e10vq
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 JUNE 30, 2011
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM                      TO                     
Commission File number 000-51734
Calumet Specialty Products Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)
     
Delaware   37-1516132
(State or Other Jurisdiction of   (I.R.S. Employer
Incorporation or Organization)   Identification Number)
     
2780 Waterfront Parkway East Drive, Suite 200    
Indianapolis, Indiana   46214
(Address of principal executive officers)   (Zip code)
Registrant’s telephone number including area code (317) 328-5660
     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 Registration 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 þ 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o (Do not check if a smaller reporting company)   Smaller reporting company o
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
     At August 8, 2011, there were 39,779,778 common units outstanding.
 
 

 


 

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Six Months Ended June 30, 2011
Table of Contents
     
    Page
   
   
 
   
  5
 
   
  6
 
   
  7
 
   
  8
 
   
  9
 
   
  33
 
   
  51
 
   
  52
 
   
   
 
   
  53
 
   
  53
 
   
  56
 
   
  56
 
   
  56
 
   
  56
 
   
  57
 EX-10.1
 EX-10.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

2


Table of Contents

FORWARD-LOOKING STATEMENTS
     This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. The statements regarding (i) estimated capital expenditures as a result of the required audits or required operational changes included in our settlement with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental and regulatory liabilities, (ii) our anticipated levels of use of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes, (iii) the estimated purchase price, potential financing, closing timeline and all other discussion with respect to the Superior Acquisition (as defined in this Quarterly Report) and (iv) our ability to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, credit agreement covenants, contingencies and anticipated capital expenditures, as well as other matters discussed in this Quarterly Report that are not purely historical data, are forward-looking statements. These statements discuss future expectations or state other “forward-looking” information and involve risks and uncertainties. When considering these forward-looking statements, unitholders should keep in mind the risk factors and other cautionary statements included in this Quarterly Report, our Quarterly Report filed with the Securities and Exchange Commission (the “SEC”) on May 6, 2011 (our “2011 First Quarterly Report”) and in our Annual Report on Form 10-K filed with the SEC on February 22, 2011 (our “2010 Annual Report”). These risk factors and other factors noted throughout this Quarterly Report and in our 2010 Annual Report could cause our actual results to differ materially from those contained in any forward-looking statement. These factors include, but are not limited to:
    satisfaction of the conditions to the closing of the Superior Acquisition and the possibility that the Superior Acquisition will not close;
 
    timing of the completion of the Superior Acquisition;
 
    our ability to obtain additional financing to fund a portion of the Superior Acquisition and the final purchase price for the Superior Acquisition;
 
    the overall demand for specialty hydrocarbon products, fuels and other refined products;
 
    our ability to produce specialty products and fuels that meet our customers’ unique and precise specifications;
 
    the impact of fluctuations and rapid increases or decreases in crude oil and crack spread prices, including the resulting impact on our liquidity;
 
    the results of our hedging and other risk management activities;
 
    our ability to comply with financial covenants contained in our debt instruments;
 
    the availability of, and our ability to consummate, acquisition or combination opportunities and impact of any completed acquisitions;
 
    labor relations;
 
    our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;
 
    successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships;
 
    environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
 
    maintenance of our credit ratings and ability to receive open credit lines from our suppliers;
 
    demand for various grades of crude oil and resulting changes in pricing conditions;

3


Table of Contents

    fluctuations in refinery capacity;
 
    the effects of competition;
 
    continued creditworthiness of, and performance by, counterparties;
 
    the impact of current and future laws, rulings and governmental regulations, including guidance related to the Dodd-Frank Wall Street Reform and Consumer Protection Act;
 
    shortages or cost increases of power supplies, natural gas, materials or labor;
 
    hurricane or other weather interference with business operations;
 
    fluctuations in the debt and equity markets;
 
    accidents or other unscheduled shutdowns; and
 
    general economic, market or business conditions.
     Other factors described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Our forward looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward looking statement. Please also read Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part II Item 1A “Risk Factors” of this Quarterly Report.
     All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
     References in this Quarterly Report to “Calumet Specialty Products Partners, L.P.,” “the Company,” “we,” “our,” “us” or like terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References in this Quarterly Report to “our general partner” refer to Calumet GP, LLC, the general partner of the Company.

4


Table of Contents

PART I
Item 1. Financial Statements
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
                 
    June 30, 2011     December 31, 2010  
    (Unaudited)          
    (In thousands, except unit data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 55     $ 37  
Accounts receivable:
               
Trade
    203,749       157,185  
Other
    2,436       776  
 
           
 
    206,185       157,961  
Inventories
    258,665       147,110  
Prepaid expenses and other current assets
    3,656       1,909  
Deposits
    14,829       2,094  
 
           
Total current assets
    483,390       309,111  
Property, plant and equipment, net
    607,422       612,433  
Goodwill
    48,335       48,335  
Other intangible assets, net
    26,170       29,666  
Other noncurrent assets, net
    30,907       17,127  
 
           
Total assets
  $ 1,196,224     $ 1,016,672  
 
           
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities:
               
Accounts payable
  $ 236,169     $ 146,730  
Accounts payable — related party
    1,380       27,985  
Accrued salaries, wages and benefits
    7,975       7,559  
Taxes payable
    8,360       7,174  
Other current liabilities
    7,146       16,605  
Current portion of long-term debt
    942       4,844  
Derivative liabilities
    137,885       32,814  
 
           
Total current liabilities
    399,857       243,711  
Pension and postretirement benefit obligations
    8,426       9,168  
Other long-term liabilities
    1,069       1,083  
Long-term debt, less current portion
    428,440       364,431  
 
           
Total liabilities
    837,792       618,393  
Commitments and contingencies (Note 4)
               
Partners’ capital:
               
Limited partners’ interest (39,779,778 units and 35,279,778 units issued and outstanding at June 30, 2011 and December 31, 2010, respectively)
    462,458       407,773  
General partner’s interest
    19,302       18,125  
Accumulated other comprehensive loss
    (123,328 )     (27,619 )
 
           
Total partners’ capital
    358,432       398,279  
 
           
Total liabilities and partners’ capital
  $ 1,196,224     $ 1,016,672  
 
           
See accompanying notes to unaudited condensed consolidated financial statements.

5


Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
                                 
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (In thousands, except per unit data)  
Sales
  $ 733,770     $ 514,652     $ 1,339,010     $ 999,269  
Cost of sales
    683,205       465,033       1,241,581       917,974  
 
                       
Gross profit
    50,565       49,619       97,429       81,295  
 
                       
Operating costs and expenses:
                               
Selling, general and administrative
    10,467       8,321       20,995       15,491  
Transportation
    22,691       19,956       45,766       40,202  
Taxes other than income taxes
    1,203       1,098       2,563       2,123  
Insurance recoveries
    (7,910 )           (8,698 )      
Other
    703       480       1,238       808  
 
                       
Operating income
    23,411       19,764       35,565       22,671  
 
                       
Other income (expense):
                               
Interest expense
    (10,544 )     (7,277 )     (18,025 )     (14,711 )
Debt extinguishment costs
    (15,130 )           (15,130 )      
Realized loss on derivative instruments
    (2,370 )     (5,297 )     (1,984 )     (5,858 )
Unrealized loss on derivative instruments
    (3,124 )     (8,008 )     (3,541 )     (15,766 )
Other
    274       9       103       (50 )
 
                       
Total other expense
    (30,894 )     (20,573 )     (38,577 )     (36,385 )
 
                       
Net loss before income taxes
    (7,483 )     (809 )     (3,012 )     (13,714 )
Income tax expense
    168       98       438       260  
 
                       
Net loss
  $ (7,651 )   $ (907 )   $ (3,450 )   $ (13,974 )
 
                       
Allocation of net loss:
                               
Net loss
  $ (7,651 )   $ (907 )   $ (3,450 )   $ (13,974 )
Less:
                               
General partner’s interest in net loss
    (153 )     (18 )     (69 )     (279 )
Holders of incentive distribution rights
                       
 
                       
Net loss attributable to limited partners
  $ (7,498 )   $ (889 )   $ (3,381 )   $ (13,695 )
 
                       
Weighted average limited partner units outstanding — basic and diluted
    39,886       35,359       38,373       35,355  
 
                       
Limited partners’ interest basic and diluted net loss per unit
  $ (0.19 )   $ (0.03 )   $ (0.09 )   $ (0.39 )
 
                       
Cash distributions declared per limited partner unit
  $ 0.495     $ 0.455     $ 0.97     $ 0.91  
 
                       
See accompanying notes to unaudited condensed consolidated financial statements.

6


Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
                                         
    Accumulated Other     Partners’ Capital        
    Comprehensive     General     Limited Partners        
    Loss     Partner     Common     Subordinated     Total  
    (In thousands)  
Balance at December 31, 2010
  $ (27,619 )   $ 18,125     $ 390,843     $ 16,930     $ 398,279  
Distributions to partners
          (724 )     (29,393 )     (6,141 )     (36,258 )
Subordinated unit conversion
                10,789       (10,789 )      
Comprehensive loss:
                                       
Net loss
          (69 )     (3,381 )           (3,450 )
Cash flow hedge loss reclassified to net loss
    46,944                         46,944  
Change in fair value of cash flow hedges
    (142,775 )                       (142,775 )
Defined benefit pension and retiree health benefit plans
    122                         122  
 
                                     
Comprehensive loss
                                    (99,159 )
Proceeds from public equity offering, net
                92,290             92,290  
Contribution from Calumet GP, LLC
          1,970                   1,970  
Units repurchased for phantom unit grants
                (620 )           (620 )
Issuance of phantom units
                648             648  
Amortization of vested phantom units
                1,282             1,282  
 
                             
Balance at June 30, 2011
  $ (123,328 )   $ 19,302     $ 462,458     $     $ 358,432  
 
                             
See accompanying notes to unaudited condensed consolidated financial statements.

7


Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                 
    For the Six Months Ended  
    June 30,  
    2011     2010  
    (In thousands)  
Operating activities
               
Net loss
  $ (3,450 )   $ (13,974 )
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
               
Depreciation and amortization
    28,964       29,502  
Amortization of turnaround costs
    5,746       4,100  
Non-cash interest expense
    1,655       1,906  
Non-cash debt extinguishment costs
    14,401        
Provision for doubtful accounts
    255       (91 )
Unrealized loss on derivative instruments
    3,541       15,766  
Other non-cash activities
    338       1,114  
Changes in assets and liabilities:
               
Accounts receivable
    (48,479 )     (27,323 )
Inventories
    (111,555 )     (9,583 )
Prepaid expenses and other current assets
    (1,747 )     (1,324 )
Derivative activity
    5,699       1,443  
Turnaround costs
    (7,501 )     (8,548 )
Deposits
    (12,735 )     3,589  
Accounts payable
    62,834       48,584  
Accrued salaries, wages and benefits
    383       (603 )
Taxes payable
    1,186       166  
Other liabilities
    (9,473 )     (2,143 )
Pension and postretirement benefit obligations
    (620 )     (14 )
 
           
Net cash provided by (used in) operating activities
    (70,558 )     42,567  
Investing activities
               
Additions to property, plant and equipment
    (20,635 )     (17,017 )
Proceeds from insurance recoveries — equipment
    1,942        
Proceeds from sale of equipment
    130       121  
 
           
Net cash used in investing activities
    (18,563 )     (16,896 )
Financing activities
               
Proceeds from borrowings — revolving credit facility
    692,543       489,489  
Repayments of borrowings — revolving credit facility
    (675,285 )     (480,249 )
Repayments of borrowings — term loan credit facility
    (367,385 )     (1,925 )
Payments on capital lease obligations
    (534 )     (743 )
Proceeds from equity offering, net
    92,290       793  
Proceeds from senior notes offering
    400,000        
Debt issuance costs
    (17,582 )      
Contribution from Calumet GP, LLC
    1,970       18  
Common units repurchased for vested phantom unit grants
    (620 )     (248 )
Distributions to partners
    (36,258 )     (32,788 )
 
           
Net cash provided by (used in) financing activities
    89,139       (25,653 )
 
           
Net increase in cash and cash equivalents
    18       18  
Cash and cash equivalents at beginning of period
    37       49  
 
           
Cash and cash equivalents at end of period
  $ 55     $ 67  
 
           
Supplemental disclosure of cash flow information
               
Interest paid
  $ 11,830     $ 13,074  
Income taxes paid
  $ 116     $ 89  
 
           
See accompanying notes to unaudited condensed consolidated financial statements.

8


Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
1. Description of the Business
     Calumet Specialty Products Partners, L.P. (the “Company”) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of June 30, 2011, the Company had 39,779,778 common units and 811,832 general partner units outstanding. The number of common units outstanding includes 13,066,000 common units that converted from subordinated units on February 16, 2011. There are no longer any subordinated units outstanding. Refer to Note 9 for additional information. The general partner owns 2% of the Company while the remaining 98% is owned by limited partners. The Company is engaged in the production and marketing of crude oil-based specialty lubricating oils, white mineral oils, solvents, petrolatums, waxes and fuels. The Company owns facilities located in Shreveport, Louisiana (“Shreveport”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”) and Dickinson, Texas (“Dickinson”) and a terminal located in Burnham, Illinois (“Burnham”).
     The unaudited condensed consolidated financial statements of the Company as of June 30, 2011 and for the three and six months ended June 30, 2011 and 2010 included herein have been prepared, without audit, pursuant to the rules and regulations of the SEC. Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States of America (the “U.S.”) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three and six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2010 Annual Report. The Company issued these unaudited condensed consolidated financial statements by filing them with the SEC and has evaluated subsequent events up to the time of filing. Refer to Note 15 for additional information on these subsequent events.
2. New Accounting Pronouncements
     In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures About Fair Value Measurements” ( “ASU 2010-06”), which amends ASC No. 820, “Fair Value Measurements and Disclosures” to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. ASU 2010-06 also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. ASU 2010-06 is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for the requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a gross basis, which is effective for fiscal years (including interim periods) beginning after December 15, 2010. Effective January 1, 2010, the Company adopted ASU 2010-06 standard relating to disclosures about transfers in and out of Level 1 and 2 and the inputs and valuation techniques used to measure fair value. Effective January 1, 2011, the Company adopted ASU 2010-06 standard relating to the requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a gross basis. The adoption of ASU 2010-06 did not have a material impact on the Company’s financial position, results of operations or cash flows.
     In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. ASU 2011-04 is effective for the first reporting period (including interim periods) beginning after December 15, 2011. The Company is in process of evaluating the impact of the adoption of ASU 2011-04 on the Company’s financial statements.

9


Table of Contents

     In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income,” (“ASU 2011-05”) which amends current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income as part of the statement of partners’ capital. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for public companies during the interim and annual periods beginning after December 15, 2011 with early adoption permitted. The adoption of ASU 2011-05 will not have an impact on the Company’s consolidated financial position, results of operations or cash flows as it only requires a change in the format of the current presentation.
3. Inventories
     The cost of inventories is determined using the last-in, first-out (LIFO) method. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value.
     Inventories consist of the following:
                 
    June 30,     December 31,  
    2011     2010  
Raw materials
  $ 82,301     $ 12,885  
Work in process
    59,807       49,006  
Finished goods
    116,557       85,219  
 
           
 
  $ 258,665     $ 147,110  
 
           
     The replacement cost of these inventories, based on current market values, would have been $85,775 and $55,855 higher as of June 30, 2011 and December 31, 2010, respectively. For the three and six months ended June 30, 2011 and 2010, the Company recorded $0 and $883, respectively, of gains in cost of sales in the unaudited condensed consolidated statements of operations due to the liquidation of lower cost inventory layers.
4. Commitments and Contingencies
     From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxation and regulatory authorities, such as the LDEQ, the U.S. Environmental Protection Agency (“EPA”), the Internal Revenue Service and the Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.
Insurance Recoveries
     During the second quarter, the Company reached a final settlement of its insurance claim related to the failure of an environmental operating unit at its Shreveport refinery in 2010, resulting in a gain of $7,910 recorded in the second quarter of 2011. This claim related to both property damage and business interruption. Recoveries of $1,942 related to property damage have been reflected within investing activities (with the remainder in operating activities) in the unaudited condensed consolidated statement of cash flows.
Environmental
     The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations can impair the Company’s operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company can release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, and imposing substantial liabilities for pollution resulting from its operations. Certain environmental laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes, or other materials have been released or disposed.
     Failure to comply with environmental laws and regulations may result in the triggering of administrative, civil and criminal measures, including the assessment of monetary penalties, the imposition of remedial obligations and the issuance of injunctions

10


Table of Contents

limiting or prohibiting some or all of the Company’s operations. On occasion, the Company receives notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. For example, the LDEQ initiated enforcement actions in prior years for the following alleged violations: (i) a May 2001 notification received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations, as identified in the course of the Company’s Leak Detection and Repair program, and also for failure to submit various reports related to the facility’s air emissions; (ii) a December 2002 notification received by the Company’s Cotton Valley refinery from the LDEQ regarding alleged violations for excess emissions, as identified in the LDEQ’s file review of the Cotton Valley refinery; (iii) a December 2004 notification received by the Cotton Valley refinery from the LDEQ regarding alleged violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency; and (iv) an August 2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations, as identified by the LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emissions levels. On December 23, 2010, the Company entered into a settlement agreement with the LDEQ that consolidated the terms of its settlement of the aforementioned violations with the Company’s agreement to voluntarily participate in the LDEQ’s “Small Refinery and Single Site Refinery Initiative” described below.
     In 2010, the Company entered into a settlement agreement with the LDEQ regarding the Company’s voluntary participation in the LDEQ’s “Small Refinery and Single Site Refinery Initiative.” This state initiative is patterned after the EPA’s “National Petroleum Refinery Initiative,” which is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. The agreement, voluntarily entered into by the Company, requires the Company to make a $1,000 payment to the LDEQ and complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries. The Company estimates implementation of these requirements will result in approximately $11,000 to $15,000 of capital expenditures, expenditures related to additional personnel and environmental studies over the next five years. This agreement also fully settles the aforementioned alleged environmental and permit violations at the Company’s Shreveport, Cotton Valley and Princeton refineries and stipulates that no further civil penalties over alleged past violations at those refineries will be pursued by the LDEQ. The required investments are expected to include projects resulting in (i) nitrogen oxide and sulfur dioxide emission reductions from heaters and boilers and the application of New Source Performance Standards for sulfur recovery plants and flaring devices, (ii) control of incidents related to acid gas flaring, tail gas and hydrocarbon flaring, (iii) electrical reliability improvements to reduce flaring, (iv) flare refurbishment at the Shreveport refinery, (v) enhancement of the Benzene Waste National Emissions Standards for Hazardous Air Pollutants programs and the Leak Detection and Repair programs at the Company’s three Louisiana refineries and (vi) Title V audits and targeted audits of certain regulatory compliance programs. During negotiations with the LDEQ, the Company voluntarily initiated projects for certain of these requirements prior to the settlement with the LDEQ, and currently anticipates completion of these projects over the next five years. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the settlement to have a material adverse effect on the Company’s financial results or operations. Before the terms of this settlement agreement are deemed final, they will require the concurrence of the Louisiana Attorney General, which concurrence is anticipated to be granted during 2011.
     Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. The Company incurred approximately $261 of such capital expenditures at its Cotton Valley refinery during the first six months of 2011 and estimates that it will incur another $489 of capital expenditures at its Cotton Valley refinery during the remainder of 2011 in connection with these activities. The Company incurred approximately $541 of such capital expenditures at its Cotton Valley refinery during 2010.
     The Company is indemnified by Shell Oil Company, as successor to Pennzoil-Quaker State Company and Atlas Processing Company, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The indemnity is unlimited in amount and duration, but requires the Company to contribute up to $1,000 of the first $5,000 of indemnified costs for certain of the specified environmental liabilities.

11


Table of Contents

Health, Safety and Maintenance
     The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety, training and maintenance programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. The Company has implemented an internal program of inspection designed to monitor and enforce compliance with worker safety requirements as well as a quality system that meets the requirements of the ISO-9001-2008 Standard. The integrity of the Company’s ISO-9001-2008 Standard certification is maintained through surveillance audits by its registrar at regular intervals designed to ensure adherence to the standards.
     The Company has completed studies to assess the adequacy of its process safety management practices at its Shreveport refinery with respect to certain consensus codes and standards. The Company expects to incur between $5,000 and $8,000 of capital expenditures in total during 2011, 2012 and 2013 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards. The Company believes that its operations are in substantial compliance with OSHA and similar state laws.
     Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program, which is targeting all U.S. refineries for review. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the “Shreveport Citation”) to the Company as a result of the Shreveport inspection, which included a proposed civil penalty amount of $173. The Company contested the Shreveport Citation and associated penalty amount and agreed to a final penalty amount of $119 that was paid in January 2011. Similarly, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under OSHA’s National Emphasis Program in the first quarter of 2011. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $208. The Company has contested the Cotton Valley Citation and associated penalties and is currently in negotiations with OSHA to reach a settlement allowing an extended abatement period for a new refinery flare system study and for completion of facility siting modifications, including relocation and hardening of structures.
Standby Letters of Credit
     The Company has agreements with various financial institutions for standby letters of credit which have been issued to domestic vendors. As of June 30, 2011 and December 31, 2010, the Company had outstanding standby letters of credit of $179,473 and $90,725, respectively, under its senior secured revolving credit facility (the “revolving credit facility”), which was amended and restated on June 24, 2011. Refer to Note 5 for additional information. The maximum amount of letters of credit the Company can issue at June 30, 2011 is limited to its borrowing capacity under its revolving credit facility or $550,000, whichever is lower. At December 31, 2010, the limitation was the lower of the Company’s borrowing capacity or $375,000. As of June 30, 2011 and December 31, 2010, the Company had availability to issue letters of credit of $194,668 and $145,454, respectively, under its revolving credit facility. As discussed in Note 5, as of June 30, 2011 the outstanding standby letters of credit issued under the revolving credit facility included a $25,000 letter of credit to support a portion of its fuel products hedging program.

12


Table of Contents

5. Long-Term Debt
     Long-term debt consisted of the following:
                 
    June 30,     December 31,  
    2011     2010  
Borrowings under senior secured first lien term loan with third-party lenders, extinguished in 2011
  $     $ 367,385  
Borrowings under senior secured revolving credit agreement with third-party lenders, amended and restated in June 2011
          10,832  
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest at prime plus 1.25% (4.50% at June 30, 2011), interest payments monthly, borrowings due June 2016
    28,090        
Borrowings under 2019 Notes, interest at a fixed rate of 9.375% at June 30, 2011, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.95% for the quarter ended June 30, 2011
    400,000        
Capital lease obligations, at various interest rates, interest and principal payments quarterly through November 2013
    1,292       1,781  
Less unamortized discount on senior secured first lien term loan with third-party lenders, extinguished in 2011
          (10,723 )
 
           
Total long-term debt
    429,382       369,275  
Less current portion of long-term debt
    942       4,844  
 
           
 
  $ 428,440     $ 364,431  
 
           
     During the quarter ended June 30, 2011, the Company restructured the majority of its outstanding long-term debt. The Company issued $400,000 in aggregate principal amount 9 3/8% senior notes due May 1, 2019 (the “2019 Notes”), amended its then current senior secured revolving credit agreement to allow for the issuance of the 2019 Notes, and used the majority of the proceeds from the 2019 Notes to repay borrowings under, and subsequently extinguish, the senior secured first lien term loan. The Company also amended certain of its master derivative contracts and entered into a collateral sharing agreement with its hedging counterparties. Further, the Company amended and restated its revolving credit agreement to increase the credit facility from $375,000 to $550,000, as well as amend covenants and contractual terms. Each of these activities is discussed in further detail in the following paragraphs.
9 3/8% Senior Notes
     On April 21, 2011, the Company issued and sold the 2019 Notes in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers. The 2019 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $389,038 net of underwriters’ fees and expenses, which the Company used to repay in full borrowings outstanding under its existing senior secured first lien term loan, as well as all accrued interest and fees, and for general partnership purposes. Interest on the 2019 Notes will be paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are guaranteed on a senior unsecured basis by all of the Company’s operating subsidiaries and the Company’s future operating subsidiaries.
     At any time prior to May 1, 2014, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.
     On and after May 1, 2015, the Company may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:

13


Table of Contents

         
Year   Percentage  
2015
    104.688 %
2016
    102.344 %
2017 and at any time thereafter
    100.000 %
     Prior to May 1, 2015, the Company may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
     The indenture governing the 2019 Notes contains covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.
     Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.
     In connection with the notes offering on April 21, 2011, the Company’s then current senior secured revolving credit agreement was amended on April 15, 2011, to among other things, (i) permit the issuance of the 2019 Notes; (ii) upon consummation of the issuance of the 2019 Notes and the termination of the senior secured first lien credit agreement, release the revolving credit facility lenders’ second priority lien on the collateral securing the senior secured first lien credit facility; and (iii) change the interest rate pricing on the revolving credit facility.
Registration Rights Agreement
     On April 21, 2011, in connection with the issuance and sale of the 2019 Notes, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with the initial purchasers of the 2019 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC, so that holders of the 2019 Notes can offer to exchange the 2019 Notes issued in the April 2011 offering for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. The Company must use reasonable best efforts to cause the exchange offer registration statement to become effective by April 20, 2012 and remain effective until 180 days after the closing of the exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2019 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.
Senior Secured First Lien Credit Agreement
     The Company’s $435,000 senior secured first lien credit facility (the “term loan facility”) included a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. The Company extinguished this facility on April 21, 2011 in connection with the issuance and sale of the 2019 Notes, as further discussed above. The term loan bore interest at a rate equal to (i) with respect to a LIBOR Loan, the LIBOR Rate (as defined in the senior secured first lien credit agreement) plus 400 basis points and (ii) with respect to a Base Rate Loan, the Base Rate (as defined in the senior secured first lien credit agreement) plus 300 basis points. At December 31, 2010, the term loan bore interest at 4.29%. Please refer to “Amendments to Master Derivative Contracts” below for information on termination of the $50,000 prefunded letter of credit to support crack spread hedging.

14


Table of Contents

     Lenders under the term loan facility generally had a first priority lien on the Company’s fixed assets and a second priority lien on its cash, accounts receivable, inventory and certain other personal property. The term loan facility required quarterly principal payments of $963 through September 30, 2014, with the remaining balance due at maturity on January 3, 2015.
     On April 21, 2011, the Company used approximately $369,486 of the net proceeds from the issuance and sale of the 2019 Notes to repay in full its term loan, as well as accrued interest and fees, and terminated the entire senior secured first lien credit facility, including the term loan and $50,000 prefunded letter of credit. The Company did not incur any material early termination penalties in connection with its termination of the senior secured first lien credit facility. Further, in the second quarter of 2011 the Company recorded approximately $15,130 of extinguishment charges related to the writeoff of the unamortized debt issuance costs and the unamortized discount associated with the term loan.
Amendments to Master Derivative Contracts
     In connection with the termination of the term loan facility and the amendment of the senior secured revolving credit agreement, on April 21, 2011, the Company entered into amendments to certain of the Company’s master derivatives contracts (“Amendments”) to provide new credit support arrangements to secure the Company’s payment obligations under these contracts following the termination of the term loan facility and the amendment and restatement of the senior secured revolving credit agreement. Under the new credit support arrangements, the Company’s payment obligations under all of the Company’s master derivatives contracts for commodity hedging generally are secured by a first priority lien on the Company’s real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). The Company also issued to one counterparty a $25,000 standby letter of credit under the amended and restated senior secured revolving credit facility to replace a prefunded $50,000 letter of credit previously issued under the senior secured first lien credit facility. In the event that such counterparty’s exposure to the Company exceeds $150,000, the Company will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges. In addition to the $25,000 standby letter of credit posted to one counterparty, as of June 30, 2011 the Company had cash collateral posted with another counterparty of $11,900. The Company’s master derivatives contracts continue to impose a number of covenant limitations on the Company’s operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.
     In connection with the Amendments, on April 21, 2011, the Company entered into a collateral sharing agreement among each of its secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties, which governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by the Company to the secured hedging counterparties under their respective master derivatives contracts. Subject to certain conditions set forth in the collateral trust agreement, the Company has the ability to add secured hedging counterparties thereto.
Amended and Restated Senior Secured Revolving Credit Agreement
     On June 24, 2011, the Company entered into an amended and restated senior secured revolving credit agreement which increased the maximum availability of credit from $375,000 to $550,000, subject to borrowing base limitations, and includes a $300,000 incremental uncommitted expansion feature. The revolving credit agreement, which is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations, matures in June 2016 and currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. As of June 30, 2011, the margin was 125 basis points for prime and 250 basis points for LIBOR; however the margin fluctuates quarterly based on the Company’s average availability for additional borrowings under the revolving credit agreement in the preceding calendar quarter as follows:
                 
Quarterly Average   Margin on Base Rate     Margin on LIBOR  
Availability Percentage   Revolving Loans     Revolving Loans  
≥ 66%
    1.00 %     2.25 %
≥ 33% and < 66%
    1.25 %     2.50 %
< 33%
    1.50 %     2.75 %
     The borrowing capacity at June 30, 2011 under the revolving credit facility was $402,231. As of June 30, 2011, the Company borrowed $28,090, leaving $194,668 available for additional borrowings based on collateral and specified availability limitations. The lenders under the revolving credit agreement have a first priority lien on the Company’s cash, accounts receivable, inventory and certain other personal property.
     In addition, the amended and restated senior secured revolving credit agreement contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments;

15


Table of Contents

redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; and enter into a merger, consolidation or sale of assets. Further, the amended and restated senior secured revolving credit agreement contains one springing financial covenant which provides that only if the Company’s availability under the amended and restated senior secured revolving credit agreement falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $30,000, then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0.
     As of June 30, 2011, maturities of the Company’s long-term debt are as follows:
         
Year   Maturity  
2011
  $ 505  
2012
    551  
2013
    236  
2014
     
2015
     
Thereafter
    428,090  
 
     
Total
  $ 429,382  
 
     
6. Derivatives
     The Company utilizes derivative instruments to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas, the sale of fuel products and interest payments. The Company employs various hedging strategies, which are further discussed below. The Company does not hold or issue derivative instruments for trading purposes.
     The Company recognizes all derivative instruments at their fair values (see Note 8) as either assets or liabilities on the condensed consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The Company recorded the following derivative assets and liabilities at their fair values as of June 30, 2011 and December 31, 2010:
                                 
    Derivative Assets     Derivative Liabilities  
    June 30, 2011     December 31, 2010     June 30, 2011     December 31, 2010  
Derivative instruments designated as hedges:
                               
Fuel products segment:
                               
Crude oil swaps
  $     $     $ 126,090     $ 134,916  
Gasoline swaps
                (12,815 )     (14,149 )
Diesel swaps
                (75,698 )     (53,744 )
Jet fuel swaps
                (173,134 )     (96,556 )
Interest rate swaps:
                      (2,681 )
 
                       
Total derivative instruments designated as hedges
                (135,557 )     (32,214 )
 
                       
Derivative instruments not designated as hedges:
                               
Fuel products segment:
                               
Jet fuel crack spread collars (1)
                      20  
Specialty products segment: (2)
                               
Crude oil collars
                       
Natural gas swaps
                       
Crude oil swaps
                      662  
Interest rate swaps: (3)
                (2,328 )     (1,282 )
 
                       
Total derivative instruments not designated as hedges
                (2,328 )     (600 )
 
                       
Total derivative instruments
  $     $     $ (137,885 )   $ (32,814 )
 
                       
 
(1)   The Company entered into jet fuel crack spread collars, which do not qualify for hedge accounting, to economically hedge its exposure to changes in the jet fuel crack spread.
 
(2)   The Company enters into combinations of crude oil options and swaps and natural gas swaps to economically hedge its exposures to price risk related to these commodities in its specialty products segment. The Company has not designated these derivative instruments as hedges.

16


Table of Contents

(3)   The Company refinanced its long-term debt in April 2011 and, as a result, all of its interest rate swaps that were designated as a cash flow hedge for the interest payments under the previous debt agreement are no longer designated as hedges.
     To the extent a derivative instrument is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive loss, a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations. The Company accounts for certain derivatives hedging purchases of crude oil and natural gas, sales of gasoline, diesel and jet fuel and the payment of interest as cash flow hedges. The derivatives hedging sales and purchases are recorded to sales and cost of sales, respectively, in the unaudited condensed consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. The derivatives designated as hedging payments of interest are recorded in interest expense in the unaudited condensed consolidated statements of operations upon payment of interest. The Company assesses, both at inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
     For derivative instruments not designated as cash flow hedges and the portion of any cash flow hedge that is determined to be ineffective, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations.

17


Table of Contents

     The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital as of, and for the three months ended, June 30, 2011 and 2010 related to its derivative instruments that were designated as cash flow hedges:
                                                                 
                    Amount of (Gain)        
    Amount of Gain (Loss)     Loss Reclassified        
    Recognized in     from Accumulated        
    Accumulated Other     Other Comprehensive     Amount of Gain (Loss)  
    Comprehensive Loss     Loss into     Recognized in Net  
    on Derivatives     Net Loss     Loss on Derivatives  
    (Effective Portion)     (Effective Portion)     (Ineffective Portion)  
    Three Months Ended     Location of     Three Months Ended             Three Months Ended  
    June 30,     (Gain)     June 30,     Location of Gain     June 30,  
Type of Derivative   2011     2010     Loss     2011     2010     (Loss)     2011     2010  
Fuel products segment:
                                                               
Crude oil swaps
  $ (75,758 )   $ (95,836 )   Cost of sales   $ (39,333 )   $ (18,178 )   Unrealized/ Realized   $ (1,716 )   $ (3,500 )
Gasoline swaps
    1,374       25,491     Sales     12,576       5,874     Unrealized/ Realized     (878 )     (3,016 )
Diesel swaps
    27,530       41,122     Sales     25,074       10,002     Unrealized/ Realized     19       (43 )
Jet fuel swaps
    31,169       24,847     Sales     29,113           Unrealized/ Realized     (1,128 )     166  
Specialty products segment:
                                                               
Crude oil collars
              Cost of sales               Unrealized/ Realized            
Crude oil swaps
              Cost of sales               Unrealized/ Realized            
Natural gas swaps
              Cost of sales               Unrealized/ Realized            
Interest rate swaps:
    1,634       (449 )   Interest expense           511     Unrealized/ Realized            
 
                                                   
Total
  $ (14,051 )   $ (4,825 )           $ 27,430     $ (1,791 )           $ (3,703 )   $ (6,393 )
 
                                                   
     The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital for the three months ended June 30, 2011 and 2010 related to its derivative instruments not designated as cash flow hedges:
                                 
    Amount of Gain (Loss)     Amount of Gain (Loss)  
    Recognized in     Recognized  
    Realized Loss on     in Unrealized Loss on  
    Derivatives     Derivatives  
    Three Months Ended     Three Months Ended  
    June 30,     June 30,  
Type of Derivative   2011     2010     2011     2010  
Fuel products segment:
                               
Crude oil swaps
  $     $ (2,155 )   $     $ 5,366  
Gasoline swaps
          3,709             (7,161 )
Diesel swaps
          (325 )           325  
Jet fuel swaps
                       
Jet fuel collars
                      (162 )
Specialty products segment:
                               
Crude oil collars
          (2,188 )           (2,245 )
Crude oil swaps
          (1,686 )           (298 )
Natural gas swaps
                      (76 )
Interest rate swaps:
    (553 )     (205 )     (1,238 )     189  
 
                       
Total
  $ (553 )   $ (2,850 )   $ (1,238 )   $ (4,062 )
 
                       

18


Table of Contents

     The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital as of, and for the six months ended, June 30, 2011 and 2010 related to its derivative instruments that were designated as cash flow hedges:
                                                                 
                    Amount of (Gain)        
    Amount of Gain (Loss)     Loss Reclassified        
    Recognized in     from Accumulated        
    Accumulated Other     Other Comprehensive     Amount of Gain (Loss)  
    Comprehensive Loss     Loss into     Recognized in Net  
    on Derivatives     Net Loss     Loss on Derivatives  
    (Effective Portion)     (Effective Portion)     (Ineffective Portion)  
    Six Months Ended     Location of     Six Months Ended             Six Months Ended  
    June 30,     (Gain)     June 30,     Location of Gain     June 30,  
Type of Derivative   2011     2010     Loss     2011     2010     (Loss)     2011     2010  
Fuel products segment:
                                                               
Crude oil swaps
  $ 61,188     $ (79,355 )   Cost of sales   $ (58,434 )   $ (35,686 )   Unrealized/ Realized   $ (497 )   $ (9,973 )
Gasoline swaps
    (17,736 )     19,650     Sales     18,815       11,058     Unrealized/ Realized     (1,339 )     (4,551 )
Diesel swaps
    (68,792 )     32,556     Sales     43,187       15,810     Unrealized/ Realized     (538 )     (1,224 )
Jet fuel swaps
    (119,414 )     17,623     Sales     42,674           Unrealized/ Realized     (1,604 )     166  
Specialty products segment:
                                                               
Crude oil collars
              Cost of sales               Unrealized/ Realized            
Crude oil swaps
              Cost of sales               Unrealized/ Realized            
Natural gas swaps
              Cost of sales               Unrealized/ Realized            
Interest rate swaps:
    1,979       (1,398 )   Interest expense     702       1,297     Unrealized/ Realized            
 
                                                   
Total
  $ (142,775 )   $ (10,924 )           $ 46,944     $ (7,521 )           $ (3,978 )   $ (15,582 )
 
                                                   
     The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital for the six months ended June 30, 2011 and 2010 related to its derivative instruments not designated as cash flow hedges:
                                 
    Amount of Gain (Loss)     Amount of Gain (Loss)  
    Recognized in     Recognized  
    Realized Loss on     in Unrealized Loss  
    Derivatives     on Derivatives  
    Six Months Ended     Six Months Ended  
    June 30,     June 30,  
Type of Derivative   2011     2010     2011     2010  
Fuel products segment:
                               
Crude oil swaps
  $     $ (4,390 )   $     $ 6,938  
Gasoline swaps
          7,103             (9,203 )
Diesel swaps
          (650 )           650  
Jet fuel swaps
                       
Jet fuel collars
    (562 )           543       (288 )
Specialty products segment:
                               
Crude oil collars
          (2,959 )           (1,268 )
Crude oil swaps
    932       (1,662 )     (662 )     (247 )
Natural gas swaps
          (35 )           (76 )
Interest rate swaps:
    (752 )     (405 )     (1,046 )     450  
 
                       
Total
  $ (382 )   $ (2,998 )   $ (1,165 )   $ (3,044 )
 
                       
     The cash flow impact of the Company’s derivative activities is classified as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows.
     The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company executes all of its derivative instruments with large financial institutions that have ratings of at least A2 and A by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark to market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed upon thresholds in its contracts with these counterparties. No such collateral was held by the Company as of June 30, 2011 or December 31, 2010. The Company’s contracts with these counterparties allow for netting of derivative instrument positions executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits, on the Company’s condensed consolidated balance sheets and not netted against derivative assets or liabilities. As of June 30, 2011, the Company had provided its counterparties with $11,900 cash collateral above the $25,000 letter of credit provided to one

19


Table of Contents

counterparty to support crack spread hedging. As of December 31, 2010, the Company had provided its counterparties with no cash collateral or letters of credit above the $50,000 prefunded letter of credit then in effect and provided to one counterparty to support crack spread hedging. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.
     Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating was lowered below its current level by either Moody’s or S&P, such counterparties would have the right to reduce the applicable threshold to zero and demand full collateralization of the Company’s net liability position on outstanding derivative instruments. As of June 30, 2011 and December 31, 2010, there was a net liability of $753 and $388, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.
     The effective portion of the hedges classified in accumulated other comprehensive loss is $118,598 as of June 30, 2011, and absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2013 with balances being recognized as follows:
         
    Accumulated Other  
    Comprehensive  
Year   Loss  
2011
  $ 35,586  
2012
    80,630  
2013
    2,382  
 
     
Total
  $ 118,598  
 
     
     Based on fair values as of June 30, 2011, the Company expects to reclassify $79,666 of net losses on derivative instruments from accumulated other comprehensive loss to earnings during the next twelve months due to actual crude oil purchases, gasoline and diesel and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the date of settlements.
Crude Oil Swap and Collar Contracts — Specialty Products Segment
     The Company is exposed to fluctuations in the price of crude oil, its principal raw material. The Company utilizes combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty products segment. These derivatives may be designated as cash flow hedges of the future purchase of crude oil if they meet the hedge criteria. The Company’s general policy is to enter into crude oil derivative contracts that mitigate the Company’s exposure to price risk associated with crude oil purchases related to specialty products production (for up to 70% of expected purchases). While the Company’s policy generally requires that these positions be short term in nature and expire within three to nine months from execution, the Company may execute derivative contracts for up to two years forward, if a change in the risks supports lengthening the Company’s position. As of June 30, 2011, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.
     At December 31, 2010, the Company had the following crude oil derivatives related to crude oil purchases in its specialty products segment, none of which were designated as hedges.
                         
                    Average  
    Barrels             Swap  
Crude Oil Swap Contracts by Expiration Dates   Purchased     BPD     ($/Bbl)  
February 2011
    33,600       1,200     $ 83.10  
March 2011
    37,200       1,200       83.55  
 
                   
Totals
    70,800                  
Average price
                  $ 83.34  

20


Table of Contents

Crude Oil Swap Contracts — Fuel Products Segment
     The Company is exposed to fluctuations in the price of crude oil, its principal raw material. The Company utilizes swap contracts to manage crude oil price risk and volatility of cash flows in its fuel products segment. The Company’s policy is generally to enter into crude oil swap contracts for a period no greater than five years forward and for no more than 75% of crude oil purchases used in fuels production. At June 30, 2011, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
    Barrels             Swap  
Crude Oil Swap Contracts by Expiration Dates   Purchased     BPD     ($/Bbl)  
Third Quarter 2011
    1,610,000       17,500     $ 77.38  
Fourth Quarter 2011
    1,334,000       14,500       77.71  
Calendar Year 2012
    5,626,000       15,372       87.43  
Calendar Year 2013
    2,864,000       7,847       100.71  
 
                   
Totals
    11,434,000                  
Average price
                  $ 88.21  
     At December 31, 2010, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
    Barrels             Swap  
Crude Oil Swap Contracts by Expiration Dates   Purchased     BPD     ($/Bbl)  
First Quarter 2011
    1,215,000       13,500     $ 75.32  
Second Quarter 2011
    1,729,000       19,000       76.62  
Third Quarter 2011
    1,610,000       17,500       77.38  
Fourth Quarter 2011
    1,334,000       14,500       77.71  
Calendar Year 2012
    5,535,000       15,123       86.30  
 
                   
Totals
    11,423,000                  
Average price
                  $ 81.41  
Fuel Products Swap Contracts
     The Company is exposed to fluctuations in the prices of gasoline, diesel and jet fuel. The Company utilizes swap contracts to manage diesel, gasoline and jet fuel price risk and volatility of cash flows in its fuel products segment. The Company’s policy is generally to enter into diesel, jet fuel and gasoline swap contracts for a period no longer than five years forward and for no more than 75% of forecasted fuel sales.
Diesel Swap Contracts
     At June 30, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
                    Swap  
Diesel Swap Contracts by Expiration Dates   Barrels Sold     BPD     ($/Bbl)  
Third Quarter 2011
    552,000       6,000     $ 91.74  
Fourth Quarter 2011
    552,000       6,000       91.74  
Calendar Year 2012
    1,651,000       4,511       103.79  
Calendar Year 2013
    824,000       2,258       125.69  
 
                   
Totals
    3,579,000                  
Average price
                  $ 105.12  

21


Table of Contents

     At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
                    Swap  
Diesel Swap Contracts by Expiration Dates   Barrels Sold     BPD     ($/Bbl)  
First Quarter 2011
    630,000       7,000     $ 89.57  
Second Quarter 2011
    637,000       7,000       89.57  
Third Quarter 2011
    552,000       6,000       91.74  
Fourth Quarter 2011
    552,000       6,000       91.74  
Calendar Year 2012
    1,560,000       4,262       99.27  
 
                   
Totals
    3,931,000                  
Average price
                  $ 94.03  
Jet Fuel Swap Contracts
     At June 30, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
                    Swap  
Jet Fuel Swap Contracts by Expiration Dates   Barrels Sold     BPD     ($/Bbl)  
Third Quarter 2011
    920,000       10,000     $ 89.86  
Fourth Quarter 2011
    644,000       7,000       89.21  
Calendar Year 2012
    3,838,500       10,488       99.78  
Calendar Year 2013
    1,860,000       5,096       125.50  
 
                   
Totals
    7,262,500                  
Average price
                  $ 104.17  
     At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
                    Swap  
Jet Fuel Swap Contracts by Expiration Dates   Barrels Sold     BPD     ($/Bbl)  
First Quarter 2011
    405,000       4,500     $ 86.12  
Second Quarter 2011
    819,000       9,000       89.58  
Third Quarter 2011
    920,000       10,000       89.86  
Fourth Quarter 2011
    644,000       7,000       89.21  
Calendar Year 2012
    3,838,500       10,488       99.78  
 
                   
Totals
    6,626,500                  
Average price
                  $ 95.28  
Gasoline Swap Contracts
     At June 30, 2011, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
                    Swap  
Gasoline Swap Contracts by Expiration Dates   Barrels Sold     BPD     ($/Bbl)  
Third Quarter 2011
    138,000       1,500     $ 85.50  
Fourth Quarter 2011
    138,000       1,500       85.50  
Calendar Year 2012
    136,500       373       89.04  
Calendar Year 2013
    180,000       493       110.38  
 
                   
Totals
    592,500                  
Average price
                  $ 93.87  

22


Table of Contents

     At December 31, 2010, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as hedges.
                         
                    Average  
                    Swap  
Gasoline Swap Contracts by Expiration Dates   Barrels Sold     BPD     ($/Bbl)  
First Quarter 2011
    180,000       2,000     $ 81.84  
Second Quarter 2011
    273,000       3,000       82.66  
Third Quarter 2011
    138,000       1,500       85.50  
Fourth Quarter 2011
    138,000       1,500       85.50  
Calendar Year 2012
    136,500       373       89.04  
 
                   
Totals
    865,500                  
Average price
                  $ 84.40  
Jet Fuel Put Spread Contracts
     At June 30, 2011, the Company had the following jet fuel put options related to jet fuel crack spreads in its fuel products segment, none of which are designated as hedges.
                                 
                    Average     Average  
                    Sold Put     Bought Put  
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates   Barrels     BPD     ($/Bbl)     ($/Bbl)  
Fourth Quarter 2011
    184,000       2,000     $ 4.75     $ 7.00  
 
                         
Totals
    184,000                          
Average price
                  $ 4.75     $ 7.00  
     At December 31, 2010, the Company had the following jet fuel put options related to jet fuel crack spreads in its fuel products segment, none of which are designated as hedges.
                                 
                    Average     Average  
                    Sold Put     Bought Put  
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates   Barrels     BPD     ($/Bbl)     ($/Bbl)  
First Quarter 2011
    630,000       7,000     $ 4.00     $ 6.00  
Fourth Quarter 2011
    184,000       2,000       4.75       7.00  
 
                         
Totals
    814,000                          
Average price
                  $ 4.17     $ 6.23  
Natural Gas Swap Contracts
     Natural gas purchases comprise a significant component of the Company’s cost of sales; therefore, changes in the price of natural gas also significantly affect its profitability and cash flows. The Company utilizes swap contracts to manage natural gas price risk and volatility of cash flows. The Company’s policy is generally to enter into natural gas derivative contracts to hedge no more than 75% of its upcoming fall and winter months’ anticipated natural gas requirement for a period no greater than three years forward. At June 30, 2011 and December 31, 2010, the Company had no derivatives outstanding related to natural gas purchases.
Interest Rate Swap Contracts
     The Company’s profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of the Company’s interest rate risk management activities is to hedge its exposure to changes in interest rates. Historically, the Company’s policy has been to enter into interest rate swap agreements to hedge up to 75% of its interest rate risk related to variable rate debt. With the completion of its 2019 Notes offering, the Company does not expect to enter into additional hedges to fix its interest rates.
     During 2010, the Company entered into forward swap contracts to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan. The Company hedged the future interest payments related to $100,000 of the total outstanding term loan indebtedness for the period from February 15, 2011 to February 15, 2012 pursuant to these forward swap contracts. These swap contracts were designated as cash flow hedges of the future payments of interest with three-month LIBOR fixed at an average rate during the hedge period of 2.03%. Due to the repayment of the variable rate senior secured first lien term loan in April 2011 with proceeds from the issuance of the 2019 Notes, the interest rate swap contract was discontinued as a cash flow hedge

23


Table of Contents

for the future payment of interest. For the three and six months ended June 30, 2011, the Company reclassified approximately $1,435 into unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations.
     In 2009, the Company hedged the future interest payments related to $200,000 of its total outstanding term loan indebtedness for the period from February 15, 2010 to February 15, 2011. This swap contract was designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at an average rate during the hedge period of 0.94%. The cash flow hedge settled during the first quarter of 2011.
     In 2008, the Company entered into a forward swap contract to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan which closed January 3, 2008. The Company hedged the future interest payments related to $50,000 of the total outstanding term loan indebtedness in 2010, pursuant to this forward swap contract. This swap contract was designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at 3.66% per annum in 2010 and the first quarter of 2011. The cash flow hedge settled during the first quarter of 2011.
     In 2006, the Company entered into a forward swap contract to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan. Due to the repayment of $19,000 of the outstanding balance of the Company’s then existing term loan facility in August 2007 and subsequent refinancing of the remaining term loan balance, this swap contract was not designated as a cash flow hedge of the future payment of interest. The entire change in the fair value of this interest rate swap is recorded to unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations. In the first quarter of 2008, the Company fixed its unrealized loss on this interest rate swap derivative instrument by entering into an offsetting interest rate swap expiring December 2012, which is not designated as a cash flow hedge.
7. Fair Value of Financial Instruments
     The Company’s financial instruments which require fair value disclosure consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and indebtedness. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The fair value of the Company’s 2019 Notes was $412,000 at June 30, 2011, using quoted market prices. The fair value of the Company’s term loan was $355,445 at December 31, 2010, using quoted market prices. The carrying values of borrowings under the Company’s senior secured revolving credit facility were $28,090 and $10,832 at June 30, 2011 and December 31, 2010, respectively, and approximate their fair values.
8. Fair Value Measurements
     The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded, and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants, and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.
     As of June 30, 2011, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to crude oil, gasoline, diesel, jet fuel and interest rates and investments associated with the Company’s non-contributory defined benefit plan (“Pension Plan”).
     The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least A2 and A by Moody’s and S&P, respectively. To estimate the fair values of the Company’s derivative instruments, the Company uses the market approach. Under this approach, the fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, jet fuel and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the Company obtains this data through surveying its counterparties and

24


Table of Contents

performing various analytical tests to validate the data. The Company determines the fair value of its crude oil option contracts utilizing a standard option pricing model based on inputs that can be derived from information available in publicly quoted markets, or are quoted by counterparties to these contracts. In situations where the Company obtains inputs via quotes from its counterparties, it verifies the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. The Company also includes an adjustment for non-performance risk in the recognized measure of fair value of all of the Company’s derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When the Company is in a net asset position, it uses its counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. The Company uses its own peer group’s estimated CDS when it is in a net liability position. As a result of applying the applicable CDS, at June 30, 2011 and December 31, 2010, the Company’s liability was reduced by approximately $2,025 and $687, respectively. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for gasoline, jet fuel and diesel, the Company has categorized these derivative instruments as Level 3. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds.
     The Company’s investments associated with its Pension Plan primarily consist of (i) mutual funds that are publicly traded and (ii) a commingled fund. The mutual funds are publicly traded and market prices of the mutual funds are readily available; thus, these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of shares held by the Pension Plan at quarter end.
     The Company’s assets and liabilities measured at fair value at June 30, 2011 were as follows:
                                 
    Fair Value Measurements  
    Level 1     Level 2 (a)     Level 3     Total  
Assets:
                               
Cash and cash equivalents
  $ 55     $     $     $ 55  
Crude oil swaps
                126,090       126,090  
Gasoline swaps
                       
Diesel swaps
                       
Jet fuel swaps
                       
Crude oil options
                       
Jet fuel options
                       
Pension plan investments
    15,018       2,095             17,113  
 
                       
Total assets at fair value
  $ 15,073     $ 2,095     $ 126,090     $ 143,258  
 
                       
Liabilities:
                               
Crude oil swaps
  $     $     $     $  
Gasoline swaps
                (12,815 )     (12,815 )
Diesel swaps
                (75,698 )     (75,698 )
Jet fuel swaps
                (173,134 )     (173,134 )
Crude oil options
                       
Jet fuel options
                       
Interest rate swaps
                (2,328 )     (2,328 )
Pension plan investments
                       
 
                       
Total liabilities at fair value
  $     $     $ (263,975 )   $ (263,975 )
 
                       
 
(a)   Transferred from Level 1 to Level 2 in the first quarter of 2011 because of lack of observable market data in the underlying investments.

25


Table of Contents

     The Company’s financial assets and liabilities measured at fair value at December 31, 2010 were as follows:
                                 
    Fair Value Measurements  
    Level 1     Level 2     Level 3     Total  
Assets:
                               
Cash and cash equivalents
  $ 37     $     $     $ 37  
Crude oil swaps
                135,578       135,578  
Gasoline swaps
                       
Diesel swaps
                       
Jet fuel swaps
                       
Crude oil options
                       
Jet fuel options
                20       20  
Pension plan investments
    16,039                   16,039  
 
                       
Total assets at fair value
  $ 16,076     $     $ 135,598     $ 151,674  
 
                       
Liabilities:
                               
Crude oil swaps
  $     $     $     $  
Gasoline swaps
                (14,149 )     (14,149 )
Diesel swaps
                (53,744 )     (53,744 )
Jet fuel swaps
                (96,556 )     (96,556 )
Crude oil options
                       
Jet fuel options
                       
Interest rate swaps
                (3,963 )     (3,963 )
Pension plan investments
                       
 
                       
Total liabilities at fair value
  $     $     $ (168,412 )   $ (168,412 )
 
                       
     The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the six months ended June 30, 2011 and 2010:
                 
    Six Months Ended  
    June 30,  
    2011     2010  
Fair value at January 1,
  $ (32,814 )   $ 26,138  
Realized losses
    1,984       5,858  
Unrealized losses
    (3,541 )     (15,766 )
Change in fair value of cash flow hedges
    (142,775 )     (10,924 )
Settlements
    39,261       (14,823 )
Transfers in (out) of Level 3
           
 
           
Fair value at June 30,
  $ (137,885 )   $ (9,517 )
 
           
Total losses included in net loss attributable to changes in unrealized losses relating to financial assets and liabilities held as of June 30,
  $ (3,541 )   $ (15,766 )
 
           
     All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives, cost of sales for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in the unaudited condensed consolidated financial statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments are recorded in earnings immediately in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized loss on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 6 for further information on derivative instruments.
9. Partners’ Capital
     In February 2011, the Company satisfied the last of the earnings and distributions tests contained in its partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution paid on February 14, 2011. Two days following this quarterly distribution to unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.
     On February 24, 2011, the Company completed an equity offering of its common units in which it sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $92,290 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $3,915. The Company’s general

26


Table of Contents

partner contributed $1,970 to retain its 2% general partner interest.
10. Comprehensive Income (Loss)
     Comprehensive income (loss) for the Company includes the change in fair value of cash flow hedges and the minimum pension liability adjustment that have not been recognized in net loss. Comprehensive income (loss) for the three and six months ended June 30, 2011 and 2010 was as follows:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Net loss
  $ (7,651 )   $ (907 )   $ (3,450 )   $ (13,974 )
Cash flow hedge (gain) loss reclassified to net loss
    27,430       (1,791 )     46,944       (7,521 )
Change in fair value of cash flow hedges
    (14,051 )     (4,825 )     (142,775 )     (10,924 )
Defined benefit pension and retiree health benefit plans
    61       59       122       464  
 
                       
Total comprehensive income (loss)
  $ 5,789     $ (7,464 )   $ (99,159 )   $ (31,955 )
 
                       
11. Unit-Based Compensation and Distributions
     A summary of the Company’s nonvested phantom units as of June 30, 2011 and the changes during the six months ended June 30, 2011is presented below:
                 
            Weighted Average  
            Grant Date  
Nonvested Phantom Units   Grant     Fair Value  
Nonvested at December 31, 2010
    105,492     $ 17.68  
Granted
    47,927       21.31  
Vested
    (48,900 )     19.58  
Forfeited
           
 
           
Nonvested at June 30, 2011
    104,519     $ 18.46  
 
           
     For the three months ended June 30, 2011 and 2010, compensation expense of $653 and $145, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. For the six months ended June 30, 2011 and 2010, compensation expense of $1,282 and $292, respectively, was recognized in the unaudited condensed statements of operations related to vested phantom unit grants. As of June 30, 2011 and 2010, there was a total of $1,929 and $899, respectively, of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately three years.
     The Company’s distribution policy is as defined in its partnership agreement. For the three months ended June 30, 2011 and 2010, the Company made distributions of $19,311 and $16,391, respectively, to its partners. For the six months ended June 30, 2011 and 2010, the Company made distributions of $36,258 and $32,788, respectively, to its partners.
12. Employee Benefit Plans
     The components of net periodic pension and other post retirement benefits cost for the three months ended June 30, 2011 and 2010 were as follows:
                                 
    For the Three Months Ended June 30,  
    2011     2010  
            Other Post             Other Post  
    Pension     Retirement     Pension     Retirement  
    Benefits     Employee Benefits     Benefits     Employee Benefits  
Service cost
  $ 25     $     $ 21     $  
Interest cost
    333       4       334       6  
Expected return on assets
    (265 )           (258 )      
Amortization of net (gain) loss
    70             68        
Prior service cost
          (9 )           (9 )
 
                       
Net periodic benefit cost
  $ 163     $ (5 )   $ 165     $ (3 )
 
                       

27


Table of Contents

     The components of net periodic pension and other post retirement benefits cost for the six months ended June 30, 2011 and 2010 were as follows:
                                 
    For the Six Months Ended June 30,  
    2011     2010  
            Other Post             Other Post  
    Pension     Retirement     Pension     Retirement  
    Benefits     Employee Benefits     Benefits     Employee Benefits  
Service cost
  $ 49     $     $ 42     $  
Interest cost
    666       9       668       12  
Expected return on assets
    (529 )           (517 )      
Amortization of net (gain) loss
    140       (1 )     137       (1 )
Prior service cost
          (18 )           (18 )
 
                       
Net periodic benefit cost
  $ 326     $ (10 )   $ 330     $ (7 )
 
                       
     During the three months ended June 30, 2011 and 2010, the Company made contributions of $374 and $337, respectively, to its non-contributory defined benefit plan (the “Pension Plan”). During the six months ended June 30, 2011 and 2010, the Company made contributions of $936 and $337, respectively, and expects to make total contributions to its Pension Plan in 2011 of $1,685.
     The Company’s investments associated with its Pension Plan primarily consist of (i) mutual funds that are publicly traded and (ii) a commingled fund. The mutual funds are publicly traded and market prices of the mutual funds are readily available; thus, these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of the shares held by the Pension Plan at quarter end. The Company’s Pension Plan assets measured at fair value at June 30, 2011 and December 31, 2010 were as follows:
                                 
    June 30, 2011     December 31, 2010  
    Pension Benefits     Pension Benefits  
    Level 1     Level 2     Level 1     Level 2  
Cash
  $ 3,747     $     $ 347     $  
Equity
    4,208             7,784        
Foreign equities
    839             1,890        
Commingled fund
          2,095              
Fixed income
    6,224             6,018        
 
                       
 
  $ 15,018     $ 2,095     $ 16,039     $  
 
                       
13. Transactions with Related Parties
     On March 24, 2011, Calumet Lubricants Co., Limited Partnership (“Calumet Lubricants”), a wholly owned subsidiary of the Company, entered into Amendment No. 5 (the “Princeton Amendment”) to that certain Crude Oil Supply Agreement, effective as of April 30, 2008 (as amended since such date, the “Princeton Crude Oil Supply Agreement”), by and between Calumet Lubricants and Legacy Resources Co., L.P. (“Legacy”), under which Legacy supplies the Company’s Princeton refinery with all of the refinery’s crude oil requirements on a just-in-time basis. The Princeton Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Princeton Crude Oil Supply Agreement and shortened the termination notice period set forth in the Princeton Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Princeton Amendment, on March 24, 2011, Calumet Lubricants provided notice to Legacy that it was exercising its contractual rights under the Princeton Crude Oil Supply Agreement, as amended by the Princeton Amendment, to terminate the Princeton Crude Oil Supply Agreement on May 31, 2011. The Company did not incur any material early termination penalties in connection with its termination of the Princeton Crude Oil Supply Agreement.
     On March 24, 2011, Calumet Shreveport Fuels, LLC (“Calumet Shreveport Fuels”), a wholly owned subsidiary of the Company, entered into Amendment No. 5 (the “Shreveport Amendment”) to that certain Crude Oil Supply Agreement, effective as of September 1, 2009 (as amended since such date, the “Shreveport Crude Oil Supply Agreement”), by and between Calumet Shreveport Fuels and Legacy, under which Legacy supplies the Company’s Shreveport refinery with a portion of the refinery’s crude oil requirements on a just-in-time basis. The Shreveport Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Shreveport Crude Oil Supply Agreement and shortened the termination notice period set forth in the Shreveport Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Shreveport Amendment, on March 24, 2011, Calumet Shreveport Fuels provided notice to Legacy that it was exercising its contractual rights under the Shreveport Crude Oil Supply Agreement, as amended by the Shreveport Amendment, to terminate the Shreveport Crude Oil

28


Table of Contents

Supply Agreement on May 31, 2011. The Company did not incur any material early termination penalties in connection with its termination of the Shreveport Crude Oil Supply Agreement.
     With the termination of the agreements, the Company has one remaining crude oil supply agreement with Legacy, the Master Crude Oil Purchase and Sale Agreement, that was entered into on January 26, 2009. No crude oil is currently being purchased by the Company under this agreement.
     Legacy is owned in part by three of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and vice chairman, F. William Grube, and the Company’s president and chief operating officer, Jennifer G. Straumins. During the three and six months ended June 30, 2011, the Company had crude oil purchases of $48,036 and $241,287, respectively, from Legacy. Accounts payable to Legacy at June 30, 2011 were $95.
14. Segments and Related Information
a. Segment Reporting
     The Company has two reportable segments: Specialty Products and Fuel Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes and asphalt and other by-products. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The Fuel Products segment produces a variety of fuel and fuel-related products including gasoline, diesel and jet fuel. Because of the similar economic characteristics, certain operations have been aggregated for segment reporting purposes.
     The accounting policies of the segments are the same as those described in the summary of significant accounting policies except that the Company evaluates segment performance based on income (loss) from operations. The Company accounts for intersegment sales and transfers at cost plus a specified mark-up. Reportable segment information is as follows:

29


Table of Contents

                                         
    Specialty     Fuel     Combined             Consolidated  
Three Months Ended June 30, 2011   Products     Products     Segments     Eliminations     Total  
Sales:
                                       
External customers
  $ 466,414     $ 267,356     $ 733,770     $     $ 733,770  
Intersegment sales
    291,351       15,272       306,623       (306,623 )      
 
                             
Total sales
  $ 757,765     $ 282,628     $ 1,040,393     $ (306,623 )   $ 733,770  
 
                             
Depreciation and amortization
    17,722             17,722             17,722  
Operating income (loss)
    35,485       (12,074 )     23,411             23,411  
Reconciling items to net loss:
                                       
Interest expense
                                    (10,544 )
Debt extinguishment costs
                                    (15,130 )
Loss on derivative instruments
                                    (5,494 )
Other
                                    274  
Income tax expense
                                    (168 )
 
                                     
Net loss
                                  $ (7,651 )
 
                                     
Capital expenditures
  $ 14,069     $     $ 14,069     $     $ 14,069  
                                         
    Specialty     Fuel     Combined             Consolidated  
Three Months Ended June 30, 2010   Products     Products     Segments     Eliminations     Total  
Sales:
                                       
External customers
  $ 329,423     $ 185,229     $ 514,652     $     $ 514,652  
Intersegment sales
    188,654       16,427       205,081       (205,081 )      
 
                             
Total sales
  $ 518,077     $ 201,656     $ 719,733     $ (205,081 )   $ 514,652  
 
                             
Depreciation and amortization
    18,017             18,017             18,017  
Operating income
    19,472       292       19,764             19,764  
Reconciling items to net loss:
                                       
Interest expense
                                    (7,277 )
Loss on derivative instruments
                                    (13,305 )
Other
                                    9  
Income tax expense
                                    (98 )
 
                                     
Net loss
                                  $ (907 )
 
                                     
Capital expenditures
  $ 11,348     $     $ 11,348     $     $ 11,348  
                                         
    Specialty     Fuel     Combined             Consolidated  
Six Months Ended June 30, 2011   Products     Products     Segments     Eliminations     Total  
Sales:
                                       
External customers
  $ 863,516     $ 475,494     $ 1,339,010     $     $ 1,339,010  
Intersegment sales
    507,428       18,907       526,335       (526,335 )      
 
                             
Total sales
  $ 1,370,944     $ 494,401     $ 1,865,345     $ (526,335 )   $ 1,339,010  
 
                             
Depreciation and amortization
    36,365             36,365             36,365  
Operating income (loss)
    51,955       (16,390 )     35,565             35,565  
Reconciling items to net loss:
                                       
Interest expense
                                    (18,025 )
Debt extinguishment costs
                                    (15,130 )
Loss on derivative instruments
                                    (5,525 )
Other
                                    103  
Income tax expense
                                    (438 )
 
                                     
Net loss
                                  $ (3,450 )
 
                                     
Capital expenditures
  $ 20,635     $     $ 20,635     $     $ 20,635  

30


Table of Contents

                                         
    Specialty     Fuel     Combined             Consolidated  
Six Months Ended June 30, 2010   Products     Products     Segments     Eliminations     Total  
Sales:
                                       
External customers
  $ 634,899     $ 364,370     $ 999,269     $     $ 999,269  
Intersegment sales
    363,261       27,217       390,478       (390,478 )      
 
                             
Total sales
  $ 998,160     $ 391,587     $ 1,389,747     $ (390,478 )   $ 999,269  
 
                             
Depreciation and amortization
    35,508             35,508             35,508  
Operating income
    16,835       5,836       22,671             22,671  
Reconciling items to net loss:
                                       
Interest expense
                                    (14,711 )
Loss on derivative instruments
                                    (21,624 )
Other
                                    (50 )
Income tax expense
                                    (260 )
 
                                     
Net loss
                                  $ (13,974 )
 
                                     
Capital expenditures
  $ 17,017     $     $ 17,017     $     $ 17,017  
                 
    June 30, 2011     December 31, 2010  
Segment assets:
               
Specialty products
  $ 1,058,981     $ 962,850  
Fuel products
    137,243       53,822  
 
           
Total assets
  $ 1,196,224     $ 1,016,672  
 
           
b. Geographic Information
     International sales accounted for less than 10% of consolidated sales in each of the three months and six months ended June 30, 2011 and 2010. All of the Company’s long-lived assets are domestically located.
c. Product Information
     The Company offers products primarily in five general categories consisting of lubricating oils, solvents, waxes, fuels and asphalt and by-products. Fuel products primarily consist of gasoline, diesel, jet fuel and by-products. The following table sets forth the major product category sales:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     2011     2010  
Specialty products:
                               
Lubricating oils
  $ 246,448     $ 176,354     $ 455,499     $ 340,402  
Solvents
    135,642       95,777       253,978       183,631  
Waxes
    33,874       28,362       68,181       54,608  
Fuels
    592       2,232       1,423       3,971  
Asphalt and other by-products
    49,858       26,698       84,435       52,287  
 
                       
Total
  $ 466,414     $ 329,423     $ 863,516     $ 634,899  
 
                       
Fuel products:
                               
Gasoline
    127,452       76,287       223,233       152,170  
Diesel
    91,611       77,396       173,764       141,626  
Jet fuel
    40,686       27,816       67,460       65,380  
By-products
    7,607       3,730       11,037       5,194  
 
                       
Total
  $ 267,356     $ 185,229     $ 475,494     $ 364,370  
 
                       
Consolidated sales
  $ 733,770     $ 514,652     $ 1,339,010     $ 999,269  
 
                       
d. Major Customers
     During the three and six months ended June 30, 2011 and 2010, the Company had no customer that represented 10% or greater of consolidated sales.

31


Table of Contents

15. Subsequent Events
     On July 22, 2011, the Company declared a quarterly cash distribution of $0.495 per unit on all outstanding units, or approximately $20,124 in aggregate, for the quarter ended June 30, 2011. The distribution will be paid on August 12, 2011 to unitholders of record as of the close of business on August 2, 2011. This quarterly distribution of $0.495 per unit equates to $1.98 per unit, or approximately $80,496 in aggregate on an annualized basis.
     The fair value of the Company’s derivatives decreased by approximately $46,000 subsequent to June 30, 2011 to a liability of approximately $184,000. As of August 8, 2011, the Company had $31,300 in cash margin posted with one counterparty to support crack spread hedging. The fair value of the Company’s long-term debt, excluding capital leases, has not changed materially subsequent to June 30, 2011.
     On July 25, 2011, the Company entered into a definitive asset purchase agreement with Murphy Oil Corporation (“Murphy Oil”), pursuant to which the Company will acquire (the “Superior Acquisition”):
    Murphy Oil’s refinery located in Superior, Wisconsin (the “Superior Refinery”) and associated inventories;
 
    the Superior Refinery’s wholesale marketing business and related assets, including certain owned or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin, Duluth and Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah and associated inventories and logistics assets located at each of the foregoing facilities; and
 
    Murphy Oil’s “SPUR” branded gasoline wholesale business and related assets.
     The Superior Acquisition is expected to close by the end of the third quarter of 2011, subject to customary closing conditions and regulatory approvals.
     The Superior Refinery produces gasoline, distillate, asphalt and specialty petroleum products that are marketed in the Midwest region of the United States, Canada and the surrounding border states. The Superior wholesale business transports products produced at the Superior Refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through its own leased and owned product terminals located in Superior and Rhinelander, Wisconsin, Duluth, Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah. The Superior Wholesale Business also sells gasoline wholesale to SPUR branded gas stations, which are owned and operated by independent franchisees.
     The aggregate purchase price for the acquired business is $214,000, plus the market value of the acquired business’ hydrocarbon inventories at closing and the reimbursement of certain capital expenditures to be incurred at the Superior Refinery during the period from the execution of the Purchase Agreement to the closing of the Superior Acquisition (the “Interim Period”). The purchase price is also subject to customary purchase price adjustments. The Company intends to finance the Superior Acquisition primarily through a combination of equity and long-term debt financing and through borrowings under its revolving credit facility. The Company’s obligation to consummate the Superior Acquisition is not conditioned upon the receipt of financing.

32


Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The historical consolidated financial statements included in this Quarterly Report reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet,” the “Company,” “we,” “our,” “us”). The following discussion analyzes the financial condition and results of operations of Calumet for the three and six months ended June 30, 2011 and 2010. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Calumet in conjunction with our 2010 Annual Report and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.
Overview
     We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We own plants located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport, Louisiana, Karns City, Pennsylvania and a terminal located in Burnham, Illinois. Our business is organized into two segments: specialty products and fuel products. In our specialty products segment, we process crude oil and other feedstocks into a wide variety of customized lubricating oils, white mineral oils, solvents, petrolatums and waxes. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for basic industrial, consumer and automotive goods. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products, including gasoline, diesel and jet fuel. In connection with our production of specialty products and fuel products, we also produce asphalt and a limited number of other by-products.
Second Quarter 2011 Update
     For the three months ended June 30, 2011 and 2010, 51.5% and 51.8%, respectively, of our sales volume and 115.3% and 93.5%, respectively, of our gross profit was generated from our specialty products segment while, for the same periods, 48.5% and 48.2%, respectively, of our sales volume and (15.3)% and 6.5%, respectively, of our gross profit was generated from our fuel products segment.
     We noted continued improvement in our specialty products segment during the second quarter of 2011. The trend of increased demand for our specialty products has continued, with specialty products segment sales volume increasing 12.8% for the quarter ended June 30, 2011 compared to the same period in 2010. Specialty products segment generated a gross profit margin of 12.5% in the second quarter of 2011, as compared to a gross profit margin of 14.1% for the same period in the prior year.
     While fuel products refining margins significantly strengthened during the second quarter, our fuel products segment did not fully realize the impact of higher market crack spreads due primarily to lower than expected run rates caused by the approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding during this period, resulting in minimal unhedged fuel products barrels. In addition, we recorded realized derivative losses of $27.4 million during the second quarter in our fuel products segment. We expect to benefit more significantly going forward from the higher market crack spread environment as our overall production rates have increased subsequent to the restart of the pipeline in late June 2011. In addition, during this period of higher crack spreads we have entered into additional crack spread hedges, hedging crack spreads on 7,847 barrels per day in calendar year 2013 at an average of $23.90 per barrel, an $11.42 per barrel increase over our average hedged crack spreads in calendar year 2011.
     Our second quarter 2011 total production increased by 13.2% quarter over quarter, due primarily to our decision to increase production run rates at our Shreveport refinery to take advantage of better fuel refining crack spreads in the second quarter of 2011, the impact of the failure of an environmental operating unit at our Shreveport refinery in the first quarter of 2010 that was not replaced until after the second quarter of 2010 and a planned turnaround at our Shreveport refinery in the second quarter of 2010, with no such events in 2011, partially offset by the impact of the approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period. Production levels at our other facilities, which focus primarily on the production of specialty products, also increased quarter over quarter to take advantage of higher specialty products demand.
     We used $70.6 million in cash flows from operating activities during the second quarter of 2011 primarily due to increased crude inventory levels as a result of terminating certain just-in-time inventory supply arrangements with a related party, Legacy, effective May 31, 2011, increased working capital requirements resulting from increased run rates at our Shreveport refinery and higher commodity prices in general. We plan to continue focusing our efforts on generating positive cash flows from operations which we expect will be used to (i) improve our liquidity position, (ii) pay quarterly distributions to our unitholders, (iii) service our debt obligations and (iv) provide funding for general partnership purposes.

33


Table of Contents

     During the second quarter of 2011, we restructured the majority of our outstanding long-term debt. We issued $400.0 million in aggregate principal amount of our 9 3/8% senior notes due 2019 (the “2019 Notes”) in a private placement and used the majority of the proceeds to repay borrowings under, and subsequently extinguish, our $435.0 million term loan facility, consisting of a $385.0 million term loan and a prefunded $50 million letter of credit to support crack spread hedging. We also amended our master derivative contracts with various hedging counterparties and entered into a collateral sharing agreement with these counterparties to continue to support our fuel products hedging program. Further, we amended and restated our revolving credit agreement to increase the credit facility from $375.0 million to $550.0 million, as well as amend its covenants and terms.
Superior Refinery Purchase Agreement
     On July 25, 2011, we entered into a definitive asset purchase agreement with Murphy Oil Corporation (“Murphy Oil”), pursuant to which we will acquire (the “Superior Acquisition”):
    Murphy Oil’s refinery located in Superior, Wisconsin (the “Superior Refinery”) and associated inventories;
 
    the Superior Refinery’s wholesale marketing business and related assets, including certain owned or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin, Duluth and Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah and associated inventories and logistics assets located at each of the foregoing facilities; and
 
    Murphy Oil’s “SPUR” branded gasoline wholesale business and related assets.
     In this Quarterly Report on Form 10-Q, the Superior Refinery, the wholesale business and the “SPUR” business are collectively referred to as the “Acquired Business.” The Superior Acquisition is expected to close by the end of the third quarter of 2011, subject to customary closing conditions and regulatory approvals.
     The Superior Refinery produces gasoline, distillate, asphalt and specialty petroleum products that are marketed in the Midwest region of the United States, Canada and the surrounding border states. The Superior Refinery has crude oil throughput capacity of approximately 45,000 barrels per day. The Superior wholesale business transports products produced at the Superior Refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through its own leased and owned product terminals located in Superior and Rhinelander, Wisconsin, Duluth, Crookston and Proctor, Minnesota, Grand Island, Nebraska and Toole, Utah. The Superior Wholesale Business also sells gasoline wholesale to SPUR branded gas stations, which are owned and operated by independent franchisees.
     The aggregate purchase price for the Acquired Business is $214.0 million, plus the market value of the Acquired Business’ hydrocarbon inventories at closing and the reimbursement of certain capital expenditures to be incurred at the Superior Refinery during the period from the execution of the Purchase Agreement to the closing of the Superior Acquisition (the “Interim Period”). The estimated market value of the hydrocarbon inventories of the Acquired Business as of June 30, 2011 was approximately $260.0 million and the projected capital expenditures at the Superior Refinery to be reimbursed by us for the Interim Period are approximately $4.0 million. The purchase price is also subject to customary purchase price adjustments. We intend to finance the Superior Acquisition primarily through a combination of equity and long-term debt financing and through borrowings under our revolving credit facility. Our obligation to consummate the Superior Acquisition is not conditioned upon the receipt of financing.
Key Performance Measures
     Our sales and net income are principally affected by the price of crude oil, demand for specialty and fuel products, prevailing crack spreads for fuel products, the price of natural gas used as fuel in our operations and our results from derivative instrument activities.
     Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our control. We monitor these risks and enter into financial derivatives designed to mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash

34


Table of Contents

distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.” As of June 30, 2011, we have hedged approximately 11.4 million barrels of fuel products through December 2013 at an average refining margin of $15.73 per barrel with average refining margins ranging from a low of $12.16 per barrel in 2011 to a high of $23.90 per barrel in 2013. Please refer to Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” and Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Existing Commodity Derivative Instruments” for detailed information regarding our derivative instruments.
     Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:
    sales volumes;
 
    production yields; and
 
    specialty products and fuel products gross profit.
     Sales volumes. We view the volumes of specialty products and fuel products sold as an important measure of our ability to effectively utilize our refining assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.
     Production yields. In order to maximize our gross profit and minimize lower margin by-products, we seek the optimal product mix for each barrel of crude oil we refine, which we refer to as production yield.
     Specialty products and fuel products gross profit. Specialty products and fuel products gross profit are important measures of our ability to maximize the profitability of our specialty products and fuel products segments. We define specialty products and fuel products gross profit as sales less the cost of crude oil and other feedstocks and other production-related expenses, the most significant portion of which includes labor, plant fuel, utilities, contract services, maintenance, depreciation and processing materials. We use specialty products and fuel products gross profit as indicators of our ability to manage our business during periods of crude oil and natural gas price fluctuations, as the prices of our specialty products and fuel products generally do not change immediately with changes in the price of crude oil and natural gas. The increase in selling prices typically lags behind the rising costs of crude oil feedstocks for specialty products. Other than plant fuel, production-related expenses generally remain stable across broad ranges of throughput volumes, but can fluctuate depending on maintenance activities performed during a specific period.
     Our fuel products segment gross profit may differ from a standard U.S. Gulf Coast 2/1/1 or 3/2/1 market crack spread due to many factors, including our fuel products mix as shown in our production table being different than the ratios used to calculate such market crack spreads, the allocation of by-product (primarily asphalt) losses at the Shreveport refinery to the fuel products segment, operating costs including fixed costs, derivative activity to hedge our fuel products segment revenues and cost of crude oil reflected in gross profit and our local market pricing differential in Shreveport, Louisiana as compared to U.S. Gulf Coast postings.
     In addition to the foregoing measures, we also monitor our selling, general and administrative expenditures, substantially all of which are incurred through our general partner.

35


Table of Contents

Results of Operations for the Three and Six Months Ended June 30, 2011 and 2010
     Production Volume. The following table sets forth information about our combined operations. Facility production volume differs from sales volume due to changes in inventory.
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     % Change     2011     2010     % Change  
            (In bpd)             (In bpd)  
Total sales volume (1)
    59,648       52,626       13.3 %     56,619       52,166       8.5 %
Total feedstock runs (2)
    61,853       57,169       8.2 %     58,986       52,774       11.8 %
Facility production: (3)
                                               
Specialty products:
                                               
Lubricating oils
    14,141       13,783       2.6 %     13,961       12,538       11.3 %
Solvents
    11,051       8,904       24.1 %     10,592       8,490       24.8 %
Waxes
    1,204       1,152       4.5 %     1,133       1,081       4.8 %
Fuels
    435       978       (55.5 )%     533       1,063       (49.9 )%
Asphalt and other by-products
    8,961       6,075       47.5 %     8,495       5,921       43.5 %
 
                                   
Total
    35,792       30,892       15.9 %     34,714       29,093       19.3 %
 
                                   
Fuel products:
                                               
Gasoline
    10,266       8,710       17.9 %     9,619       8,743       10.0 %
Diesel
    11,424       10,875       5.0 %     11,095       9,936       11.7 %
Jet fuel
    5,429       5,326       1.9 %     4,303       5,290       (18.7 )%
By-products
    1,065       722       47.5 %     812       511       58.9 %
 
                                   
Total
    28,184       25,633       10.0 %     25,829       24,480       5.5 %
 
                                   
Total facility production (3)
    63,976       56,525       13.2 %     60,543       53,573       13.0 %
 
                                   
 
(1)   Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements and sales of inventories.
 
(2)   Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. The increase in the total feedstock runs for the three months ended June 30, 2011 compared to the same quarter in 2010 is due primarily to the decision to increase crude oil run rates at our facilities because of favorable economics of running additional barrels, the failure of an environmental operating unit at our Shreveport refinery in 2010 and a planned turnaround at our Shreveport refinery in April 2010 partially offset by the impact of the approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period. Additionally, the increase in feedstock runs for the for the six months ended June 30, 2011 compared to the same period in 2010 is due primarily to the operational reasons discussed above further offset by a planned turnaround at the Shreveport refinery in the first quarter of 2011.
 
(3)   Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities, pursuant to supply and/or processing agreements, including such agreements with LyondellBasell. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of finished products and volume loss. The increase in production in the three and six months ended June 30, 2011 compared to the same periods in 2010 is due primarily to higher throughput rates at our Shreveport and Cotton Valley refineries period over period as discussed above in footnote 2 of this table.

36


Table of Contents

     The following table reflects our consolidated results of operations and includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated in accordance with GAAP, please read “—Non-GAAP Financial Measures.”
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     2011     2010  
    (In thousands)     (In thousands)  
Sales
  $ 733,770     $ 514,652     $ 1,339,010     $ 999,269  
Cost of sales
    683,205       465,033       1,241,581       917,974  
 
                       
Gross profit
    50,565       49,619       97,429       81,295  
 
                       
 
                               
Operating costs and expenses:
                               
Selling, general and administrative
    10,467       8,321       20,995       15,491  
Transportation
    22,691       19,956       45,766       40,202  
Taxes other than income taxes
    1,203       1,098       2,563       2,123  
Insurance recoveries
    (7,910 )           (8,698 )      
Other
    703       480       1,238       808  
 
                       
Operating income
    23,411       19,764       35,565       22,671  
 
                       
Other income (expense):
                               
Interest expense
    (10,544 )     (7,277 )     (18,025 )     (14,711 )
Debt extinguishment costs
    (15,130 )           (15,130 )      
Realized loss on derivative instruments
    (2,370 )     (5,297 )     (1,984 )     (5,858 )
Unrealized loss on derivative instruments
    (3,124 )     (8,008 )     (3,541 )     (15,766 )
Other
    274       9       103       (50 )
 
                       
Total other expense
    (30,894 )     (20,573 )     (38,577 )     (36,385 )
 
                       
Net loss before income taxes
    (7,483 )     (809 )     (3,012 )     (13,714 )
Income tax expense
    168       98       438       260  
 
                       
Net loss
  $ (7,651 )   $ (907 )   $ (3,450 )   $ (13,974 )
 
                       
Adjusted EBITDA
  $ 40,841     $ 32,136     $ 75,494     $ 52,259  
 
                       
Distributable Cash Flow
  $ 25,367     $ 7,219     $ 43,589     $ 14,304  
 
                       
Non-GAAP Financial Measures
     We include in this Quarterly Report the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow, and provide reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.
     EBITDA, Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
    the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 
    the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
 
    our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
 
    the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
     We believe that these non-GAAP measures are useful to analysts and investors as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully trend and analyze the performance of our core cash operations.
     We define EBITDA for any period as net income plus interest expense (including debt issuance and extinguishment costs), taxes and depreciation and amortization. We define Adjusted EBITDA for any period as: (1) net income plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income; (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income; (g) debt refinancing fees, premiums and penalties and (h) all

37


Table of Contents

extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income for a prior period, but represent a cash item in the current period.
     We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement capital expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash interest expense) and income tax expense. Distributable Cash Flow is used by us and our investors to analyze our ability to pay distributions.
     The definitions of Adjusted EBITDA and Distributable Cash that are presented in this Quarterly Report have been updated to reflect the calculation of “Consolidated Cash Flow” contained in the indenture governing our 2019 Notes. We are required to report Consolidated Cash Flow to the holders of our 2019 Notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these measures are used by them to determine our compliance with certain covenants governing those debt instruments. Adjusted EBITDA and Distributable Cash Flow that are presented in this Quarterly Report for prior periods have been updated to reflect the use of the new calculations. Please refer to “Liquidity and Capital Resources — Debt and Credit Facilities” within this item for additional details regarding the covenants governing our debt instruments.
     EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP. In evaluating our performance as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the limitations of these measurements. EBITDA, Adjusted EBITDA and Distributable Cash Flow do not reflect our obligations for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only three of the measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the same manner. The following table presents a reconciliation of both net income (loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

38


Table of Contents

                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (In thousands)     (In thousands)  
Reconciliation of Net Loss to EBITDA and Adjusted EBITDA and Distributable Cash Flow:
                               
Net loss
  $ (7,651 )   $ (907 )   $ (3,450 )   $ (13,974 )
Add:
                               
Interest expense
    10,544       7,277       18,025       14,711  
Debt extinguishment costs
    15,130             15,130        
Depreciation and amortization
    14,532       15,098       28,964       29,502  
Income tax expense
    168       98       438       260  
 
                       
EBITDA
  $ 32,723     $ 21,566     $ 59,107     $ 30,499  
 
                       
Add:
                               
Unrealized loss on derivatives
  $ 3,124     $ 8,008     $ 3,541     $ 15,766  
Realized gain on derivatives, not included in net loss
    1,394       372       5,137       1,442  
Amortization of turnaround costs
    2,533       1,960       5,746       4,100  
Non-cash equity based compensation
    1,067       230       1,963       452  
 
                       
Adjusted EBITDA
  $ 40,841     $ 32,136     $ 75,494     $ 52,259  
 
                       
Less:
                               
Replacement capital expenditures (1)
    3,505       10,893       7,596       16,342  
Cash interest expense (2)
    9,887       6,318       16,370       12,805  
Turnaround costs
    1,914       7,608       7,501       8,548  
Income tax expense
    168       98       438       260  
 
                       
Distributable Cash Flow
  $ 25,367     $ 7,219     $ 43,589     $ 14,304  
 
                       
 
(1)   Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs.
 
(2)   Represents consolidated interest expense less non-cash interest expense.

39


Table of Contents

                 
    Six Months Ended  
    June 30,  
    2011     2010  
    (In thousands)  
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities:
               
Distributable Cash Flow
  $ 43,589     $ 14,304  
Add:
               
Replacement capital expenditures (1)
    7,596       16,342  
Turnaround costs
    7,501       8,548  
Cash interest expense (2)
    16,370       12,805  
Income tax expense
    438       260  
 
           
Adjusted EBITDA
  $ 75,494     $ 52,259  
 
           
Less:
               
Unrealized loss on derivative instruments
    3,541       15,766  
Realized gains on derivatives, not included in net loss
    5,137       1,442  
Non-cash equity based compensation
    1,963       452  
Amortization of turnaround costs
    5,746       4,100  
 
           
EBITDA
  $ 59,107     $ 30,499  
 
           
Add:
               
Unrealized loss on derivative instruments
    3,541       15,766  
Cash interest expense (2)
    (16,370 )     (12,805 )
Non-cash equity based compensation
    1,963       452  
Amortization of turnaround costs
    5,746       4,100  
Income tax expense
    (438 )     (260 )
Provision for doubtful accounts
    255       (91 )
Debt extinguishment costs
    (729 )      
Changes in assets and liabilities:
               
Accounts receivable
    (48,479 )     (27,323 )
Inventory
    (111,555 )     (9,583 )
Other current assets
    (14,482 )     2,265  
Turnaround costs
    (7,501 )     (8,548 )
Derivative activity
    5,699       1,443  
Accounts payable
    62,834       48,584  
Other liabilities
    (7,904 )     (2,580 )
Other, including changes in noncurrent assets and liabilities
    (2,245 )     648  
 
           
Net cash provided by (used in) operating activities
  $ (70,558 )   $ 42,567  
 
           
 
(1)   Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs.
 
(2)   Represents consolidated interest expense less non-cash interest expense.

40


Table of Contents

Changes in Results of Operations for the Three Months Ended June 30, 2011 and 2010
     Sales. Sales increased $219.1 million, or 42.6%, to $733.8 million in the three months ended June 30, 2011 from $514.7 million in the same period in 2010. Sales for each of our principal product categories in these periods were as follows:
                         
    Three Months Ended June 30,  
    2011     2010     % Change  
    (Dollars in thousands, except per barrel data)  
Sales by segment:
                       
Specialty products:
                       
Lubricating oils
  $ 246,448     $ 176,354       39.7 %
Solvents
    135,642       95,777       41.6 %
Waxes
    33,874       28,362       19.4 %
Fuels (1)
    592       2,232       (73.5 )%
Asphalt and by-products (2)
    49,858       26,698       86.7 %
 
                 
Total specialty products
  $ 466,414     $ 329,423       41.6 %
 
                 
Total specialty products sales volume (in barrels)
    2,798,000       2,481,000       12.8 %
Average specialty products sales price per barrel
  $ 166.70     $ 132.78       25.5 %
Fuel products:
                       
Gasoline
  $ 127,452     $ 76,287       67.1 %
Diesel
    91,611       77,396       18.4 %
Jet fuel
    40,686       27,816       46.3 %
By-products (3)
    7,607       3,730       103.9 %
 
                 
Total fuel products
  $ 267,356     $ 185,229       44.3 %
 
                 
Total fuel products sales volume (in barrels)
    2,630,000       2,308,000       14.0 %
Average fuel products sales price per barrel (4)
  $ 101.66     $ 80.26       26.7 %
Total sales
  $ 733,770     $ 514,652       42.6 %
 
                 
Total sales volume (in barrels)
    5,428,000       4,789,000       13.3 %
 
                 
 
(1)   Represents fuels produced in connection with the production of specialty products at the Princeton, Cotton Valley and Karns City refineries.
 
(2)   Represents asphalt and other by-products produced in connection with the production of specialty products at the Princeton, Cotton Valley and Shreveport refineries.
 
(3)   Represents by-products produced in connection with the production of fuels at the Shreveport refinery.
 
(4)   Average fuel products sales price per barrel includes impact of hedging contracts.
     Specialty products segment sales for the three months ended June 30, 2011 increased $137.0 million, or 41.6%, as a result of an increase in the average selling price per barrel of $33.92, or 25.5%, and a 12.8% increase in sales volume as compared to the same period in 2010. Lubricating oils, solvents and waxes experienced price increases, driven by improving overall demand and a 37.6% increase in the average cost of crude oil per barrel for the 2011 period as compared to the same period in 2010. The increased volume is due primarily to improving overall specialty products demand as a result of improved economic conditions and higher refinery run rates over the prior period.
     Fuel products segment sales for the three months ended June 30, 2011 increased $82.1 million, or 44.3%, due primarily to an increase in the average selling price per barrel (excluding the impact of hedging activities) of $39.91, or 45.8% and a 14.0% increase in sales volume, driven by market conditions and higher refinery run rates over the prior period. The increase in the average selling price per barrel of 45.8% compares to a 39.0% increase in the average price of crude oil per barrel. The average selling price per barrel increased for all fuel products, with jet fuel and diesel selling prices experiencing significant increases driven by improved market pricing. The increase in sales volume is due primarily to higher refinery run rates over the prior period. Refinery run rates were below expectations due to an approximate three week shutdown during May and June 2011 of an ExxonMobil crude oil pipeline serving our Shreveport refinery due to the impacts of the Mississippi River flooding occurring during this period. Also adversely impacting fuel product sales was a $50.9 million increase in derivative losses on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for discussion of the net impact of our crude oil and fuel products derivative instruments designated as hedges.

41


Table of Contents

     Gross Profit. Gross profit increased $0.9 million, or 1.9%, to $50.6 million in the three months ended June 30, 2011 from $49.6 million in the same period in 2010. Gross profit for our specialty products and fuel products segments was as follows:
                         
    Three Months Ended June 30,  
    2011     2010     % Change  
    (Dollars in thousands, except per barrel data)  
Gross profit by segment:
                       
Specialty products
  $ 58,308     $ 46,400       25.7 %
Percentage of sales
    12.5 %     14.1 %        
Specialty products gross profit per barrel
  $ 20.84     $ 18.70       11.4 %
Fuel products
  $ (7,743 )   $ 3,219       (340.5 )%
Percentage of sales
    (2.9 )%     1.7 %        
Fuel products gross profit per barrel
  $ (2.94 )   $ 1.39       (311.5 )%
Total gross profit
  $ 50,565     $ 49,619       1.9 %
Percentage of sales
    6.9 %     9.6 %        
     The increase in specialty products segment gross profit of $11.9 million quarter over quarter was due primarily to a 12.8% increase in sales volume and a 25.5% increase in the average selling price per barrel as discussed above, partially offset by a 37.6% increase in the average cost of crude oil per barrel and higher operating costs, primarily repairs and maintenance.
     The decrease in fuel products segment gross profit of $11.0 million quarter over quarter was due primarily to increased realized losses on derivatives of $27.1 million in our fuel products hedging program, a 39.0% increase in the cost of crude oil per barrel, and increased production of by-products partially offset by a 14.0% increase in sales volume and a 45.8% increase in selling prices per barrel, excluding the impact of realized hedging losses. Our fuels hedging program and refinery run rates being below expectations resulted in our diesel and jet fuel sales volumes being approximately 100% hedged at approximately $12.00 per barrel during the second quarter of 2011. This prevented us from fully realizing the benefit of increased market prices for fuels. Additionally, by-product production increased in the 2011 period as compared to the 2010 period due primarily to an increase in the mix of sour crude oil run rates at the Shreveport refinery.
     Selling, general and administrative. Selling, general and administrative expenses increased $2.1 million or 25.8% to $10.5 million in the three months ended June 30, 2011 from $8.3 million in the same period in 2010. This increase is due primarily to increased accrued incentive compensation costs of $1.6 million in 2011 compared to 2010.
     Transportation. Transportation expenses increased $2.7 million, or 13.7%, to $22.7 million in the three months ended June 30, 2011 from $20.0 million in the same period in 2010. This increase is due primarily to increased sales volumes of lubricating oils, solvents and waxes, as well as higher freight costs.
     Insurance recoveries. Insurance recoveries were $7.9 million for the three months ended June 30, 2011. The gain was related to a claim settled in the second quarter of 2011 with insurers related to the failure of an environmental operating unit at the Shreveport refinery in the first quarter of 2010.
     Interest expense. Interest expense increased $3.3 million, or 44.9%, to $10.5 million in the three months ended June 30, 2011 from $7.3 million in the three months ended June 30, 2010, due primarily to higher interest rates associated with the new 2019 Notes as compared to our term loan that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.
     Debt extinguishment costs. Debt extinguishment costs were $15.1 million during the three months ended June 30, 2011. The debt extinguishment costs were related to the extinguishment of the term loan with proceeds from the issuance of the 2019 Notes.
     Realized loss on derivative instruments. Realized loss on derivative instruments decreased $2.9 million to $2.4 million in the three months ended June 30, 2011 from $5.3 million for the three months ended June 30, 2010. The change was due primarily to realized losses of approximately $3.9 million in our specialty products segment related to crude oil derivatives not designated as hedges, partially offset by realized crack spread derivative gains of $1.3 million that were both incurred during the three months ended June 30, 2010, with minimal comparable activity during the three months ended June 30, 2011.
     Unrealized loss on derivative instruments. Unrealized loss on derivative instruments decreased $4.9 million, to $3.1 million in the three months ended June 30, 2011 from $8.0 million in the three months ended June 30, 2010. The change was due primarily to decreases in unrealized losses on crack spread derivatives that were executed to economically lock in gains on a portion of our fuel

42


Table of Contents

products segment derivative hedging activity related to 2010, and decreases in unrealized losses on derivatives used to economically hedge our specialty products segment crude oil purchases and increased gain ineffectiveness. Partially offsetting these improvements were the losses on the $1.4 million in interest rate swap contracts that were discontinued as cash flow hedges of the future payment of interest on our term loan that was extinguished with the issuance of the 2019 Notes.
Changes in Results of Operations for the Six Months Ended June 30, 2011 and 2010
     Sales. Sales increased $339.7 million, or 34.0%, to $1,339.0 million in the six months ended June 30, 2011 from $999.3 million in the same period in 2010. Sales for each of our principal product categories in these periods were as follows:
                         
    Six Months Ended June 30,  
    2011     2010     % Change  
    (Dollars in thousands, except per barrel data)  
Sales by segment:
                       
Specialty products:
                       
Lubricating oils
  $ 455,499     $ 340,402       33.8 %
Solvents
    253,978       183,631       38.3 %
Waxes
    68,181       54,608       24.9 %
Fuels (1)
    1,423       3,971       (64.2 )%
Asphalt and by-products (2)
    84,435       52,287       61.5 %
 
                 
Total specialty products
  $ 863,516     $ 634,899       36.0 %
 
                 
Total specialty products sales volume (in barrels)
    5,446,000       4,936,000       10.3 %
Average specialty products sales price per barrel
  $ 158.56     $ 128.63       23.3 %
Fuel products:
                       
Gasoline
  $ 223,233     $ 152,170       46.7 %
Diesel
    173,764       141,626       22.7 %
Jet fuel
    67,460       65,380       3.2 %
By-products (3)
    11,037       5,194       112.5 %
 
                 
Total fuel products
  $ 475,494     $ 364,370       30.5 %
 
                 
Total fuel products sales volume (in barrels)
    4,802,000       4,506,000       6.6 %
Average fuel products sales price per barrel (4)
  $ 99.02     $ 80.86       22.5 %
Total sales
  $ 1,339,010     $ 999,269       34.0 %
 
                 
Total sales volume (in barrels)
    10,248,000       9,442,000       8.5 %
 
                 
 
(1)   Represents fuels produced in connection with the production of specialty products at the Princeton, Cotton Valley and Karns City refineries.
 
(2)   Represents asphalt and other by-products produced in connection with the production of specialty products at the Princeton, Cotton Valley and Shreveport refineries.
 
(3)   Represents by-products produced in connection with the production of fuels at the Shreveport refinery.
 
(4)   Average fuel products sales price per barrel includes impact of hedging contracts.
     Specialty products segment sales for the six months ended June 30, 2011 increased $228.6 million, or 36.0%, as a result of an increase in the average selling price per barrel of $29.93, or 23.3%, and a 10.3% increase in sales volume as compared to the same period in 2010. Lubricating oils, solvents and waxes experienced price increases, driven by improving overall demand and a 30.6% increase in the average cost of crude oil per barrel for the 2011 period as compared to the same period in 2010. The increased volume is due primarily to improving overall specialty products demand as a result of improved economic conditions and higher refinery run rates over the prior period.
     Fuel products segment sales for the six months ended June 30, 2011 increased $111.1 million, or 30.5%, due primarily to an increase in the average selling price per barrel (excluding the impact of hedging activities) of $34.00, or 39.2%, driven by market conditions compared to a 31.6% increase in the average price of crude oil per barrel and a 6.6% increase in sales volume. The average selling price per barrel increased for all fuel products, with gasoline and diesel selling prices experiencing significant increases driven by improved market pricing. Adversely impacting fuel products sales was a $77.8 million increase in derivative losses on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for discussion of the net impact of our crude oil and fuel products derivative instruments designated as hedges.

43


Table of Contents

     Gross Profit. Gross profit increased $16.1 million, or 19.8%, to $97.4 million in the six months ended June 30, 2011 from $81.3 million in the same period in 2010. Gross profit for our specialty products and fuel products segments was as follows:
                         
    Six Months Ended June 30,  
    2011     2010     % Change  
    (Dollars in thousands, except per barrel data)  
Gross profit by segment:
                       
Specialty products
  $ 106,199     $ 69,826       52.1 %
Percentage of sales
    12.3 %     11.0 %        
Specialty products gross profit per barrel
  $ 19.50     $ 14.15       37.8 %
Fuel products
  $ (8,770 )   $ 11,469       (176.5 )%
Percentage of sales
    (1.8 )%     3.1 %        
Fuel products gross profit per barrel
  $ (1.83 )   $ 2.55       (171.8 )%
Total gross profit
  $ 97,429     $ 81,295       19.8 %
Percentage of sales
    7.3 %     8.1 %        
     The increase in specialty products segment gross profit of $36.4 million for the six months ended June 30, 2011 compared to the same period in 2010 was due primarily to a 10.3% increase in sales volumes and a 23.3% increase in the average selling price per barrel as discussed above, partially offset by a 30.6% increase in the average cost of crude oil per barrel and higher operating costs, primarily repair and maintenance.
     The decrease in fuel products segment gross profit of $20.2 million for the six months ended June 30, 2011 compared to the same period in 2010 was due primarily to increased realized losses on derivatives of $52.4 million in our fuel products hedging program, a 31.6% increase in the cost of crude oil per barrel, and increased production of by-products, partially offset by a 6.6% increase in sales volume and a 39.2% increase in selling prices per barrel, excluding the impact of realized hedging losses. Our fuel products hedging program and refinery run rates being below expectations resulted in our diesel and jet fuel sales volumes being approximately 100% hedged during the second quarter of 2011 at approximately $12.00 per barrel. This prevented us from realizing the benefit of increased market pricing for these products. Additionally, by-product production increased in the 2011 period as compared to the 2010 period due primarily to an increase in the mix of sour crude oil run rates at the Shreveport refinery.
     Selling, general and administrative. Selling, general and administrative expenses increased $5.5 million, or 35.5%, to $21.0 million in the six months ended June 30, 2011 from $15.5 million in 2010. This increase is due primarily to increased accrued incentive compensation costs of $3.0 million in 2011 compared to 2010, as well as increased overall salaries and wages, bad debt expense and advertising.
     Transportation. Transportation expenses increased $5.6 million, or 13.8%, to $45.8 million in the six months ended June 30, 2011 from $40.2 million in the same period in 2010. This increase is due primarily to increased sales volumes of lubricating oils, solvents and waxes, as well as higher freight costs.
     Insurance recoveries. Insurance recoveries were $8.7 million for the six months ended June 30, 2011. The gain was related to a claim settled in the second quarter of 2011 with insurers related to the failure of an environmental operating unit at the Shreveport refinery in the first quarter of 2010.
     Interest expense. Interest expense increased $3.3 million or 22.5%, to $18.0 million in the six months ended June 30, 2011 from $14.7 million in the six months ended June 30, 2010, due primarily to higher interest rates associated with the new 2019 Notes as compared to our term loan that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.
     Debt extinguishment costs. Debt extinguishment costs were $15.1 million during the six months ended June 30, 2011. The debt extinguishment costs were related to the extinguishment of the term loan with proceeds from the issuance of the 2019 Notes.
     Realized loss on derivative instruments. Realized loss on derivative instruments decreased $3.9 million to $2.0 million in the six months ended June 30, 2011 from $5.9 million for the six months ended June 30, 2010. This change was due primarily to increased realized gains of approximately $0.9 million in our specialty products segment related to crude oil derivatives not designated as hedges for the six months ended June 30, 2011, while experiencing losses on similar specialty products segment derivatives of $4.6

44


Table of Contents

million for the same period in 2010. Partially offsetting these decreased losses were realized crack spread derivative gains of $2.3 million realized in the prior period, with minimal comparable activity during the six months ended June 30, 2011.
     Unrealized loss on derivative instruments. Unrealized loss on derivative instruments decreased $12.2 million, to $3.5 million in the six months ended June 30, 2011 from $15.8 million in the six months ended June 30, 2010. The decreased loss is due primarily to an increase in gain ineffectiveness during the quarter ended June 30, 2011 with significant loss ineffectiveness in the prior period. Partially offsetting this improvement were the losses on the $1.4 million in interest rate swap contracts that were discontinued as cash flow hedges of the future payment of interest on our term loan that was extinguished with the issuance of the 2019 Notes.
Liquidity and Capital Resources
     The following should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” included under Part I Item 7 in our 2010 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 5 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for additional discussion related to long-term debt.
     Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings, proceeds from notes offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions to our unitholders and general partner and debt service. We expect that our principal uses of cash in the future will be for distributions to our limited partners and general partner, debt service, replacement and environmental capital expenditures and capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. We expect to fund future capital expenditures with current cash flow from operations and borrowings under our revolving credit facility. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and borrowings under our existing revolving credit facility and may require us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.
     As discussed above, we intend to finance the Superior Acquisition primarily through a combination of equity and long-term debt financing and through borrowings under our revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Superior Refinery Purchase Agreement” above for additional information.
Cash Flows
     We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity to meet our financial commitments, debt service obligations and anticipated capital expenditures. However, we are subject to business and operational risks that could materially adversely affect our cash flows. A material decrease in our cash flow from operations including a significant, sudden decrease in crude oil prices would likely produce a corollary material adverse effect on our borrowing capacity under our revolving credit facility and potentially our ability to comply with the covenants under our credit facilities. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which would be funded by borrowings under our revolving credit facility.
     The following table summarizes our primary sources and uses of cash in each of the periods presented:
                 
    Six Months Ended  
    June 30,  
    2011     2010  
    (In thousands)  
Net cash provided by (used in) operating activities
  $ (70,558 )   $ 42,567  
Net cash used in investing activities
  $ (18,563 )   $ (16,896 )
Net cash provided by (used in) financing activities
  $ 89,139     $ (25,653 )
     Operating Activities. Operating activities used cash of $70.6 million during the six months ended June 30, 2011 compared to cash provided of $42.6 million during the same period in 2010. The change was due primarily to increases in working capital requirements of $122.0 million, due primarily to the increased crude oil inventory levels as a result of terminating certain just-in-time inventory supply arrangements with a related party, Legacy, effective May 31, 2011, increased working capital requirements resulting from increased run rates at our Shreveport facility and higher commodity prices in general, partially offset by insurance recoveries related to a settled claim with insurers resulting from the failure of an environmental operating unit at the Shreveport refinery in the first quarter of 2010.
     Investing Activities. Cash used in investing activities increased to $18.6 million during the six months ended June 30, 2011 compared to $16.9 million during the six months ended June 30, 2010. The increase is due primarily to increased capital expenditures for capital improvements, which were partially offset by insurance recoveries of $1.9 million.

45


Table of Contents

     Financing Activities. Financing activities provided cash of $89.1 million for the six months ended June 30, 2011 compared to cash used of $25.7 million during the six months ended June 30, 2010. The increase is due primarily to the net proceeds from the public equity offering of $92.3 million during the first quarter of 2011 and net proceeds from the 2019 Notes offering of $389.0 million in the second quarter of 2011, partially offset by debt issuance costs, the repayment of the senior secured first lien term loan facility and quarterly distributions to our unitholders.
     On April 8, 2011, we declared a quarterly cash distribution of $0.475 per unit on all outstanding units, or approximately $19.3 million in the aggregate, for the quarter ended March 31, 2011. The distribution was paid on May 13, 2011 to unitholders of record as of the close of business on May 3, 2011. This quarterly distribution of $0.475 per unit equates to $1.90 per unit, or approximately $77.2 million in the aggregate on an annualized basis.
     On July 22, 2011, we declared a quarterly cash distribution of $0.495 per unit on all outstanding units, or approximately $20.1 million in aggregate, for the quarter ended June 30, 2011. The distribution will be paid on August 12, 2011 to unitholders of record as of the close of business on August 2, 2011. This quarterly distribution of $0.495 per unit equates to $1.98 per unit, or approximately $80.5 million in the aggregate on an annualized basis.
Capital Expenditures
     Our capital expenditure requirements consist of capital improvement expenditures, replacement capital expenditures and environmental capital expenditures. Capital improvement expenditures include expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs. Replacement capital expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.
     The following table sets forth our capital improvement expenditures, replacement capital expenditures and environmental capital expenditures in each of the periods shown.
                 
    Six Months Ended June 30,  
    2011     2010  
    (In thousands)  
Capital improvement expenditures
  $ 13,039     $ 675  
Replacement capital expenditures
    5,873       8,801  
Environmental capital expenditures
    1,723       7,541  
 
           
Total
  $ 20,635     $ 17,017  
 
           
     We anticipate that future capital expenditure requirements will be provided primarily through cash from operations and available borrowings under our revolving credit facility. We estimate our replacement and environmental capital expenditures will be approximately $6.0 million per quarter for the remainder of 2011, with total replacement and environmental capital expenditures below 2010 levels. These estimated amounts for 2011 include a portion of the $11.0 million to $15.0 million in environmental projects to be spent over the next five years as required by our settlement with the LDEQ under the “Small Refinery and Single Site Refining Initiative.” Please read Note 4 of Part I Item 1 “Financial Statements — Commitments and Contingencies — Environmental” for additional information. Our capital improvement expenditures have increased due to various minor capital improvement projects to reduce energy costs, improve finished product quality and improve finished product yields. We do not expect significant capital improvement expenditures for the remainder of 2011.
Debt and Credit Facilities
     As of June 30, 2011, our debt and credit facilities consisted of:
    a $550.0 million senior secured revolving credit facility, subject to borrowing base restrictions, with a letter of credit sublimit equal to the greater of (i) $400.0 million and (ii) 80% of revolver commitments then in effect; and
 
    $400.0 million of 9 3/8% senior notes due 2019.

46


Table of Contents

Amended and Restated Senior Secured Revolving Credit Facility
     On June 24, 2011, we entered into an amended and restated senior secured revolving credit facility, which increased the maximum availability from $375.0 million to $550.0 million, subject to borrowing base limitations, and includes a $300.0 million incremental uncommitted expansion feature. The revolving credit facility, which matures in June 2016, has a first priority lien on our cash, accounts receivable, inventory and certain other personal property .
     The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; and enter into a merger, consolidation or sale of assets. The revolving credit facility generally permits us to make cash distributions to our unitholders as long as immediately after giving effect to such a cash distribution we have availability under the revolving credit facility at least equal to the greater of (i) 15% of the lesser of (a) the Borrowing Base (as defined in the revolving credit facility) without giving effect to the LC Reserve (as defined in the revolving credit facility) and (b) the revolving credit facility commitments then in effect and (ii) $45.0 million. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $30.0 million, then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0.
     Borrowings under the revolving credit facility are limited to a borrowing base that is determined based on advance rates of percentages of eligible accounts receivable and inventory (as defined by the revolving credit facility agreement). As such, the borrowing base can fluctuate based on changes in selling prices of our products and our current material costs, primarily the cost of crude oil. On June 30, 2011, we had availability on our revolving credit facility of $194.7 million, based upon a $402.2 million borrowing base, $179.5 million in outstanding standby letters of credit and outstanding borrowings of $28.1 million. Our borrowing base at June 30, 2011 was $402.2 million. The borrowing base cannot exceed the revolving credit facility commitments then in effect. The lender group under our revolving credit facility is comprised of a syndicate of eleven lenders with total commitments of $550.0 million.
     The revolving credit facility, which is our primary source of liquidity for cash needs in excess of cash generated from operations, matures in June 2016 and currently bears interest at prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of June 30, 2011, this margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin fluctuates quarterly based on our average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter. Letters of credit issued under the revolving credit facility accrue fees at the margin applicable to LIBOR loans. Basis points margin is as follows:
         
Quarterly Average   Margin on Base Rate   Margin on LIBOR
Availability Percentage   Revolving Loans   Revolving Loans
≥ 66%
  1.00%   2.25%
≥ 33% and < 66%   1.25%   2.50%
< 33%   1.50%   2.75%
     If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of the credit facilities and exercise other rights and remedies. An event of default includes, among other things, the nonpayment of principal interest, fees or other amounts; failure of any representation or warranty to be true and correct when made or confirmed; failure to perform or observe covenants in the revolving credit facility or other loan documents, subject, in limited circumstances, to certain grace periods; cross-defaults in other indebtedness if the effect of such default is to cause, or permit the holders of such indebtedness to cause, the acceleration of such indebtedness under any material agreement; bankruptcy or insolvency events; monetary judgment defaults; asserted invalidity of the loan documentation; and a change of control over us.
     Amounts outstanding on our revolving credit facility fluctuate materially during each quarter due to normal changes in working capital, payments of quarterly distributions to unitholders and debt service costs. Specifically, the amount borrowed under our revolving credit facility is typically at its highest level after we pay for the majority of our crude oil supplies on the 20th day of every month per standard industry terms. The maximum revolving credit facility borrowings during the second quarter of 2011 were $97.6

47


Table of Contents

million. Nonetheless, our availability on our revolving credit facility during the peak borrowing days of a quarter has been ample to support our operations and service upcoming requirements. During the quarter ended June 30, 2011, availability for additional borrowings under our revolving credit facility was approximately $104.3 million at its lowest point. We believe that we will continue to have sufficient cash flow from operations and borrowing availability under our revolving credit facility to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, credit agreement covenants, contingencies and anticipated capital expenditures.
9 3/8% Senior Notes
     On April 21, 2011, we and Calumet Finance Corp. issued and sold $400.0 million in aggregate principal amount of our 9 3/8% 2019 Notes in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers. The 2019 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. We received proceeds of $389.0 million net of underwriters’ fees and expenses, which we used to repay in full borrowings outstanding under our existing senior secured first lien term loan facility, as well as all accrued interest and fees, and for general partnership purposes. Interest on the 2019 Notes will be paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are guaranteed on a senior unsecured basis by all of our operating subsidiaries and certain of our future operating subsidiaries.
     At any time prior to May 1, 2014, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.
     On and after May 1, 2015, we may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:
         
Year   Percentage  
2015
    104.688 %
2016
    102.344 %
2017 and at any time thereafter
    100.000 %
     Prior to May 1, 2015, we may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
     The indenture governing the 2019 Notes contains covenants that, among other things, restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.
     Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that we repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.
     In connection with the notes offering on April 21, 2011, our then current revolving credit facility was amended to, among other things, (i) permit the issuance of the 2019 Notes; (ii) upon consummation of the issuance of the 2019 Notes and the termination of the senior secured first lien credit facility, release the revolving credit facility lenders’ second priority lien on the collateral securing the senior secured first lien credit facility and (iii) change the interest rate pricing on the revolving credit facility.

48


Table of Contents

Registration Rights Agreement
     On April 21, 2011, in connection with the issuance and sale of the 2019 Notes, we entered into a registration rights agreement with the initial purchasers of the 2019 Notes obligating us to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2019 Notes can offer to exchange the 2019 Notes issued in this offering for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. We must use reasonable best efforts to cause the exchange offer registration statement to become effective by April 20, 2012 and remain effective until 180 days after the closing of the exchange. Additionally, we have agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, we must use reasonable best efforts to file a shelf registration statement for the resale of the 2019 Notes. If we fail to satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.
Senior Secured First Lien Credit Facility
     On April 21, 2011, we used approximately $369.5 million of the net proceeds from the issuance and sale of the 2019 Notes to repay in full our term loan facility, as well as accrued interest and fees, and extinguished the senior secured first lien credit facility. We did not incur any material early extinguishment penalties in connection with our termination of the senior secured first lien credit facility. Further, we recorded in the second quarter of 2011 approximately $15.1 million in extinguishment charges related to the write off of the unamortized debt issuance costs and the unamortized discount associated with the term loan.
     Borrowings under the senior secured first lien credit facility were used (i) to finance a portion of the acquisition of Penreco in 2008, (ii) to fund the anticipated growth in working capital and remaining capital expenditures associated with our Shreveport refinery expansion project completed in 2008, (iii) to refinance our then-existing term loan facility, (iv) to issue a $50.0 million letter credit to secure our obligations under one of our master derivatives contracts and (v) for general partnership purposes. Each lender under the senior secured first lien credit facility generally had a first priority lien on our fixed assets and a second priority lien on our cash, accounts receivable, inventory and certain other personal property. The senior secured first lien credit facility would have matured in January 2015.
Derivatives
     In connection with the termination of the term loan facility and the amendment of our senior secured revolving credit facility, on April 21, 2011, we entered into Amendments to certain of our master derivatives contracts to provide new credit support arrangements to secure our payment obligations under these contracts following the termination of the term loan facility and the amendment and restatement of our senior secured revolving credit facility. Under the new credit support arrangements, our payment obligations are generally secured by a first priority lien on our and our subsidiaries’ real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). We also issued to one counterparty a $25.0 million standby letter of credit under the revolving credit facility to replace a prefunded $50.0 million letter of credit previously issued under the senior secured first lien facility. In the event that such counterparty’s exposure to us exceeds $150.0 million, we will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges. Our master derivatives contracts will continue to impose a number of covenant limitations on our operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements. In addition to the $25.0 million standby letter of credit posted to one counterparty, as of June 30, 2011 we had cash collateral posted to another counterparty of $11.9 million. For financial reporting purposes, we do not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to us upon settlement of the related derivative instrument liability. Our master derivative contracts continue to impose a number of covenant limitations on our operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.
     The fair value of the Company’s derivatives decreased by approximately $46.0 million subsequent to June 30, 2011 to a liability of approximately $184.0 million. As of August 8, 2011, we had approximately $31.3 million in cash margin posted with one counterparty to support crack spread hedging. All other credit support thresholds with our counterparties are at levels where it would take a substantial increase in fuel products crack spreads to require additional collateral to be posted. As a result, we do not expect further increases in fuel products crack spreads to significantly impact our liquidity.

49


Table of Contents

Contractual Obligations and Commercial Commitments
     The following table summarizes our contractual cash obligations as of June 30, 2011 at current maturities and reflects only those line items that are materially changed since December 31, 2010:
                                         
            Payments Due by Period  
            Less Than     1-3     3-5     More Than  
    Total     1 Year     Years     Years     5 Years  
                    (In thousands)                  
Operating activities:
                                       
Interest on long-term debt at contractual rates (1)
  $ 309,932     $ 43,288     $ 80,219     $ 80,175     $ 106,250  
Operating lease obligations (2)
    33,107       11,789       15,458       5,182       678  
Letters of credit (3)
    179,473       179,473                    
Purchase commitments (4)
    1,271,176       765,864       436,920       68,392        
Financing activities:
                                       
Capital lease obligations
    1,292       942       350              
Long-term debt obligations, excluding capital lease obligations
    428,090                         428,090  
 
                             
Total obligations
  $ 2,223,070     $ 1,001,356     $ 532,947     $ 153,749     $ 535,018  
 
                             
 
(1)   Interest on long-term debt at contractual rates and maturities relates primarily to our 2019 Notes and revolving credit agreement.
 
(2)   We have various operating leases primarily for the use of land, storage tanks, pressure stations, railcars, equipment, precious metals and office facilities that extend through August 2017.
 
(3)   Letters of credit primarily supporting crude oil purchases, precious metals leasing and hedging activities.
 
(4)   Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil and other feedstocks and finished products for resale from various suppliers based on current market prices at the time of delivery.
     In connection with the closing of the acquisition of Penreco on January 3, 2008, we entered into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, ConocoPhillips is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, we expect to purchase $74.6 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of June 30, 2011. This amount is not included in the table above. If the Base Volume is not supplied at any point during the first five years of the ten year term, a penalty for each gallon of shortfall must be paid to us as liquidated damages.
Off-Balance Sheet Arrangements
     We have no material off-balance sheet arrangements.
Critical Accounting Policies and Estimates
     For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Part I Item 7 of our 2010 Annual Report.
Recent Accounting Pronouncements
     For additional discussion regarding recent accounting pronouncements, see Note 2 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements.”
Equity Transactions
     In February 2011, we satisfied the last of the earnings and distributions tests contained in our partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution on February 14, 2011. Two days following this quarterly distribution to our unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.

50


Table of Contents

     On February 24, 2011, we completed a public equity offering of our common units in which we sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by us from this offering (net of underwriting discounts, commissions and expenses but before our general partner’s capital contribution) were $92.3 million. The net proceeds were used to repay borrowings under our revolving credit facility and for general partnership purposes. Underwriting discounts totaled $3.9 million. Our general partner contributed $2.0 million to retain its 2% general partner interest.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
     The following should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part I Item 7A in our 2010 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for additional discussion related to derivative instruments and hedging activities.
Commodity Price Risk
     Holding all other variables constant, we expect a $1 increase in the applicable commodity prices would change our recorded mark-to-market valuation by the following amounts based upon the volumes hedged as of June 30, 2011:
         
    In millions  
Crude oil swaps
  $ 11.4  
Diesel swaps
  $ 3.6  
Jet fuel swaps
  $ 7.3  
Gasoline swaps
  $ 0.6  
Interest Rate Risk
     Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates, which is consistent with prior years. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates. Historically, our policy has been to enter into interest rate swap agreements to hedge up to 75% of our interest rate risk related to variable rate debt.
     We are exposed to market risk from fluctuations in interest rates. As of June 30, 2011, we had approximately $28.1 million of variable rate debt outstanding under our revolving credit facility. Holding other variables constant (such as debt levels), a one hundred basis point change in interest rates on our variable rate debt as of June 30, 2011 would be expected to have an impact on net income and cash flows for 2011 of approximately $0.3 million.
Existing Commodity Derivative Instruments
Fuel Products Segment
     The following table provides a summary of the implied crack spreads for the crude oil, diesel, jet fuel and gasoline swaps as of June 30, 2011 disclosed in Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements,” all of which are designated as hedges.
                         
                    Implied Crack  
Crude Oil and Fuel Products Swap Contracts by Expiration Dates   Barrels     BPD     Spread ($/Bbl)  
Third Quarter 2011
    1,610,000       17,500     $ 12.75  
Fourth Quarter 2011
    1,334,000       14,500       12.16  
Calendar Year 2012
    5,626,000       15,372       13.27  
Calendar Year 2013
    2,864,000       7,847       23.90  
 
                 
Totals
    11,434,000                  
Average price
                  $ 15.73  

51


Table of Contents

     At June 30, 2011, we had the following jet fuel put options related to jet fuel crack spreads in our fuel products segment, none of which are designated as hedges.
                                 
                    Average     Average  
                    Sold Put     Bought Put  
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates   Barrels     BPD     ($/Bbl)     ($/Bbl)  
Fourth Quarter 2011
    184,000       2,000     $ 4.75     $ 7.00  
 
                         
Totals
    184,000                          
Average price
                  $ 4.75     $ 7.00  
Specialty Products Segment
     At June 30, 2011, we had no derivative positions outstanding related to crude oil purchases in our specialty products segment. Please refer to Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for detailed information on these derivatives.
Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
     As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2011 at the reasonable assurance level.
(b) Changes in Internal Control over Financial Reporting
     There was no change in our internal control over financial reporting during the second fiscal quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

52


Table of Contents

PART II
Item 1. Legal Proceedings
     We are not a party to, and our property is not the subject of, any pending legal proceedings other than ordinary routine litigation incidental to our business. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. The information provided under Note 4 “Commitments and Contingencies” in Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” is incorporated herein by reference.
Item 1A. Risk Factors
     The risk factors included in our 2010 Annual Report have not materially changed other than as set forth below.
Our revolving credit facility, indenture governing the 2019 Notes and master derivative contracts contain operating and financial restrictions that may restrict our business and financing activities.
     The operating and financial restrictions and covenants in our revolving credit facility, indenture governing the 2019 Notes, master derivative contracts and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities, including restrictions on our ability to, among other things:
    pay distributions or redeem or repurchase our units or repurchase our subordinated debt;
    incur or guarantee additional indebtedness or issue preferred units;
    create or incur certain liens;
    make certain acquisitions and investments;
    make capital expenditures above specified amounts;
    redeem or repay other debt or make other restricted payments;
    enter into transactions with affiliates;
    enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
    create unrestricted subsidiaries;
    enter into sale and leaseback transactions;
    enter into a merger, consolidation or transfer or sale of assets, including equity interests in our subsidiaries;
    cease our commodity hedging program; and
    engage in certain business activities.
     Our revolving credit facility contains operating and financial restrictions similar to the above listed items, including a springing financial covenant which provides that if availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $30.0 million, we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0. The failure to comply with any of these or other covenants would cause a default under our revolving credit facility.

53


Table of Contents

     Our existing indebtedness imposes, and any future indebtedness may impose, a number of covenants on us regarding collateral maintenance and insurance maintenance. As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
     Our ability to comply with the covenants and restrictions contained in the indenture governing the 2019 Notes, our revolving credit facility and our master derivative contracts may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with the covenants, ratios or tests in the indenture governing the 2019 Notes, our revolving credit facility, our master derivative contracts or any future indebtedness could result in an event of default under the indenture, our revolving credit facility, our master derivative contracts, the indenture governing our 2019 Notes or our future indebtedness, which, if not cured or waived, could have a material adverse affect on our business, financial condition and results of operations. In the event of any default on our indebtedness, our debt holders and lenders:
    will not be required to lend any additional amounts to us;
    could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
    could elect to require that all obligations accrue interest at the default rate, if such rate has not already been imposed;
    may have the ability to require us to apply all of our available cash to repay these borrowings; or
    may prevent us from making debt service payments under our other agreements, any of which could result in an event of default under the notes.
     If an acceleration of our debt occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if new financing were available, it may be on terms that are less attractive to us than our then existing credit facilities or it may not be on terms that are acceptable to us.
     If our existing indebtedness were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are secured by substantially all of our accounts receivable, inventory and certain related assets and our obligations under our master derivative contracts are secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements), and if we are unable to repay our indebtedness under the revolving credit facility or master derivative contracts, the lenders could seek to foreclose on these assets. Please read Part I Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information regarding our long-term debt.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets and our ability to distribute cash to our unitholders and make payments on our debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us.
     We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the equity interests in our subsidiaries. As a result, our ability to distribute cash to our unitholders and payments of debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our revolving credit facility and applicable state laws and other laws and regulations. If we are unable to obtain the funds necessary to distribute cash to our unitholders or payments of debt obligations, we may be required to adopt one or more alternatives, such as a refinancing of our indebtedness, including our 2019 Notes, or incurring borrowings under our revolving credit facility. We cannot assure you that we would be able to refinance our indebtedness or that the terms on which we could refinance our indebtedness would be favorable.
A change of control could result in us facing substantial repayment obligations under our revolving credit facility and our 2019 Notes.
     Our revolving credit agreement and the indenture governing our 2019 Notes contain provisions relating to change of control of our managing general partner, our partnership and our operating subsidiaries. Upon a change of control event, we may be required

54


Table of Contents

immediately to repay the outstanding principal, any accrued interest on and any other amounts owed by us under our revolving credit facility, the 2019 Notes and other outstanding indebtedness. The source of funds for these repayments would be our available cash or cash generated from other sources. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under our revolving credit facility would have the right to foreclose on our assets, which would have a material adverse effect on us. Furthermore, certain change of control events would constitute an event of default under the agreement governing our revolving credit facility, and we might not be able to obtain a waiver of such default. There is no restriction in our partnership agreement on the ability of our general partner to enter into a transaction which would trigger the change of control provisions of our revolving credit facility agreement or the indenture governing our 2019 Notes.
We depend on certain key crude oil and other feedstock suppliers for a significant portion of our supply of crude oil and other feedstocks, and the loss of any of these key suppliers or a material decrease in the supply of crude oil and other feedstocks generally available to our refineries could materially reduce our ability to make distributions to unitholders.
     We purchase crude oil and other feedstocks from major oil companies as well as from various crude oil gatherers and marketers in east Texas and north Louisiana. In 2010, subsidiaries of Plains All American Pipeline, L.P. and Genesis Crude Oil, L.P. supplied us with approximately 49.6% and 4.6%, respectively, of our total crude oil supplies under term contracts and evergreen crude oil supply contracts. In addition, 41.5% of our total crude oil purchases in 2010 were from Legacy Resources, an affiliate of our general partner, to supply crude oil to our Princeton and Shreveport refineries. Each of our refineries is dependent on one or more of these suppliers and the loss of any of these suppliers would adversely affect our financial results to the extent we were unable to find another supplier of this substantial amount of crude oil. We do not maintain long-term contracts with most of our suppliers. For example, our contracts with Plains are currently month-to-month terminable upon 90 days’ notice. Additionally, we expect to purchase the crude oil supply for the Princeton refinery and Shreveport refinery directly from third-party suppliers under evergreen supply contracts and on the spot market. These evergreen contracts are generally terminable on 30 days notice, and purchases on the spot market may expose us to changes in commodity prices. For additional discussion regarding our crude oil and feedstock supply, please read Items 1 and 2 “Business and Properties — Crude Oil and Feedstock Supply” in our 2010 Annual Report.
     To the extent that our suppliers reduce the volumes of crude oil and other feedstocks that they supply us as a result of declining production or competition or otherwise, our revenues, net income and cash available for distribution to unitholders and payments of our debt obligations would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks on comparable terms from other suppliers, which may not be possible in areas where the supplier that reduces its volumes is the primary supplier in the area. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines, governmental moratoriums on drilling or production activities or otherwise, could result in a decline in the volume of crude oil we refine. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We have no control over the level of drilling activity in the fields that supply our refineries, the amount of reserves underlying the wells in these fields, the rate at which production from a well will decline or the production decisions of producers, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital.
We are dependent on certain third-party pipelines for transportation of crude oil and refined products, and if these pipelines become unavailable to us, our revenues and cash available for distributions to our unitholders and payment of our debt obligations could decline.
     Our Shreveport refinery is interconnected to pipelines that supply most of its crude oil and ship a portion of its refined fuel products to customers, such as pipelines operated by subsidiaries of Enterprise Products Partners L.P. and ExxonMobil. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. In addition, any of these third-party pipelines could become unavailable to transport crude oil or our refined fuel products because of acts of God, accidents, government regulation, terrorism or other events. For example, our refinery run rates were affected by an approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period. If any of these third-party pipelines become unavailable to transport crude oil or our refined fuel products because of acts of God, accidents, government regulation, terrorism or other events, our revenues, net income and cash available for distributions to our unitholders and payment of our debt obligations could decline.

55


Table of Contents

Decreases in the price of crude oil may lead to a reduction in the borrowing base under our revolving credit facility or the requirement that we post substantial amounts of cash collateral for derivative instruments, either of which could adversely affect our liquidity, financial condition and our ability to distribute cash to our unitholders.
     The borrowing base under our revolving credit facility is determined weekly or monthly depending upon availability levels or the existence of a default or event of default. Reductions in the value of our inventories as a result of lower crude oil prices could result in a reduction in our borrowing base, which would reduce the amount of financial resources available to meet our capital requirements. Further, if at any time our available capacity under our revolving credit facility falls below $35.0 million, or a default or event of default exists and for an additional 60 days after those circumstances do not exist, our cash balances in a dominion account established with the administrative agent will be applied on a daily basis to our outstanding obligations and the revolving credit facility. In addition, decreases in the price of crude oil may require us to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our hedging positions. At June 30, 2011, we had $194.7 million in availability under our revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information. If the borrowing base under our revolving credit facility decreases or we are required to post substantial amounts of cash collateral to our hedging counterparties, it could have a material adverse effect on our liquidity, financial condition and our ability to distribute cash to our unitholders.
An increase in interest rates will cause our debt service obligations to increase.
     Borrowings under our revolving credit facility bear interest at a floating rate (4.50% as of June 30, 2011). The interest rate is subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) or prime rate. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow available for distribution to our unitholders. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.
     In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors discussed in Part I Item 1A. “Risk Factors” in our 2010 Annual Report, which could materially affect our business, financial condition or future results. The risks described in this Quarterly Report and in our 2010 Annual Report are not the only risks facing the Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
     None.
Item 3. Defaults Upon Senior Securities
     None.
Item 4. Removed and Reserved
Item 5. Other Information
     None.

56


Table of Contents

Item 6. Exhibits
     The following documents are filed as exhibits to this Quarterly Report:
     
Exhibit    
Number   Description
3.1
  Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
   
3.2
  Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
   
3.3
  Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
   
3.4
  Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
   
3.5
  Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).
   
3.6
  Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)).
   
4.1
  Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)).
   
4.2
  Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).
   
4.3
  Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).
   
10.1*
  Amended and Restated ISDA Master Agreement and related Schedule, Lien Annex, Credit Support Annex and amendments thereto, dated as of January 3, 2008, between Calumet Lubricants Co., Limited Partnership and J. Aron & Company.
   
10.2*
  Collateral Trust Agreement, as amended, dated as of April 21, 2011, among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A.
   
10.3
  Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)).
   
31.1*
  Sarbanes-Oxley Section 302 certification of F. William Grube.
   
31.2*
  Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.
   
32.1*
  Section 1350 certification of F. William Grube and R. Patrick Murray, II.
   
100.INS**
  XBRL Instance Document
   
101.SCH**
  XBRL Taxonomy Extension Schema Document
   
101.CAL**
  XBRL Taxonomy Extension Calculation Linkbase Document
   
101.DEF**
  XBRL Taxonomy Extension Definition Linkbase Document
   
101.LAB**
  XBRL Taxonomy Extension Label Linkbase Document
   
101.PRE**
  XBRL Taxonomy Extension Presentation Linkbase Document
 
*   Filed herewith.
 
**   XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

57


Table of Contents

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.
         
  CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
 
  By:   Calumet GP, LLC,    
    its general partner   
     
  By:   /s/ R. Patrick Murray, II    
    R. Patrick Murray, II Vice President,   
    Chief Financial Officer and Secretary of
Calumet GP, LLC, general partner of
Calumet Specialty Products Partners, L.P.
(Authorized Person and Principal Accounting Officer) 
 
 
Date: August 8, 2011

58


Table of Contents

Index to Exhibits
     
Exhibit    
Number   Description
3.1
  Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
   
3.2
  Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
   
3.3
  Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
   
3.4
  Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
   
3.5
  Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).
   
3.6
  Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)).
   
4.1
  Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)).
   
4.2
  Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).
   
4.3
  Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).
   
10.1*
  Amended and Restated ISDA Master Agreement and related Schedule, Lien Annex, Credit Support Annex and amendments thereto, dated as of January 3, 2008, between Calumet Lubricants Co., Limited Partnership and J. Aron & Company.
   
10.2*
  Collateral Trust Agreement, as amended, dated as of April 21, 2011, among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A.
   
10.3
  Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)).
   
31.1*
  Sarbanes-Oxley Section 302 certification of F. William Grube.
   
31.2*
  Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.
   
32.1*
  Section 1350 certification of F. William Grube and R. Patrick Murray, II.
   
100.INS**
  XBRL Instance Document
   
101.SCH**
  XBRL Taxonomy Extension Schema Document
   
101.CAL**
  XBRL Taxonomy Extension Calculation Linkbase Document
   
101.DEF**
  XBRL Taxonomy Extension Definition Linkbase Document
   
101.LAB**
  XBRL Taxonomy Extension Label Linkbase Document
   
101.PRE**
  XBRL Taxonomy Extension Presentation Linkbase Document
 
*   Filed herewith.
 
**   XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

59