO LIBOR           73  
March 2009
  September 2010   $ 25,000       1.290 %   1 MO LIBOR           194  
April 2009
  January 2010   $ 25,000       .720 %   1 MO LIBOR           38  
April 2009
  October 2010   $ 40,000       1.000 %   1 MO LIBOR           190  
February 2009
  November 2010   $ 75,000     3 MO LIBOR     1.445 %     721        
March 2009
  December 2009   $ 40,000     3 MO LIBOR     1.420 %     113        
March 2009
  September 2010   $ 25,000     3 MO LIBOR     1.590 %     260        
April 2009
  January 2010   $ 25,000     3 MO LIBOR     1.070 %     85        
April 2009
  October 2010   $ 40,000     3 MO LIBOR     1.240 %     319        
                                     
 
                                  $ 1,498     $ 8,788  
                                     
Item 4. Controls and Procedures
          Evaluation of disclosure controls and procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report, to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
          There were no changes in our internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II — OTHER INFORMATION
Item 1. Legal Proceedings
          From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity.
          In addition to the foregoing, as a result of an inspection by the U.S. Coast Guard of our tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, we have been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two employees of Martin Resource Management who provide services to us were served with grand jury subpoenas during the fourth quarter of 2007. In addition, in April of 2009, an additional grand jury subpoena was issued pertaining to the provision of certain documents relating to the Martin Explorer and its crew. We are cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against us.
Item 1A. Risk Factors
Our credit facility expires on November 9, 2010, and we have commenced the process of extending, amending or replacing the facility. If we are unable to obtain an extension, amendment or a new credit facility, the outstanding balance thereof will become due and payable on that date and our ability to make scheduled debt payments, make quarterly distributions on our units, meet our working capital requirements and fund our expansion and maintenance capital expenditures will be adversely affected.
In addition, we anticipate that on December 31, 2009, if we successfully consummate certain pending cash and asset contributions from Martin Resource Management the owner of our General Partner, in exchange for newly issued common and subordinated units in us, we will be in compliance with our credit facility covenants. However, if we fail to consummate such transactions, it is possible that we will be out of compliance with the debt to EBITDA leverage ratio covenant in our credit facility on that date, thereby resulting in a default thereunder and the need to seek a waiver of such default from our lenders and negatively impacting our ability to extend, amend or replace our credit facility.
          Our credit facility, with an outstanding balance of $300 million as of September 30, 2009, expires on November 9, 2010 and all outstanding balances thereunder will become due and payable on that date. As a result, we have engaged our existing administrative agent and another lender to act as lead arranging agents for the purpose of assisting us in securing an extension or an amendment to the credit facility or a new replacement credit facility. We anticipate that the syndication process relating to such extension, amendment or new facility will commence following the consummation of certain pending cash and asset contributions from Martin Resource Management, the owner of our General Partner, in exchange for newly issued common and subordinated units in us, which consummation is anticipated prior to the end of November 2009, subject to certain conditions, including the approval of such transactions by the lenders under Martin Resource Management’s credit facility. (See “Subsequent Events — Cross Transaction and Equity Transaction” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” set forth elsewhere herein for a description of such pending transactions). While we do not currently anticipate a problem obtaining an extension, amendment or a new facility, there can be no assurance, in light of the current credit market and the existing litigation at Martin Resource Management (See “Item 5. Other Information” set forth elsewhere herein for a description of such litigation), that we will successfully obtain an extension, amendment or a new facility. If we are unable to obtain an extension, amendment or a new credit facility, our ability to make scheduled debt payments, make quarterly distributions on our units, meet our working capital requirements and fund our expansion and maintenance capital expenditures will be adversely affected.
          In addition, unless we are able to consummate the pending cash and asset contributions described in the immediately preceding paragraph prior to December 31, 2009, it is possible that we will be out of compliance with the debt to EBITDA leverage ratio covenant contained in our credit facility on such date, thereby resulting in a default thereunder and the need to seek a waiver of such default from our lenders and negatively impacting our ability to extend, amend or replace our credit facility. Should we fail to obtain a waiver of such default, the lenders would be entitled to demand immediate payment of all outstanding amounts

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under the credit facility. The leverage ratio is calculated by dividing our total secured funded debt at the end of the December 31, 2009 quarter by our EBITDA for the year then ended. However, we believe that such pending cash and asset contributions will be consummated prior to the end of November 2009 and that, and as a result, we will be in compliance with such leverage ratio on December 31, 2009.
     There have been no other material changes in our risk factors from those disclosed in “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2008 filed with the SEC on March 4, 2009. For more information with regard to risk factors, please see “Item 1A. Risk Factors” of our Form 10-K for the year ended December 31, 2008 filed with the SEC on March 4, 2009.
Item 5. Other Information
          Certain Other Information. On May 2, 2008, we received a copy of a petition filed in the District Court of Gregg County, Texas (the “Court”) by Scott D. Martin (the “Plaintiff”) against Ruben S. Martin, III (the “Defendant”) with respect to certain matters relating to Martin Resource Management. The Plaintiff and the Defendant are executive officers of Martin Resource Management and our general partner, the Defendant is a director of both Martin Resource Management and our general partner, and the Plaintiff is a director of Martin Resource Management. The lawsuit alleged that the Defendant breached a settlement agreement with the Plaintiff concerning certain Martin Resource Management matters and that the Defendant breached fiduciary duties allegedly owed to the Plaintiff in connection with their respective ownership and other positions with Martin Resource Management. Prior to the trial of this lawsuit, the Plaintiff dropped his claims against the Defendant relating to the breach of fiduciary duty allegations. We are not a party to the lawsuit and the lawsuit does not assert any claims (i) against us, (ii) concerning our governance or operations or (iii) against the Defendant with respect to his service as an officer or director of our general partner.
          In May 2009, the lawsuit went to trial and on June 18, 2009, the Court entered a judgment (the “Judgment”) with respect to the lawsuit as further described below. In connection with the Judgment, the Defendant has advised us that he has filed a motion for new trial, a motion for judgment notwithstanding the verdict and a notice of appeal. In addition, on June 22, 2009, the Plaintiff filed a notice of appeal with the Court indicating his intent to appeal the Judgment. The Defendant has further advised us that on June 30, 2009 he posted a cash deposit in lieu of a bond and the judge has ruled that as a result of such deposit, the enforcement of any of the provisions in the Judgment is stayed until the matter is resolved on appeal. Accordingly, during the pendancy of the of the appeal process, no change in the makeup of the Martin Resource Management Board of Directors is expected.
          The Judgment awarded the Plaintiff monetary damages in the approximate amount of $3.2 million, attorney’s fees of approximately $1.6 million and interest. In addition, the Judgment grants specific performance and provides that the Defendant is to (i) transfer one share of his Martin Resource Management common stock to the Plaintiff, (ii) take such actions, including the voting of any Martin Resource Management shares which the Defendant owns, controls or otherwise has the power to vote, as are necessary to change the composition of the Board of Directors of Martin Resource Management from a five-person board, currently consisting of the Defendant and the Plaintiff as well as Wes Skelton, Don Neumeyer, and Bob Bondurant (executive officers of Martin Resource Management and the Partnership), to a four-person board to consist of the Defendant and his designee and the Plaintiff and his designee, and (iii) take such actions as are necessary to change the trustees of the Martin Resource Management Employee Stock Ownership Trust (the “MRMC ESOP Trust”), currently consisting of the Defendant, the Plaintiff and Wes Skelton, to just the Defendant and the Plaintiff. The Judgment is directed solely at the Defendant and is not binding on any other officer, director or shareholder of Martin Resource Management or any trustee of a trust owning Martin Resource Management shares. The Judgment with respect to (ii) above will terminate on February 17, 2010, and with respect to (iii) above on the 30th day after the election by the Martin Resource Management shareholders of the first successor Martin Resource Management board after February 17, 2010. However, any enforcement of the Judgment is stayed pending resolution of the appeal relating to it.
          On September 5, 2008, the Plaintiff and one of his affiliated partnerships (the “SDM Plaintiffs”), on behalf of themselves and derivatively on behalf of Martin Resource Management, filed suit in a Harris County, Texas district court against Martin Resource Management, the Defendant, Robert Bondurant, Donald R. Neumeyer and Wesley Skelton, in their capacities as directors of Martin Resource Management (the “MRMC Director Defendants”), as well as 35 other officers and employees of Martin Resource Management (the “Other MRMC Defendants”). In addition to their respective positions with Martin Resource Management, Robert Bondurant, Donald Neumeyer and Wesley Skelton are officers of our general partner. We are not a party to this

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lawsuit, and it does not assert any claims (i) against us, (ii) concerning our governance or operations or (iii) against the MRMC Director Defendants or Other MRMC Defendants with respect to their service to us.
          The SDM Plaintiffs allege, among other things, that the MRMC Director Defendants have breached their fiduciary duties owed to Martin Resource Management and the SDM Plaintiffs, entrenched their control of Martin Resource Management and diluted the ownership position of the SDM Plaintiffs and certain other minority shareholders in Martin Resource Management, and engaged in acts of unjust enrichment, excessive compensation, waste, fraud and conspiracy with respect to Martin Resource Management. The SDM Plaintiffs seek, among other things, to rescind the June 2008 issuance by Martin Resource Management of shares of its common stock under its 2007 Long-Term Incentive Plan to the Other MRMC Defendants, remove the MRMC Director Defendants as officers and directors of Martin Resource Management, prohibit the Defendant, Wesley Skelton and Robert Bondurant from serving as trustees of the MRMC Employee Stock Ownership Plan, and place all of the Martin Resource Management common shares owned or controlled by the Defendant in a constructive trust that prohibits him from voting those shares. The SDM Plaintiffs have amended their Petition to eliminate their claims regarding rescission of the issue by Martin Resource Management of shares of its common stock to the MRMC Employee Stock Ownership Plan. The Court abated this lawsuit on July 13, 2009 until a mandamus pending before the Texas Supreme Court dealing with matters at issue in the lawsuit is resolved.
          The lawsuits described above are in addition to (i) a separate lawsuit filed in July 2008 in a Gregg County, Texas district court by the daughters of the Defendant against the Plaintiff, both individually and in his capacity as trustee of the Ruben S. Martin, III Dynasty Trust, which suit alleges, among other things, that the Plaintiff has engaged in self-dealing in his capacity as a trustee under the trust, which holds shares of Martin Resource Management common stock, and has breached his fiduciary duties owed to the plaintiffs, and who are beneficiaries of such trust, and (ii) a separate lawsuit filed in October 2008 in the United States District Court for the Eastern District of Texas by Angela Jones Alexander against the Defendant and Karen Yost in their capacities as a former trustee and a trustee, respectively, of the R.S. Martin Jr. Children Trust No. One (f/b/o Angela Santi Jones), which holds shares of Martin Resource Management common stock, which suit alleges, among other things that the Defendant and Karen Yost breached the fiduciary duties owed to the plaintiff, who is the beneficiary of such trust, and seeks to remove Karen Yost as the trustee of such trust. With respect to the lawsuit described in (i) above, it should be noted that the Plaintiff has resigned as a trustee of the Ruben S. Martin, III Dynasty Trust. With respect to the lawsuit described in (ii) above, Angela Jones Alexander has amended her claims to include her grandmother, Margaret Martin, as a party. The lawsuit referenced in (i) above is currently set for trial on November 30, 2009.
          On September 24, 2008, Martin Resource Management removed Plaintiff as a director of the general partner of the Partnership. Such action was taken as a result of the collective effect of Plaintiff’s then recent activities, which the Board of Directors of Martin Resource Management determined were detrimental to both Martin Resource Management and the Partnership. The Plaintiff does not serve on any committees of the board of directors of our general partner. The position on the board of directors of our general partner vacated by the Plaintiff may be filled in accordance with the existing procedures for replacement of a departing director utilizing the Nominations Committee of the board of directors of the general partner of the Partnership. This position on the board of directors has not been filled as of November 4, 2009.
          Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” set forth elsewhere herein for a discussion of certain factors impacting our access to capital markets, including the litigation described above.
          Cross Transaction and Equity Transaction. On November 4, 2009, we entered into a Contribution Agreement with Martin Resource Management and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of Martin Resource Management, the owner of our general partner (“MRMC”), to acquire certain specialty lubricants processing assets (“Assets”) from Cross for total consideration of $45.0 million (the “Contribution”). In consideration for the Cross Assets, our will issue 804,721 common units and 894,134 subordinated units to MRMC at a price of $27.96 and $25.16 per limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February 2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the Contribution. At the end of such second anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units. The pricing of the units is based on the average closing price of our common units during the ten trading days ending November 3, 2009, with a 10% discount applied to the average in the case of the subordinated units. In connection with the Contribution, our general partner, will make a capital contribution of $0.9 million to us in order to maintain its 2% general partner interest in us.

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          In connection with the closing of the Contribution, MRMC and we have agreed to enter into a long-term, fee for services-based Tolling Agreement whereby MRMC agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, MRMC has generally agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a price of $4.00 per barrel. Any additional barrels will refined at a price of $4.28 per barrel. In addition, MRMC has agreed to pay a monthly reservation fee of $1.3 million and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. The Tolling Agreement will have a 12 year term, subject to certain termination rights specified therein. MRMC will continue to market and distribute all finished products under the Cross brand name. In addition, MRMC will continue to own and operate the Cross packaging business. The closing of the Contribution is subject to standard closing conditions, including the approval of the lenders under MRMC’s credit facility and the approval of the assignment of various regulatory licenses and permits. Closing is anticipated prior to the end of November 2009.
          In addition, on November 4, 2009, we entered into a separate Unit Purchase Agreement with MRMC, under which MRMC will invest $20.0 million in cash in us in exchange for 715,308 newly-issued common units (the “Investment”). In connection with the Investment, our general partner will make a capital contribution to us of $0.4 million in order to maintain its 2% general partner interest in us. The closing of the Investment is subject to standard closing conditions, including the approval of the lenders under MRMC’s credit facility. Closing is anticipated prior to the end of November 2009. Proceeds from the Investment will be used by us to repay a portion of indebtedness under its credit facility.
          The foregoing descriptions of the Contribution Agreement, Tolling Agreement and Unit Purchase Agreement do not purport to be complete and are qualified in their entirety by reference to the full text of such Contribution Agreement, form of Tolling Agreement and Unit Purchase Agreement, copies of which are filed herewith as Exhibits 10.1, 10.2 and 10.3, respectively.
Item 6. Exhibits
          The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.

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SIGNATURES
          Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  Martin Midstream Partners L.P.
 
 
  By:   Martin Midstream GP LLC    
    It’s General Partner   
       
         
Date: November 4, 2009  By:   /s/ Ruben S. Martin    
    Ruben S. Martin   
    President and Chief Executive Officer   

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INDEX TO EXHIBITS
     
Exhibit    
Number   Exhibit Name
 
   
3.1
  Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
 
   
3.2
  First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 6, 2002 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
 
   
3.3
  Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 2, 2007, and incorporated herein by reference).
 
   
3.4
  Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of the Partnership, dated effective January 1, 2007 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed April 7, 2008, and incorporated herein by reference).
 
   
3.5
  Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
 
   
3.6
  Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
 
   
3.7
  Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
 
   
3.8
  Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 33-91706), filed July 1, 2002, and incorporated herein by reference).
 
   
3.9
  Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
 
   
3.10
  Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
 
   
4.1
  Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
 
   
4.2
  Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
 
   
10.1*
  Contribution Agreement, dated November 4, 2009, by and among Martin Operating Partnership L.P., Cross Oil Refining & Marketing, Inc., Martin Resource Management Corporation, and the Partnership.
 
   
10.2*
  Form of Tolling Agreement, to be entered into by and between Martin Operating Partnership L.P. and Cross Oil Refining & Marketing, Inc.
 
   
10.3*
  Unit Purchase Agreement, dated November 4, 2009, by and between the Partnership and Martin Resource Management Corporation.
 
   
31.1*
  Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2*
  Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1*
  Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
 
   
32.2*
  Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
 
*   Filed or furnished herewith

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