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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal period ended December 31, 2008
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File number 000-51734
 
Calumet Specialty Products Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)
 
         
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  2911
(Primary Standard Industrial
Classification Code Number)
  37-1516132
(I.R.S. Employer
Identification Number)
 
2780 Waterfront Pkwy E. Drive
Suite 200
 
Indianapolis, Indiana 46214
(317) 328-5660
 
(Address, Including Zip Code, and Telephone Number,
Including Area Code, of Registrant’s Principal Executive Offices)
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common units representing limited partner interests   The NASDAQ Stock Market LLC
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE.
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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 Smaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ
 
The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the common units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $100.3 million on June 30, 2008, based on $14.36 per unit, the closing price of the common units as reported on the NASDAQ Global Market on such date.
 
At February 26, 2009, there were 19,166,000 common units and 13,066,000 subordinated units outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
NONE.
 


 

 
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-K — 2008 ANNUAL REPORT

Table of Contents
 
                 
        Page
 
      Business and Properties     4  
      Risk Factors     20  
      Unresolved Staff Comments     40  
      Legal Proceedings     40  
      Submission of Matters to a Vote of Security Holders     40  
 
PART II
      Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities     40  
      Selected Financial Data     47  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     52  
      Quantitative and Qualitative Disclosures About Market Risk     73  
      Financial Statements and Supplementary Data     79  
      Changes In and Disagreements With Accountants on Accounting and Financial Disclosure     146  
      Controls and Procedures     146  
      Other Information     147  
 
PART III
      Directors, Executive Officers of Our General Partner and Corporate Governance     148  
      Executive and Director Compensation     151  
      Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters     168  
      Certain Relationships, Related Party Transactions and Director Independence     170  
      Principal Accountant Fees and Services     173  
 
PART IV
      Exhibits     174  
 EX-10.18
 EX-21.1
 EX-23.01
 EX-31.1
 EX-31.2
 EX-32.1


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FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Some of the information in this annual report may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. The statements regarding (i) the Shreveport refinery expansion project’s increases in production levels, (ii) expected settlements with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental and regulatory liabilities, (iii) the future benefits and risks of the Penreco acquisition, (iv) our anticipated levels of use of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes and (v) future compliance with our debt covenants as well as other matters discussed in this Form 10-K 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 Annual Report on Form 10-K. The risk factors and other factors noted throughout this Annual Report on Form 10-K could cause our actual results to differ materially from those contained in any forward-looking statement. These factors include, but are not limited to:
 
  •  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 crude oil and crack spread price fluctuations and rapid increases or decreases, including the impact on our liquidity;
 
  •  the results of our hedging and other risk management activities;
 
  •  our ability to comply with financial covenants contained in our credit agreements;
 
  •  the availability of, and our ability to consummate, acquisition or combination opportunities;
 
  •  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 or businesses;
 
  •  environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
 
  •  maintenance of our credit rating and ability to receive open credit lines from our suppliers;
 
  •  demand for various grades of crude oil and resulting changes in pricing conditions;
 
  •  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;
 
  •  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.


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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. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. Please read Item 1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk.” We will not update these statements unless securities laws require us to do so.
 
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 Annual Report on Form 10-K to “Calumet Specialty Products Partners, L.P.,” “Calumet,” “the Partnership,” “the Company,” “we,” “our,” “us” or like terms, when used in a historical context prior to January 31, 2006, refer to the assets and liabilities of Calumet Lubricants Co., Limited Partnership and its subsidiaries of which substantially all such assets and liabilities were contributed to Calumet Specialty Products Partners, L.P. and its subsidiaries upon the completion of our initial public offering. When used in the present tense or prospectively, those terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References to “Predecessor” in this Form 10-K refer to Calumet Lubricants Co., Limited Partnership. The results of operations for the year ended December 31, 2006 for Calumet include the results of operations of the Predecessor for the period of January 1, 2006 through January 31, 2006. References in this Annual Report on Form 10-K to “our general partner” refer to Calumet GP, LLC.


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PART I
 
Items 1 and 2.   Business and Properties
 
Overview
 
We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. 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, solvents 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 unleaded 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 which are allocated to either the specialty products or fuel products segment. For 2008, approximately 73.9% of our gross profit was generated from our specialty products segment and approximately 26.1% of our gross profit was generated from our fuel products segment. The acquisition of Penreco on January 3, 2008 expanded our specialty products offering and customer base. For additional discussion of this acquisition, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Acquisition and Refinery Expansion.”
 
Our operating assets consist of our:
 
  •  Princeton Refinery.  Our Princeton refinery, located in northwest Louisiana and acquired in 1990, produces specialty lubricating oils, including process oils, base oils, transformer oils and refrigeration oils that are used in a variety of industrial and automotive applications. The Princeton refinery has aggregate crude oil throughput capacity of approximately 10,000 barrels per day (bpd) and had average daily crude oil throughput of approximately 6,500 bpd for 2008.
 
  •  Cotton Valley Refinery.  Our Cotton Valley refinery, located in northwest Louisiana and acquired in 1995, produces specialty solvents that are used principally in the manufacture of paints, cleaners and automotive products. The Cotton Valley refinery has aggregate crude oil throughput capacity of approximately 13,500 bpd and had average daily crude oil throughput of approximately 6,200 bpd for 2008.
 
  •  Shreveport Refinery.  Our Shreveport refinery, located in northwest Louisiana and acquired in 2001, produces specialty lubricating oils and waxes, as well as fuel products such as gasoline, diesel and jet fuel. The Shreveport refinery currently has aggregate crude oil throughput capacity of approximately 60,000 bpd subsequent to the completion of a major expansion project in May 2008 and had average daily crude oil throughput of approximately 37,100 bpd for 2008.
 
  •  Karns City Facility.  Our Karns City facility, located in western Pennsylvania and acquired in the Penreco acquisition, produces white mineral oils, petrolatums, solvents, gelled hydrocarbons, cable fillers, and natural petroleum sulfonates. The Karns City facility currently has aggregate feedstock throughput capacity of approximately 5,500 bpd for 2008.
 
  •  Dickinson Facility.  Our Dickinson facility, located in southeastern Texas and acquired in the Penreco acquisition, produces white mineral oils, compressor lubricants and natural petroleum sulfonates. The Dickinson facility currently has aggregate feedstock throughput capacity of approximately 1,300 bpd for 2008.
 
  •  Distribution and Logistics Assets.  We own and operate a terminal in Burnham, Illinois with a storage capacity of approximately 150,000 barrels that facilitates the distribution of product in the Upper Midwest and East Coast regions of the United States and in Canada. In addition, we lease approximately 1,700 railcars to receive crude oil or distribute our products throughout the United States and Canada. We also have approximately 6.0 million barrels of aggregate storage capacity at our facilities and leased storage locations.


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Business Strategies
 
Our management team is dedicated to improving our operations by executing the following strategies:
 
  •  Concentrate on stable cash flows.  We intend to continue to focus on businesses and assets that generate stable cash flows. Approximately 73.9% of our gross profit for 2008 was generated by the sale of specialty products, a segment of our business which is characterized by stable customer relationships due to their requirements for highly specialized products. We manage our exposure to crude oil price fluctuations in this segment by passing on incremental feedstock costs to our specialty products customers and by maintaining a shorter-term crude oil hedging program. Dramatic changes in crude oil prices, both increases and decreases, during 2008 did impact the stability of cash flows throughout the year. During the period where crude oil prices rose dramatically, our gross profit was negatively impacted as adjustments to specialty product selling prices did not keep pace with the increases in crude oil prices. During the period where crude oil prices fell dramatically, our gross profit was enhanced as reductions in crude oil prices exceeded downward adjustments to specialty products selling prices. The impacts of this volatility can best be seen in our specialty products segment gross profit on a quarterly basis as it fluctuated from $22.3 million, $21.5 million, $66.1 million and $77.7 million in the first, second, third and fourth quarters of 2008, respectively.
 
     Also, in our fuel products segment, which accounted for 26.1% of our gross profit in 2008, we seek to mitigate our exposure to fuel products margin volatility by maintaining a long-term hedging program. In summary, we believe the diversity of our products, our broad customer base and our hedging activities help contribute to the stability of our cash flows.
 
  •  Develop and expand our customer relationships.  Due to the specialized nature of, and the long lead-time associated with, the development and production of many of our specialty products, our customers have an incentive to continue their relationships with us. We believe that our larger competitors do not work with customers as we do from product design to delivery for smaller volume specialty products like ours. We intend to continue to assist our existing customers in expanding their product offerings as well as marketing specialty product formulations to new customers. By striving to maintain our long-term relationships with our existing customers and by adding new customers, we seek to limit our dependence on a small number of customers. Our Penreco acquisition provided us with an increase of approximately 1,400 customers and has enhanced our ability to expand our product offering and to meet our customers’ needs.
 
  •  Enhance profitability of our existing assets.  We continue to evaluate opportunities to improve our existing asset base to increase our throughput, profitability and cash flows. Following each of our asset acquisitions, we have undertaken projects designed to maximize the profitability of our acquired assets. We intend to further increase the profitability of our existing asset base through various measures which may include changing the product mix of our processing units, debottlenecking and expanding units as necessary to increase throughput, restarting idle assets and reducing costs by improving operations. For example, in late 2004 at the Shreveport refinery we recommissioned certain of its previously idled fuels production units, refurbished existing fuels production units, converted existing units to improve gasoline blending profitability and expanded capacity to approximately 42,000 bpd to increase lubricating oil and fuels production. Also, in December 2006, we commenced construction of an expansion project at our Shreveport refinery that was completed and operational in May 2008, to increase its aggregate crude oil throughput capacity from 42,000 bpd to approximately 60,000 bpd. For additional discussion of this project, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.”
 
  •  Pursue strategic and complementary acquisitions.  Since 1990, our management team has demonstrated the ability to identify opportunities to acquire refineries whose operations we can enhance and whose profitability we can improve. In the future, we intend to continue to make strategic acquisitions of refineries that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion. In addition, we may pursue selected acquisitions in new geographic or product areas to the extent we perceive similar opportunities. For example, on January 3, 2008, we acquired Penreco from ConocoPhillips Company (“ConocoPhillips”) and M.E. Zukerman Specialty Oil Corporation for a purchase price of approximately $269.1 million. For additional discussion of this project, please read Item 7


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  “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.”
 
Competitive Strengths
 
We believe that we are well positioned to execute our business strategies successfully based on the following competitive strengths:
 
  •  We offer our customers a diverse range of specialty products.  We offer a wide range of over 750 specialty products. We believe that our ability to provide our customers with a more diverse selection of products than our competitors generally gives us an advantage in competing for new business. We believe that we are the only specialty products manufacturer that produces all four of naphthenic lubricating oils, paraffinic lubricating oils, waxes and solvents. A contributing factor to our ability to produce numerous specialty products is our ability to ship products between our facilities for product upgrading in order to meet customer specifications.
 
  •  We have strong relationships with a broad customer base.  We have long-term relationships with many of our customers, and we believe that we will continue to benefit from these relationships. Our customer base includes over 2,400 companies and we are continually seeking new customers. No single specialty products customer accounts for more that 10% of our consolidated sales.
 
  •  Our facilities have advanced technology.  Our facilities are equipped with advanced, flexible technology that allows us to produce high-grade specialty products and to produce fuel products that comply with new low sulfur fuel regulations. For example, our Shreveport and Cotton Valley refineries have the capability to make all of their low sulfur diesel into ultra low sulfur diesel and all of the Shreveport refinery’s gasoline production meets low sulfur standards set by the U.S. Environmental Protection Agency (“EPA”). Also, unlike larger refineries, which lack some of the equipment necessary to achieve the narrow distillation ranges associated with the production of specialty products, our operations are capable of producing a wide range of products tailored to our customers’ needs. We have also upgraded the operations of many of our assets through our investment in advanced, computerized refinery process controls.
 
  •  We have an experienced management team.  Our management has a proven track record of enhancing value through the acquisition, exploitation and integration of refining assets and the development and marketing of specialty products. Our senior management team, the majority of whom have been working together since 1990, has an average of over 25 years of industry experience. Our team’s extensive experience and contacts within the refining industry provide a strong foundation and focus for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing and enhancing the profitability of new assets.
 
Our Operating Assets
 
General
 
We own and operate facilities in northwest Louisiana, which consist of the Princeton refinery, the Cotton Valley refinery and the Shreveport refinery, facilities in Karns City, Pennsylvania and Dickinson, Texas as well as a terminal in Burnham, Illinois.


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The following table sets forth information about our combined operations. Production volume differs from sales volume due to changes in inventory. The following table does not include operations of our Karns City, Pennsylvania and Dickinson, Texas facilities for 2007 and 2006, as we did not acquire these facilities until January 3, 2008 with the acquisition of Penreco.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
          (In bpd)        
 
Total sales volume (1)
    56,232       47,663       50,345  
Total feedstock runs (2)
    56,243       48,354       51,598  
Production:
                       
Specialty products:
                       
Lubricating oils
    12,462       10,734       11,436  
Solvents
    8,130       5,104       5,361  
Waxes
    1,736       1,177       1,157  
Fuels
    1,208       1,951       2,038  
Asphalt and other by-products
    6,623       6,157       6,596  
                         
Total
    30,159       25,123       26,588  
                         
Fuel products:
                       
Gasoline
    8,476       7,780       9,430  
Diesel
    10,407       5,736       6,823  
Jet fuel
    5,918       7,749       6,911  
By-products
    370       1,348       461  
                         
Total
    25,171       22,613       23,625  
                         
Total production (3)
    55,330       47,736       50,213  
                         
 
 
(1) Total sales volume includes sales from the production of our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements, and sales of inventories.
 
(2) Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our facilities and, beginning in 2008, at certain third-party facilities pursuant to supply and/or processing agreements. The increase in feedstock runs for 2008 is primarily due to the acquisition of the Karns City, PA and the Dickinson, TX facilities as part of the Penreco acquisition and the completion of the Shreveport expansion project in May 2008. These increases were offset by decreases in production rates in the fourth quarter due to scheduled turnarounds at our Princeton, Cotton Valley and Shreveport refineries.
 
(3) Total production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and, beginning in 2008, at certain third-party facilities pursuant to supply and/or processing agreements. The difference between total production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.


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Set forth below is information regarding sales of our principal products by segment.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In millions)  
 
Sales of specialty products:
                       
Lubricating oils
  $ 841.2     $ 478.1     $ 509.9  
Solvents
    419.8       199.8       201.9  
Waxes
    142.5       61.6       61.2  
Fuels
    30.4       52.5       41.3  
Asphalt and other by-products
    144.1       74.7       98.8  
                         
Total
    1,578.0       866.7       913.1  
                         
Sales of fuel products:
                       
Gasoline
  $ 332.7     $ 307.1     $ 336.7  
Diesel
    379.7       203.7       207.1  
Jet fuel
    186.7       225.9       176.4  
By-products
    11.9       34.4       7.7  
                         
Total
    911.0       771.1       727.9  
                         
Consolidated sales
  $ 2,489.0     $ 1,637.8     $ 1,641.0  
                         
 
Princeton Refinery
 
The Princeton refinery, located on a 208-acre site in Princeton, Louisiana, has aggregate crude oil throughput capacity of 10,000 bpd and is currently processing naphthenic crude oil into lubricating oils, high sulfur diesel and asphalt. The high sulfur diesel may be blended to produce certain lubricating oils, transported to the Shreveport refinery for further processing into ultra low sulfur diesel or sold to third parties. The asphalt may be processed or blended for coating and roofing applications at the Princeton refinery or transported to the Shreveport refinery for processing into bright stock.
 
The Princeton refinery currently consists of seven major processing units, approximately 650,000 barrels of storage capacity in 200 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Princeton refinery in 1990, we have debottlenecked the crude unit to increase production capacity to 10,000 bpd, increased the hydrotreater’s capacity to 7,000 bpd and upgraded the refinery’s fractionation unit, which has enabled us to produce higher value specialty products. The following table sets forth historical information about production at our Princeton refinery.
 
                         
    Princeton Refinery  
    Year Ended December 31,  
    2008     2007     2006  
    (In bpd)  
 
Crude oil throughput capacity
    10,000       10,000       10,000  
Total feedstock runs (1)
    6,516       7,226       7,574  
Total refinery production (1)
    6,551       7,198       7,543  
 
 
(1) Total refinery production represents the barrels per day of specialty products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.
 
The Princeton refinery has a hydrotreater and significant fractionation capability enabling the refining of high quality naphthenic lubricating oils at numerous distillation ranges. The Princeton refinery’s processing capabilities consist of atmospheric and vacuum distillation, hydrotreating, asphalt oxidation processing and clay/acid treating


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facilities. In addition, we have the necessary tankage and technology to process our asphalt into higher value applications like coatings and road paving applications.
 
The Princeton refinery receives crude oil via tank truck, railcar and pipeline. Its crude oil supply primarily originates from east Texas and north Louisiana and is purchased through Legacy Resources Co., L.P. (“Legacy Resources”), a related party. See Item 13 “Certain Relationships, Related Party Transactions and Director Independence — Crude Oil Purchases” for additional information regarding our crude oil purchases from Legacy Resources. The Princeton refinery ships its finished products throughout the country by both truck and railcar service.
 
Cotton Valley Refinery
 
The Cotton Valley refinery, located on a 77-acre site in Cotton Valley, Louisiana, has aggregate crude oil throughput capacity of 13,500 bpd, hydrotreating capacity of 5,100 bpd and is currently processing crude oil into solvents, low sulfur diesel, fuel feedstocks and residual fuel oil. The residual fuel oil is an important feedstock for specialty refined products at our Shreveport refinery. We believe the Cotton Valley refinery produces the most complete, single-facility line of paraffinic solvents in the United States.
 
The Cotton Valley refinery currently consists of three major processing units that include a crude unit, a hydrotreater and a fractionation train, approximately 625,000 barrels of storage capacity in 74 storage tanks and related loading and unloading facilities and utilities. The Cotton Valley refinery also has a utility fractionator for batch processing of narrow distillation range specialty solvents. Since its acquisition in 1995, we have expanded the refinery’s capabilities by installing a hydrotreater that removes aromatics, increased the crude unit processing capability to 13,500 bpd and reconfigured the refinery’s fractionation train to improve product quality, enhance flexibility and lower utility costs. The following table sets forth historical information about production at our Cotton Valley refinery.
 
                         
    Cotton Valley Refinery  
    Year Ended December 31,  
    2008     2007     2006  
    (In bpd)  
 
Crude oil throughput capacity
    13,500       13,500       13,500  
Total feedstock runs (1)(2)
    6,175       6,775       7,130  
Total refinery production (2)(3)
    6,757       7,573       7,720  
 
 
(1) Total feedstock runs do not include certain interplant solvent feedstocks supplied by our Shreveport refinery.
 
(2) Total refinery production represents the barrels per day of specialty products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.
 
(3) Total refinery production includes certain interplant solvent feedstocks supplied to our Shreveport refinery.
 
The Cotton Valley configuration is flexible, which allows us to respond to market changes and customer demands by modifying its product mix. The reconfigured fractionation train also allows the refinery to satisfy demand fluctuations efficiently without large product inventory requirements.
 
The Cotton Valley refinery receives crude oil via truck and through a pipeline system operated by a subsidiary of Plains All American Pipeline, L.P. (“Plains”). Cotton Valley’s feedstock is primarily low sulfur, paraffinic crude oil originating from north Louisiana and is purchased from various marketers and gatherers. In addition, the refinery receives feedstocks for solvent production from the Shreveport refinery. The Cotton Valley refinery ships finished products throughout the country by both truck and railcar service.
 
Shreveport Refinery
 
The Shreveport refinery, located on a 240-acre site in Shreveport, Louisiana, currently has aggregate crude oil throughput capacity of 60,000 bpd subsequent to the completion of a major expansion project in May 2008 and is


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currently processing paraffinic crude oil and associated feedstocks into fuel products, paraffinic lubricating oils, waxes, residuals, and by-products.
 
The Shreveport refinery currently consists of 16 major processing units, approximately 3.4 million barrels of storage capacity in 141 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Shreveport refinery in 2001, we have expanded the refinery’s capabilities by adding additional processing and blending facilities, added a second reactor to the high pressure hydrotreater, resumed production of gasoline, diesel and other fuel products at the refinery, and added both 18,000 bpd of capacity and the capability to run up to 25,000 bpd of sour crude oil with the expansion project completed in May 2008. The following table sets forth historical information about production at our Shreveport refinery.
 
                         
    Shreveport Refinery  
    Year Ended December 31,  
    2008     2007     2006  
    (In bpd)  
 
Crude oil throughput capacity
    60,000       42,000       42,000  
Total feedstock runs (1)(2)
    37,096       34,352       36,894  
Total refinery production (2)(3)
    35,566       32,819       34,950  
 
 
(1) Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Shreveport refinery. The increase in feedstock runs for 2008 was primarily due to the completion of the expansion project in May 2008, offset by decreases in production rates in the fourth quarter of 2008 due to a scheduled turnaround.
 
(2) Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.
 
(3) Total refinery production includes certain interplant solvent feedstocks supplied to our Cotton Valley refinery.
 
We completed an expansion project in May 2008 that increased our Shreveport refinery’s aggregate crude oil throughput capacity from approximately 42,000 bpd to approximately 60,000 bpd. For further discussion of this project, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.”
 
The Shreveport refinery has a flexible operational configuration and operating personnel that facilitate development of new product opportunities. Product mix may fluctuate from one period to the next to capture market opportunities. The refinery has an idle residual fluid catalytic cracking unit, alkylation unit, vacuum tower and a number of idle towers that can be utilized for future project needs. Certain idle towers were utilized as a part of the Shreveport refinery expansion project discussed above.
 
The Shreveport refinery currently makes jet fuel, low sulfur diesel and ultra low sulfur diesel and all of its gasoline production currently meets low sulfur standards.
 
The Shreveport refinery receives crude oil from common carrier pipeline systems operated by subsidiaries of Plains and Exxon Mobil Corporation (“ExxonMobil”), each of which are connected to the Shreveport refinery’s facilities. The Plains pipeline system delivers local supplies of crude oil and condensates from north Louisiana and east Texas. The ExxonMobil pipeline system delivers domestic crude oil supplies from south Louisiana and foreign crude oil supplies from the Louisiana Offshore Oil Port (“LOOP”) or other crude oil terminals. In addition, trucks deliver crude oil gathered from local producers to the Shreveport refinery.
 
The Shreveport refinery has direct pipeline access to the TEPPCO Products Partners pipeline (“TEPPCO pipeline”), over which it can ship all grades of gasoline, diesel and jet fuel. The refinery also has direct access to the Red River Terminal facility, which provides the refinery with barge access, via the Red River, to major feedstock and petroleum products logistics networks on the Mississippi River and Gulf Coast inland waterway system. The Shreveport refinery also ships its finished products throughout the country through both truck and railcar service.


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Karns City Facility
 
The Karns City facility, located on a 225-acre site in Karns City, Pennsylvania, currently has aggregate base oil throughput of 5,500 bpd and is currently processing white mineral oils, petrolatums, solvents, gelled hydrocarbons, cable fillers, and natural petroleum sulfonates. The Karns City facility consists of seven major processing units including hydrotreating, bender treating, fractionation, acid treating, filtering and blending, approximately 817,000 barrels of storage capacity in 309 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks by rail and truck under long-term supply agreements with various suppliers, the most significant of which is ConocoPhillips. Please read “— Crude Oil and Feedstock Supply” for further discussion of the long-term supply agreements with ConocoPhillips.
 
Dickinson Facility
 
The Dickinson facility, located on a 28-acre site in Dickinson, Texas, currently has aggregate base oil throughput of 1,300 bpd and is currently processing white mineral oils, compressor lubricants, and natural petroleum sulfonates. The Dickinson facility consists of three major processing units including acid treating, filtering, and blending, approximately 183,000 barrels of storage capacity in 186 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks by rail and truck under long-term supply agreements with various suppliers, the most significant of which is ConocoPhillips. Please read “— Crude Oil and Feedstock Supply” for further discussion of the long-term supply agreements with ConocoPhillips.
 
The following table sets forth the combined historical information about production at our Karns City and Dickinson facilities.
 
         
    Combined Karns City
 
    and Dickinson Facilities
 
    Year Ended
 
    December 31, 2008  
    (in bpd)  
 
Feedstock throughput capacity (1)
    6,800  
Total feedstock runs (2)
    6,456  
Total production (3)
    6,456  
 
 
(1) Includes Karns City and Dickinson facilities only.
 
(2) Includes runs of feedstocks at our Karns City and Dickinson facilities as well as throughput at certain third-party facilities pursuant to supply and/or processing agreements.
 
(3) Total production represents the barrels per day of specialty products yielded from processing feedstocks at our Karns City and Dickinson facilities and certain third-party facilities pursuant to supply and/or processing agreements. The difference between total production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and the production of finished products.
 
Burnham Terminal and Other Logistics Assets
 
We own and operate a terminal in Burnham, Illinois. The Burnham terminal receives specialty products from each of our refineries and distributes them by truck to our customers in the Upper Midwest and East Coast regions of the United States and in Canada.
 
The terminal includes a tank farm with 67 tanks with aggregate lubricating oil, solvent and specialty product storage capacity of approximately 150,000 barrels as well as blending equipment. The Burnham terminal is complementary to our refineries and plays a key role in moving our products to the end-user market by providing the following services:
 
  •  distribution;
 
  •  blending to achieve specified products; and
 
  •  storage and inventory management.


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We also lease a fleet of approximately 1,700 railcars from various lessors. This fleet enables us to receive crude oil and distribute various specialty products throughout the United States and Canada to and from each of our facilities.
 
Crude Oil and Feedstock Supply
 
We purchase crude oil from major oil companies, various gatherers and marketers in east Texas and north Louisiana and from Legacy Resources, an affiliate of our general partner. The Shreveport refinery also receives crude oil through the ExxonMobil pipeline system originating in St. James, Louisiana, which provides the refinery with access to domestic crude oils and foreign crude oils through the LOOP or other terminal locations.
 
In 2008, we purchased 49.4% of our crude oil supply through evergreen crude oil supply contracts, which are typically terminable on 30 days’ notice by either party, approximately 38.3% of our crude oil supply from a subsidiary of Plains under a term contract that became evergreen in July 2008, and the remaining 4.6% of our crude oil supply on the spot market. Legacy Resources supplied us with 7.7% of our crude oil in 2008. In addition, we are purchasing additional crude oil from Legacy Resources in 2009 for our Shreveport refinery. Refer to Item 13, “Certain Relationships, Related Party Transactions and Director Independence — Crude Oil Purchases” for further information on our related party crude oil purchases. We also purchase foreign crude oil when its spot market price is attractive relative to the price of crude oil from domestic sources. We believe that adequate supplies of crude oil will continue to be available to us.
 
Our cost to acquire feedstocks and the price for which we ultimately can sell refined products depend on a number of factors beyond our control, including regional and global supply of and demand for crude oil and other feedstocks and specialty and fuel products. These in turn are dependent upon, among other things, the availability of imports, overall economic conditions, the production levels of domestic and foreign suppliers, U.S. relationships with foreign governments, political affairs and the extent of governmental regulation. We have historically been able to pass on the costs associated with increased feedstock prices to our specialty products customers, although the increase in selling prices for specialty products typically lags the rising cost of crude oil. We use a hedging program to manage a portion of this commodity price risk. Please read Item 7A “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk — Crude Oil Hedging Policy” for a discussion of our crude oil hedging program.
 
We have various long-term supply agreements with ConocoPhillips, with remaining terms ranging from 2 to 9 years, for feedstocks that are key to the operations of our Karns City and Dickinson facilities. In addition, certain products of our refineries can be used as feedstocks by these facilities. We believe that adequate supplies of feedstocks are available for these facilities.
 
Markets and Customers
 
We produce a full line of specialty products, including lubricating oils, solvents and waxes. Our customers purchase these products primarily as raw material components for basic industrial, consumer and automotive goods. We also produce a variety of fuel products.
 
We have an experienced marketing department with an average industry tenure of 20 years. Our salespeople regularly visit customers and our marketing department works closely with both the laboratories at our refineries and our technical department to help create specialized blends that will work optimally for our customers.
 
Markets
 
Specialty Products.  The specialty products market represents a small portion of the overall petroleum refining industry in the United States. Of the nearly 150 refineries currently in operation in the United States, only a small number of the refineries are considered specialty products producers and only a few compete with us in terms of the number of products produced.


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Our specialty products are utilized in applications across a broad range of industries, including in:
 
  •  industrial goods such as metal working fluids, belts, hoses, sealing systems, batteries, hot melt adhesives, pressure sensitive tapes, electrical transformers and refrigeration compressors;
 
  •  consumer goods such as candles, petroleum jelly, creams, tonics, lotions, coating on paper cups, chewing gum base, automotive aftermarket car-care products (fuel injection cleaners, tire shines and polishes), lamp oils, charcoal lighter fluids, camping fuel and various aerosol products; and
 
  •  automotive goods such as motor oils, greases, transmission fluid and tires.
 
We have the capability to ship our specialty products worldwide. In the United States and Canada, we ship our specialty products via railcars, trucks and barges. In 2008, about 45.5% of our specialty products were shipped in our fleet of approximately 1,700 leased railcars, about 51.2% of our specialty products shipped in trucks owned and operated by several different third-party carriers and the remaining 3.3% were shipped via water transportation. For shipments outside of North America, which accounted for less than 10% of our consolidated sales in 2008, we ship railcars to several ports where the product is loaded on ships for the customer.
 
Fuel Products.  We produce a variety of fuel and fuel-related products, primarily at our Shreveport refinery.
 
Fuel products produced at the Shreveport refinery can be sold locally or through the TEPPCO pipeline. Local sales are made in the TEPPCO terminal in Bossier City, Louisiana, which is approximately 15 miles from the Shreveport refinery, as well as from our own refinery terminal. Any excess volumes are sold to marketers further up the TEPPCO pipeline.
 
During 2008, we sold approximately 9,400 bpd of gasoline into the Louisiana, Texas and Arkansas markets, and any excess volumes to marketers further up the TEPPCO pipeline. Should the appropriate market conditions arise, we have the capability to redirect and sell additional volumes into the Louisiana, Texas and Arkansas markets rather than transport them to the Midwest. Similar market conditions exist for our diesel production. We sell the majority of our diesel locally but, similar to gasoline, we occasionally sell the excess volumes to marketers further up the TEPPCO pipeline during times of high diesel production or for competitive reasons.
 
The Shreveport refinery also has the capacity to produce about 9,000 bpd of commercial jet fuel that can be marketed to the Barksdale Air Force Base in Bossier City, Louisiana, sold as Jet-A locally or via the TEPPCO pipeline, or transferred to the Cotton Valley refinery to be used as a feedstock to produce solvents. Jet fuel sales volumes change as the margins between diesel and jet fuel change. We have a sales contract with the U.S. Department of Defense covering the Barksdale Air Force Base for approximately 1,500 bpd of jet fuel. This contract is effective until April 2009 and is bid annually.
 
Additionally, we produce a number of fuel-related products including fluid catalytic cracking (“FCC”) feedstock, asphalt vacuum residuals and mixed butanes.
 
Vacuum residuals are blended or processed further to make specialty asphalt products. Volumes of vacuum residuals which we cannot process are sold locally into the fuel oil market or sold via railcar to other producers. FCC feedstock is sold to other refiners as a feedstock for their FCC units to make fuel products. Butanes are primarily available in the summer months and are primarily sold to local marketers. If the butanes are not sold they are blended into our gasoline production.
 
Customers
 
Specialty Products.  We have a diverse customer base for our specialty products, with approximately 2,400 active accounts. Most of our customers are long-term customers who use our products in specialty applications which require six months to two years to gain approval for use in their products. No single customer of our specialty products segment accounts for more that 10% of our consolidated sales.
 
Fuel Products.  We have a diverse customer base for our fuel products, with approximately 60 active accounts. We are able to sell the majority of the fuel products we produce to the local markets of Louisiana, east Texas and Arkansas. We also have the ability to ship our fuel products to the Midwest through the TEPPCO pipeline should the need arise. During the year ended December 31, 2008, the fuel products segment had one customer,


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Murphy Oil U.S.A., which represented approximately 10.5% of consolidated sales due to rising gasoline and diesel prices and increased fuel products sales to this customer. No other fuel products segment customer represented 10% or greater of consolidated sales in each of the three years ended December 31, 2008, 2007 and 2006.
 
Safety and Maintenance
 
We perform preventive and normal maintenance on all of our refining and logistics assets and make repairs and replacements when necessary or appropriate. We also conduct inspections of our assets as required by law or regulation.
 
We are subject to the requirements of Federal Occupational Safety and Health Act (“OSHA”) and comparable state occupational safety statutes. We believe that we have operated in substantial compliance with OSHA requirements, including general industry standards, recordkeeping and reporting, hazard communication and process safety management. We have implemented a quality system that meets the requirements of the QS 9000/ISO-9002 Standard. The integrity of our certification is maintained through surveillance audits by our registrar at regular intervals designed to ensure adherence to the standards. The nature of our business may result in industrial accidents from time to time. It is possible that changes in safety and health regulations or a finding of non-compliance with current regulations could result in additional capital expenditures or operating expenses, as well as fines and penalties.
 
Competition
 
Competition in our markets is from a combination of large, integrated petroleum companies, independent refiners and wax production companies. Many of our competitors are substantially larger than us and are engaged on a national or international basis in many segments of the petroleum products business, including refining, transportation and marketing. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We distinguish our competitors according to the products that they produce. Set forth below is a description of our significant competitors according to product category.
 
Naphthenic Lubricating Oils.  Our primary competitor in producing naphthenic lubricating oils is Ergon Refining, Inc. We also compete with Cross Oil Refining and Marketing, Inc. and San Joaquin Refining Co., Inc.
 
Paraffinic Lubricating Oils.  Our primary competitors in producing paraffinic lubricating oils include ExxonMobil, Motiva Enterprises, LLC, ConocoPhillips, Sunoco Lubricants & Special Products and Sonneborn Refined Products.
 
Paraffin Waxes.  Our primary competitors in producing paraffin waxes include ExxonMobil and The International Group Inc.
 
Solvents.  Our primary competitors in producing solvents include Citgo Petroleum Corporation, Ashland Inc. and ConocoPhillips.
 
Fuel Products.  Our competitors in producing fuels products in the local markets in which we operate include Delek Refining, Ltd. and Lion Oil Company.
 
Our ability to compete effectively depends on our responsiveness to customer needs and our ability to maintain competitive prices and product offerings. We believe that our flexibility and customer responsiveness differentiate us from many of our larger competitors. However, it is possible that new or existing competitors could enter the markets in which we operate, which could negatively affect our financial performance.
 
During 2008, two of our competitors, Citgo Petroleum Corporation and Ashland Inc. announced and have completed plans to cease production of certain specialty product lines, including paraffinic lubricating oils, waxes and solvents at certain of their facilities, thereby reducing overall supply capacity in the specialty products market.


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Environmental Matters
 
We operate 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 our 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 on us for pollution resulting from our 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 limiting or prohibiting some or all of our operations. On occasion, we receive notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. In particular, the Louisiana Department of Environmental Quality (“LDEQ”) has proposed penalties totaling approximately $0.4 million and supplemental projects 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 our 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 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 LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emission levels. We anticipate that any penalties that may be assessed due to the alleged violations at our Princeton refinery as well as the aforementioned penalties related to the Cotton Valley refinery will be consolidated in a settlement agreement that we anticipate executing with the LDEQ in connection with the agency’s “Small Refinery and Single Site Refinery Initiative” described below.
 
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, in connection with accidental spills or releases associated with our operations, we cannot assure our unitholders that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with these requirements will not have a material adverse effect on us, there can be no assurance that our environmental compliance expenditures will not become material in the future.
 
Air
 
Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws. The Clean Air Act Amendments of 1990 require most industrial operations in the U.S. to incur capital expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. Under the Clean Air Act, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. In addition, the petroleum refining sector has come under stringent new EPA regulations, imposing maximum achievable control technology (“MACT”) on refinery equipment emitting certain listed hazardous air pollutants. Some of our facilities have been included within the categories of sources regulated by MACT rules. In addition, air permits are required for our refining and terminal operations that result in the emission of regulated air contaminants. These permits incorporate stringent control technology requirements and are subject to extensive


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review and periodic renewal. Excluding consideration of the alleged air violations discussed in this Environmental Matters section for which we are currently discussing settlement with the LDEQ, we believe that we are in substantial compliance with the Clean Air Act and similar state and local laws.
 
The Clean Air Act authorizes the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with the fuel product’s final use. For example, in December 1999, the EPA promulgated regulations limiting the sulfur content allowed in gasoline. These regulations required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those Western states exhibiting lesser air quality problems. Similarly, the EPA promulgated regulations that limit the sulfur content of highway diesel beginning in 2006 from its former level of 500 parts per million (“ppm”) to 15 ppm (the “ultra low sulfur standard”). The Shreveport refinery has implemented the sulfur standard with respect to gasoline in its production and produces diesel meeting the ultra low sulfur standard.
 
We are party to ongoing discussions on a voluntary basis with the LDEQ regarding the Company’s participation in that agency’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. We expect that the LDEQ’s primary focus under the state initiative will be on four compliance and enforcement concerns: (i) Prevention of Significant Deterioration/New Source Review; (ii) New Source Performance Standards for fuel gas combustion devices, including flares, heaters and boilers; (iii) Leak Detection and Repair requirements; and (iv) Benzene Waste Operations National Emission Standards for Hazardous Air Pollutants. We are in discussions with the LDEQ regarding our participation in this regulatory initiative and anticipate that we will be entering into a settlement agreement with the LDEQ pursuant to which we will be required to make emissions reductions requiring capital investments between approximately $1.0 million and $3.0 million in total over a three to five year period at our three Louisiana refineries. Because the settlement agreement is also expected to resolve the alleged air emissions issues at our Cotton Valley and Princeton refineries and consolidate any penalties associated with such issues, we further anticipate that a penalty of approximately $0.4 million will be assessed in connection with this settlement agreement.
 
We also are in separate discussions with the EPA to resolve alleged deficiencies in risk management planning in connection with a fire-related incident arising out of tank cleaning and vacuum truck operations at our Shreveport refinery on October 30, 2008. The incident involved a third-party contractor and resulted in damage to an on-site aboveground storage tank. Following an investigation of the matter, the EPA issued five violations against us, alleging, among other things, inadequate contractor training and oversight, and has proposed a penalty of $0.2 million. We are currently evaluating our response to the EPA with respect to the matter.
 
Climate Change
 
Recent studies suggest that emissions of carbon dioxide and certain other gases, referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. In response, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The most frequently utilized model for greenhouse gas emission control is a market-based cap-and-trade system, wherein regulated companies are required to obtain and surrender government-issued emission “allowances” based on the amount of greenhouse gases attributable to their facilities. Depending on how such allowances are allocated (i.e., for free or by auction), and whether a company has enough allowances to cover its greenhouse gas emissions, a company may be required to purchase allowances on the open market.
 
One form of cap-and-trade system that has been proposed is an “upstream” cap-and-trade system, wherein fuel producers, including refiners, would be required to maintain emission allowances covering the greenhouse gas emissions attributable to the combustion of their products. Were an upstream cap-and-trade system to be adopted at either the state, regional, or federal level, we could be required to purchase and surrender allowances for the greenhouse gas emissions attributable to the combustion of the fuels we produce. Although we would not be


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impacted to a greater degree than other similarly situated refiners of oil, a stringent greenhouse gas control program could have an adverse effect on our operations, financial condition, and cash flows.
 
Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could also have an adverse effect on our cost of doing business and demand for the oil we refine.
 
Hazardous Substances and Wastes
 
The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our operations, we generate wastes or handle substances that may be regulated as hazardous substances, and we could become subject to liability under CERCLA and comparable state laws.
 
We also may incur liability under the Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose requirements related to the handling, storage, treatment, and disposal of solid and hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes. In addition, our operations also generate solid wastes, which are regulated under RCRA and state law. We believe that we are in substantial compliance with the existing requirements of RCRA and similar state and local laws, and the cost involved in complying with these requirements is not material.
 
We currently own or operate, and have in the past owned or operated, properties that for many years have been used for refining and terminal activities. These properties have in the past been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes have been released on or under the properties owned or operated by us. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.
 
Voluntary remediation of subsurface contamination is in process at each of our refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, we believe that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on our financial condition. However, such costs are often unpredictable and, therefore, there


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can be no assurance that the future costs will not become material. During 2008, we determined that we will incur costs of approximately $0.7 million during 2009 at our Cotton Valley refinery in connection with continued remediation of groundwater impacts at that site.
 
Water
 
The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. Such discharges are prohibited, except in accordance with the terms of a permit issued by the EPA or the appropriate state agencies. Any unpermitted release of pollutants, including crude or hydrocarbon specialty oils as well as refined products, could result in penalties, as well as significant remedial obligations. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. We believe that we are in substantial compliance with the requirements of the Clean Water Act.
 
The primary federal law for oil spill liability is the Oil Pollution Act of 1990, as amended (“OPA”), which addresses three principal areas of oil pollution — prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including refineries, terminals, and associated facilities that may affect waters of the U.S. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages from oil spills. We believe that we are in substantial compliance with OPA and similar state laws.
 
Health and Safety
 
We are 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 our operations and that this information be provided to employees, state and local government authorities and citizens. We maintain safety, training, and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Our compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. We have commissioned studies to assess the adequacy of our process safety management practices at our Shreveport refinery. Depending on the findings made in these studies, we may incur capital expenditures over the next several years to enhance these practices so that we may maintain our compliance with applicable OSHA regulations at this refinery. While we do not expect these expenditures to be material at this time, we have not yet received the reports from the engineering firms conducting the studies to reach final resolution. We believe that our operations are in substantial compliance with OSHA and similar state laws.
 
Other Environmental Items
 
We are indemnified by Shell Oil Company, as successor to Pennzoil-Quaker State Company and Atlas Processing Company, for specified environmental liabilities arising from operations of the Shreveport refinery prior to our acquisition of the facility. The indemnity is unlimited in amount and duration, but requires us to contribute up to $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities.
 
We are indemnified on a limited basis by ConocoPhillips and M.E. Zuckerman Specialty Oil Corporation, former owners of Penreco, for pending, threatened, contemplated or contingent environmental claims against Penreco of which we were unaware upon our acquisition of Penreco. A significant portion of these indemnifications will expire in January 2010 without any claims having been asserted by us and are generally subject to a $2.0 million limit.
 
Insurance
 
Our operations are subject to certain hazards of operations, including fire, explosion and weather-related perils. We maintain insurance policies, including business interruption insurance for each of our facilities, with


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insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.
 
Seasonality
 
The operating results for the fuel products segment and the selling prices of asphalt products we produce can be seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters due to the seasonality of annual road construction. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year as a result of this seasonality.
 
Title to Properties
 
We own the following properties, which are pledged as collateral under our existing credit facilities as discussed in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Debt and Credit Facilities.”
 
         
    Acres   Location
 
Shreveport refinery
  240   Shreveport, Louisiana
Princeton refinery
  208   Princeton, Louisiana
Cotton Valley refinery
  77   Cotton Valley, Louisiana
Burnham terminal
  11   Burnham, Illinois
Karns City facility
  225   Karns City, Pennsylvania
Dickinson facility
  28   Dickinson, Texas
 
Office Facilities
 
In addition to our refineries and terminal discussed above, we occupy approximately 26,900 square feet of office space in Indianapolis, Indiana under a lease and approximately 14,500 square feet of office space in The Woodlands, Texas under a lease as a result of the Penreco acquisition that we are currently not using. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed. We expect that we will not renew our lease of our facility in The Woodlands, Texas at its expiration on April 30, 2012 and are actively engaged in efforts to sublease this office space for the remainder of the lease term.
 
Employees
 
As of February 26, 2009, our general partner employs approximately 640 people who provide direct support to the Company’s operations. Of these employees, approximately 360 are covered by collective bargaining agreements, including approximately 140 employees at the facilities acquired in the Penreco acquisition. Employees at the Princeton and Cotton Valley refineries are covered by separate collective bargaining agreements with the International Union of Operating Engineers, having expiration dates of October 31, 2011 and March 31, 2010, respectively. Employees at the Shreveport refinery are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial, and Service Workers International Union which expires on April 30, 2010. The Karns City, Pennsylvania facility employees are covered by a collective bargaining agreement with United Steel Workers that will expire on January 31, 2012. The Dickinson, Texas facility employees are covered by a collective bargaining agreement with the International Union of Operating Engineers that will expire in March 31, 2010. None of the employees at the Burnham terminal are


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covered by collective bargaining agreements. Our general partner considers its employee relations to be good, with no history of work stoppages.
 
Address, Internet Website and Availability of Public Filings
 
Our principal executive offices are located at 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, Indiana 46214 and our telephone number is (317) 328-5660. Our website is located at http://www.calumetspecialty.com.
 
We make the following information available free of charge on our website:
 
  •  Annual Report on Form 10-K;
 
  •  Quarterly Reports on Form 10-Q;
 
  •  Current Reports on Form 8-K;
 
  •  Amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934;
 
  •  Charters for the Audit, Compensation and Conflicts Committees; and
 
  •  Code of Business Conduct and Ethics.
 
Our Securities and Exchange Commission (“SEC”) filings are available on our website as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. The above information is available in print to anyone who requests it and is free of charge.
 
Item 1A.   Risk Factors
 
We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
We may not have sufficient available cash from operations each quarter to enable us to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay expenses, including payments to our general partner, and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which is primarily dependent upon our producing and selling quantities of fuel and specialty products, or refined products, at margins that are high enough to cover our fixed and variable expenses. Crude oil costs, fuel and specialty products prices and, accordingly, the cash we generate from operations, will fluctuate from quarter to quarter based on, among other things:
 
  •  overall demand for specialty hydrocarbon products, fuel and other refined products;
 
  •  the level of foreign and domestic production of crude oil and refined products;
 
  •  our ability to produce fuel and specialty products that meet our customers’ unique and precise specifications;
 
  •  the marketing of alternative and competing products;
 
  •  the extent of government regulation;
 
  •  results of our hedging activities; and
 
  •  overall economic and local market conditions.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
  •  the level of capital expenditures we make, including those for acquisitions, if any;
 
  •  our debt service requirements;


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  •  fluctuations in our working capital needs;
 
  •  our ability to borrow funds and access capital markets;
 
  •  restrictions on distributions and on our ability to make working capital borrowings for distributions contained in our credit facilities; and
 
  •  the amount of cash reserves established by our general partner for the proper conduct of our business.
 
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.
 
Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.
 
Further 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, either of which would adversely affect our liquidity, financial condition and our ability to distribute cash to our unitholders.
 
The borrowing base under our revolving credit facility is redetermined weekly or monthly depending upon availability levels. 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 our 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, we may be required by our lenders to take steps to reduce our leverage, pay off our debts on an accelerated basis, limit or eliminate distributions to our unitholders or take other similar measures. In addition, as a result of further decreases in the price of crude oil, we may be required to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our hedging positions. At December 31, 2008, we had $51.9 million in availability under our revolving credit facility. Please read Item 7 “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 would have a material adverse effect on our liquidity, financial condition and our ability to distribute cash to our unitholders.
 
Our credit agreements contain operating and financial restrictions that may restrict our business and financing activities.
 
The operating and financial restrictions and covenants in our credit agreements 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. For example, our credit agreements restrict our ability to:
 
  •  pay distributions;
 
  •  incur indebtedness;
 
  •  grant liens;
 
  •  make certain acquisitions and investments;
 
  •  make capital expenditures above specified amounts;
 
  •  redeem or prepay other debt or make other restricted payments;
 
  •  enter into transactions with affiliates;
 
  •  enter into a merger, consolidation or sale of assets; and
 
  •  cease our crack spread hedging program.


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Our ability to comply with the covenants and restrictions contained in our credit agreements may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions may be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreements are secured by substantially all of our assets and if we are unable to repay our indebtedness under our credit agreements, the lenders could seek to foreclose on our assets.
 
The new senior secured term loan credit agreement and amendment to our existing revolving credit facility that we executed on January 3, 2008 contain operating and financial restrictions similar to the above listed items. Financial covenants in the term loan credit agreement and the amended revolving credit facility agreement include a maximum consolidated leverage ratio of not more than 4.00 to 1.00 with a step down to 3.75 to 1.00 beginning with the quarter ended June 30, 2009 and a minimum consolidated interest coverage ratio of not less than 2.50 to 1.00 which increases to 2.75 to 1.00 beginning with the quarter ended June 30, 2009. The failure to comply with any of these or other covenants would cause a default under the credit facilities. A default, if not waived, could result in acceleration of our debt, in which case the debt would become immediately due and payable. If this 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.
 
We may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under our revolving credit facility because of deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
 
Global financial market and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.
 
In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.
 
In addition, we may be unable to obtain adequate funding under our revolving credit facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base under our revolving credit facility is redetermined weekly or monthly depending upon availability levels and may decrease as a result of changes in selling prices of our products, our current material costs (primarily crude oil), lending requirements or regulations, or for any other reason.
 
Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our business development plans, enhance our existing business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
 
Refining margins are volatile, and a reduction in our refining margins will adversely affect the amount of cash we will have available for distribution to our unitholders.
 
Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our specialty products prices and fuel


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products prices and the prices for crude oil and other feedstocks. The cost to acquire our feedstocks and the price at which we can ultimately sell our refined products depend upon numerous factors beyond our control.
 
A widely used benchmark in the fuel products industry to measure market values and margins is the “Gulf Coast 3/2/1 crack spread,” which represents the approximate gross margin resulting from refining crude oil, assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of heating oil. The Gulf Coast 3/2/1 crack spread, as reported by Bloomberg L.P., has averaged as follows:
 
         
Time Period
  Crack spread  
 
1990 to 1999
  $ 3.04  
2000 to 2004
  $ 4.61  
2005
  $ 10.63  
2006
  $ 10.70  
2007
  $ 14.27  
First quarter 2008
  $ 10.16  
Second quarter 2008
  $ 14.55  
Third quarter 2008
  $ 10.82  
Fourth quarter 2008
  $ 4.30  
Calendar year 2008
  $ 9.98  
 
Our actual refining margins vary from the Gulf Coast 3/2/1 crack spread due to the actual crude oil used and products produced, transportation costs, regional differences, and the timing of the purchase of the feedstock and sale of the refined products, but we use the Gulf Coast 3/2/1 crack spread as an indicator of the volatility and general levels of refining margins.
 
The prices at which we sell specialty products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our specialty products segment’s margins will fall unless we are able to pass along these price increases to our customers. Increases in selling prices for specialty products typically lag the rising cost of crude oil and may be difficult to implement when crude oil costs increase dramatically over a short period of time. For example, in the first six months of 2008, excluding the effects of hedges, we experienced a 31.3% increase in the cost of crude oil per barrel as compared to a 18.3% increase in the average sales price per barrel of our specialty products. It is possible we may not be able to pass on all or any portion of the increased crude oil costs to our customers. In addition, we will not be able to completely eliminate our commodity risk through our hedging activities.
 
Because refining margins are volatile, unitholders should not assume that our current margins will be sustained. If our refining margins fall, it will adversely affect the amount of cash we will have available for distribution to our unitholders.
 
Because of the volatility of crude oil and refined products prices, our method of valuing our inventory may result in decreases in net income.
 
The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value, if the market value of our inventory were to decline to an amount less than our cost, we would record a write-down of inventory and a non-cash charge to cost of sales. In a period of decreasing crude oil or refined product prices, our inventory valuation methodology may result in decreases in net income.
 
The price volatility of fuel and utility services may result in decreases in our earnings, profitability and cash flows.
 
The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect our net income and cash flows. Fuel and utility prices are affected by factors outside of our control, such as supply and demand for fuel and utility services in both local and regional markets.


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Natural gas prices have historically been volatile. For example, daily prices for natural gas as reported on the New York Mercantile Exchange (“NYMEX”) ranged between $5.29 and $13.58 per million British thermal unit, or MMBtu, in 2008 and between $5.38 and $8.64 per MMBtu in 2007. Typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a material adverse effect on our results of operations. Fuel and utility costs constituted approximately 36.5% and 44.2% of our total operating expenses included in cost of sales for the years ended December 31, 2008 and 2007, respectively. If our natural gas costs rise, it will adversely affect the amount of cash we will have available for distribution to our unitholders.
 
Our hedging activities may not be effective in reducing the volatility of our cash flows and may reduce our earnings, profitability and cash flows.
 
We are exposed to fluctuations in the price of crude oil, fuel products, natural gas and interest rates. We utilize derivative financial instruments related to the future price of crude oil, natural gas and fuel products with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices and derivative instruments related to interest rates for future periods with the intent of reducing volatility in our cash flows due to fluctuations in interest rates. We are not able to enter into derivative financial instruments to reduce the volatility of the prices of the specialty hydrocarbon products we sell as there is no established derivative market for such products.
 
The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual crude oil prices, natural gas prices or fuel products prices that we incur or realize in our operations. Accordingly, our commodity price risk management policy may not protect us from significant and sustained increases in crude oil or natural gas prices or decreases in fuel products prices. Conversely, our policy may limit our ability to realize cash flows from crude oil and natural gas price decreases.
 
We have a policy to enter into derivative transactions related to only a portion of the volume of our expected purchase and sales requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion of our expected purchase and sales requirements. For example, we historically have entered into monthly crude oil collars to hedge up to 14,000 bpd of crude purchases related to our specialty products segment, which had average total daily production for 2008 of 30,159 bpd. As of December 31, 2008, we had significantly reduced the volume and duration of our crude oil collars position and were hedging approximately 7,700 bpd through March 31, 2009. Thus, we could be exposed to significant crude oil cost increases on a portion of our purchases. Please read Item 7A “Quantitative and Qualitative Disclosures about Market Risk.”
 
Our actual future purchase and sales requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which may result in a substantial diminution of our liquidity. As a result, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
 
Our acquisition, asset reconfiguration and enhancement initiatives may not result in revenue or cash flow increases, may be subject to significant cost overruns and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our business, operating results, cash flows and financial condition.
 
We plan to grow our business in part through acquisition and the reconfiguration and enhancement of our existing refinery assets. As a specific example, we completed an expansion project at our Shreveport refinery to increase throughput capacity and crude oil processing flexibility in May 2008. This construction project and the


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construction of other additions or modifications to our existing refineries have and will continue to involve numerous regulatory, environmental, political, legal, labor and economic uncertainties beyond our control, which could cause delays in construction or require the expenditure of significant amounts of capital, which we may finance with additional indebtedness or by issuing additional equity securities. For example, the Shreveport expansion project total cost was approximately $375.0 million and was significantly over budget due to increased construction labor costs. Future acquisition, reconfiguration and enhancement projects may not be completed at the budgeted cost, on schedule, or at all due to the risks described above which would significantly affect our cash flows and financial condition.
 
Our acquisition of Penreco could expose us to potential significant liabilities.
 
In connection with the Penreco acquisition, we purchased all of the partnership interests of Penreco rather than just its assets. As a result, we purchased the liabilities of Penreco subject to certain exclusions in the purchase and sale agreement, including unknown and contingent liabilities. We performed a certain level of due diligence in connection with the Penreco acquisition and attempted to verify the representations of the sellers and of Penreco management, but there may be pending, threatened, contemplated or contingent claims against Penreco related to environmental, title, regulatory, litigation or other matters of which we are unaware. Although the sellers agreed to indemnify us on a limited basis against some of these liabilities, a significant portion of these indemnification obligations will expire two years after the date the acquisition is completed without any claims having been asserted by us and these obligations are subject to limits. Each seller’s liability is limited to 50% of our loss. Each seller’s indemnification obligations are generally subject to a limit of $2.0 million limit for most matters and a deductible of $1.0 million per claim, or $10.0 million for all claims in the aggregate. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations of Penreco, which could materially adversely affect our operations and financial condition.
 
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
 
We had approximately $477.6 million of outstanding indebtedness under our credit facilities as of December 31, 2008 and availability for borrowings of $51.9 million under our senior secured revolving credit facility. We continue to have the ability to incur additional debt, including the ability to borrow up to $375.0 million under our senior secured revolving credit facility, subject to the borrowing base limitations in that credit agreement. For further discussion of our term loan and revolving credit facilities, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities.” Our level of indebtedness could have important consequences to us, including the following:
 
  •  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
 
  •  covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
 
  •  we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and
 
  •  our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
 
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring


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or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.
 
Our recently acquired Penreco facilities are dependent upon ConocoPhillips for a majority of their feedstocks, and the balance of its feedstocks are not secured by long-term contracts and are subject to price increases and availability. To the extent we are unable to obtain necessary feedstocks, operations will be adversely affected.
 
Our Penreco facilities receive the majority of their feedstocks from ConocoPhillips pursuant to long-term supply contracts. In addition, one particular feedstock is produced at a unit operated by ConocoPhillips within one of its refineries, which has shut down production in the past under the force majeure provisions of a supply contract. In addition, we do not have long-term contracts with most of our other suppliers. Each of our Penreco facilities is dependent on these suppliers and the loss of these suppliers would adversely affect our financial results to the extent we were unable to find replacement suppliers.
 
We may be unable to consummate potential acquisitions we identify or successfully integrate such acquisitions.
 
We regularly consider and enter into discussions regarding potential acquisitions that we believe are complementary to our business. Any such purchase is subject to substantial due diligence, the negotiation of a definitive purchase and sale agreement and ancillary agreements, including, but not limited to supply, transition services and licensing agreements, and the receipt of various board of directors, governmental and other approvals. In the alternative, if we are successful in closing any such acquisitions, we will be subject to many risks including integration risks and the risk that a substantial portion of an acquired business may not produce “qualifying income” for purposes of the Internal Revenue Code. If our non-qualifying income exceeds 10% we would lose our election to be treated as a partnership for tax purposes and will be taxed as a corporation.
 
If our general financial condition deteriorates, we may be limited in our ability to issue letters of credit which may affect our ability to enter into hedging arrangements, to enter into leasing arrangements, or to purchase crude oil.
 
We rely on our ability to issue letters of credit to enter into hedging arrangements in an effort to reduce our exposure to adverse fluctuations in the prices of crude oil, natural gas and crack spreads. We also rely on our ability to issue letters of credit to purchase crude oil for our refineries, lease certain precious metals for use in our refinery operations and enter into cash flow hedges of crude oil and natural gas purchases and fuel products sales. If, due to our financial condition or other reasons, we are limited in our ability to issue letters of credit or we are unable to issue letters of credit at all, we may be required to post substantial amounts of cash collateral to our hedging counterparties, lessors or crude oil suppliers in order to continue these activities, which would adversely affect our liquidity and our ability to distribute cash to our unitholders.
 
We depend on certain key crude oil gatherers for a significant portion of our supply of crude oil, and the loss of any of these key suppliers or a material decrease in the supply of crude oil generally available to our refineries could materially reduce our ability to make distributions to unitholders.
 
We purchase crude oil from major oil companies as well as from various gatherers and marketers in east Texas and north Louisiana. In 2008, subsidiaries of Plains and Genesis Crude Oil, L.P. supplied us with approximately 59.1% and 6.2%, respectively, of our total crude oil supplies under term contracts and evergreen crude oil supply contracts. In addition, we received 7.7% of our total crude oil purchases from Legacy Resources, an affiliate of our general partner, in 2008 and we have expanded our supply from Legacy Resources in January 2009 through the execution of an additional crude oil supply contract. Each of our refineries is dependent on one or all 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. Please read Items 1 and 2 “Business and Properties — Crude Oil and Feedstock Supply.”


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To the extent that our suppliers reduce the volumes of crude oil that they supply us as a result of declining production or competition or otherwise, our revenues, net income and cash available for distribution would decline unless we were able to acquire comparable supplies of crude oil 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 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 distribution 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 TEPPCO Partners, L.P. and ExxonMobil. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. If any of these third-party pipelines become unavailable to transport crude oil or our refined fuel products because of accidents, government regulation, terrorism or other events, our revenues, net income and cash available for distribution could decline.
 
Distributions to unitholders could be adversely affected by a decrease in the demand for our specialty products.
 
Changes in our customers’ products or processes may enable our customers to reduce consumption of the specialty products that we produce or make our specialty products unnecessary. Should a customer decide to use a different product due to price, performance or other considerations, we may not be able to supply a product that meets the customer’s new requirements. In addition, the demand for our customers’ end products could decrease, which would reduce their demand for our specialty products. Our specialty products customers are primarily in the industrial goods, consumer goods and automotive goods industries and we are therefore susceptible to changing demand patterns and products in those industries. Consequently, it is important that we develop and manufacture new products to replace the sales of products that mature and decline in use. If we are unable to manage successfully the maturation of our existing specialty products and the introduction of new specialty products our revenues, net income and cash available for distribution to unitholders could be reduced.
 
Distributions to unitholders could be adversely affected by a decrease in demand for fuel products in the markets we serve.
 
Any sustained decrease in demand for fuel products in the markets we serve could result in a significant reduction in our cash flows, reducing our ability to make distributions to unitholders. Factors that could lead to a decrease in market demand include:
 
  •  a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;
 
  •  higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of fuel products;
 
  •  an increase in fuel economy or the increased use of alternative fuel sources;
 
  •  an increase in the market price of crude oil that lead to higher refined product prices, which may reduce demand for fuel products;
 
  •  competitor actions; and


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  •  availability of raw materials.
 
We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.
 
Our specialty products provide precise performance attributes for our customers’ products. If a product fails to perform in a manner consistent with the detailed quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. A successful claim or series of claims against us could result in a loss of one or more customers and reduce our ability to make distributions to unitholders.
 
We are subject to compliance with stringent environmental, health and safety laws and regulations that may expose us to substantial costs and liabilities.
 
Our crude oil and specialty hydrocarbon refining and terminal operations are subject to stringent and complex federal, state and local environmental, health and safety laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, worker health and safety. These laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of significant capital expenditures to limit or prevent releases of materials from our refineries, terminal, and related facilities, and the incurrence of substantial costs and liabilities for pollution resulting both from our operations and from those of prior owners. Numerous governmental authorities, such as the EPA, OSHA, and state agencies, such as the LDEQ, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with laws, regulations, permits and orders may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Described below are examples of these costs and liabilities.
 
We are in discussions with the LDEQ regarding our participation in the Small Refinery and Single Site Refinery Initiative and anticipate that we will be entering into a settlement agreement with the LDEQ pursuant to which we will be required to make emissions reductions requiring capital investments between approximately $1.0 million and $3.0 million over a three to five year period at our three Louisiana refineries. Because the settlement agreement is also expected to resolve alleged air emissions issues at our Cotton Valley and Princeton refineries and consolidate any penalties associated with such issues, we further anticipate that a penalty of approximately $0.4 million will be assessed in connection with this settlement agreement.
 
We have commissioned studies to assess the adequacy of our process safety management practices at our Shreveport refinery. Depending on the findings made in these studies, we may incur capital expenditures over the next several years to enhance these practices so that we may maintain our compliance with applicable OSHA regulations at the refinery. While we do not expect these expenditures to be material at this time, we have not completed our negotiations with OSHA to reach final resolution.
 
Our business subjects us to the inherent risk of incurring significant environmental liabilities in the operation of our refineries and related facilities.
 
There is inherent risk of incurring significant environmental costs and liabilities in the operation of our refineries, terminal, and related facilities due to our handling of petroleum hydrocarbons and wastes, air emissions and water discharges related to our operations, and historical operations and waste disposal practices by prior owners. We currently own or operate properties that for many years have been used for industrial activities, including refining or terminal storage operations. Petroleum hydrocarbons or wastes have been released on or under the properties owned or operated by us. Joint and several strict liability may be incurred in connection with such releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities. Private parties, including the owners of properties adjacent to our operations and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or


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property damage. We may not be able to recover some or any of these costs from insurance or other sources of indemnity.
 
Increasingly stringent environmental laws and regulations, unanticipated remediation obligations or emissions control expenditures and claims for penalties or damages could result in substantial costs and liabilities, and our ability to make distributions to our unitholders could suffer as a result. Neither the owners of our general partner nor their affiliates have indemnified us for any environmental liabilities, including those arising from non-compliance or pollution, that may be discovered at, or arise from operations on, the assets they contributed to us in connection with the closing of our initial public offering. As such, we can expect no economic assistance from any of them in the event that we are required to make expenditures to investigate or remediate any petroleum hydrocarbons, wastes or other materials.
 
We are exposed to trade credit risk in the ordinary course of our business activities.
 
We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties of our forward contracts, options and swap agreements. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could reduce our ability to make distributions to our unitholders.
 
If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
 
Our ability to grow depends on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, any acquisition involves potential risks, including, among other things:
 
  •  performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;
 
  •  a significant increase in our indebtedness and working capital requirements;
 
  •  an inability to timely and effectively integrate the operations of recently acquired businesses or assets, particularly those in new geographic areas or in new lines of business;
 
  •  the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets;
 
  •  the diversion of management’s attention from other business concerns; and
 
  •  customer or key employee losses at the acquired businesses.
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our funds and other resources.
 
Our refineries, facilities and terminal operations face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.
 
Our operations are subject to significant interruption, and our cash from operations could decline if any of our facilities experiences a major accident or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. These hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations.


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We are not fully insured against all risks incident to our business. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Our business interruption insurance will not apply unless a business interruption exceeds 90 days. We are not insured for environmental accidents. If we were to incur a significant liability for which we were not fully insured, it could diminish our ability to make distributions to unitholders.
 
Downtime for maintenance at our refineries and facilities will reduce our revenues and cash available for distribution.
 
Our refineries and facilities consist of many processing units, a number of which have been in operation for a long time. One or more of the units may require additional unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for each unit every one to five years. Scheduled and unscheduled maintenance reduce our revenues during the period of time that our processing units are not operating and could reduce our ability to make distributions to our unitholders.
 
We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could reduce our ability to make distributions to our unitholders.
 
The workplaces associated with the facilities we operate are subject to the requirements of the federal OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local government authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances could reduce our ability to make distributions to our unitholders if we are subjected to fines or significant compliance costs.
 
We face substantial competition from other refining companies.
 
The refining industry is highly competitive. Our competitors include large, integrated, major or independent oil companies that, because of their more diverse operations, larger refineries and stronger capitalization, may be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers. For example, if a competitor attempts to increase market share by reducing prices, our operating results and cash available for distribution to our unitholders could be reduced.
 
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 (3.75% as of December 31, 2008). Borrowings under our term loan facility bear interest at a floating rate (6.15% as of December 31, 2008). The interest rates are subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) or prime rate. The interest rate under our term loan credit facility, entered into on January 3, 2008, is LIBOR plus 4.0%. 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.
 
Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.
 
We rely exclusively on sales generated from products processed at the facilities we own. Furthermore, the majority of our assets and operations are located in northwest Louisiana. Due to our lack of diversification in asset type and location, an adverse development in these businesses or areas, including adverse developments due to


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catastrophic events or weather, decreased supply of crude oil feedstocks and/or decreased demand for refined petroleum products, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets in more diverse locations.
 
We depend on key personnel for the success of our business and the loss of those persons could adversely affect our business and our ability to make distributions to our unitholders.
 
The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available. Except with respect to Mr. Grube, neither we, our general partner nor any affiliate thereof has entered into an employment agreement with any member of our senior management team or other key personnel. Furthermore, we do not maintain any key-man life insurance.
 
We depend on unionized labor for the operation of our refineries. Any work stoppages or labor disturbances at these facilities could disrupt our business.
 
Substantially all of our operating personnel at our Princeton, Cotton Valley and Shreveport refineries are employed under collective bargaining agreements that expire in October 2011, March 2010 and April 2010, respectively. Substantially all of the operating personnel acquired through the Penreco acquisition are employed under collective bargaining agreements that expire in January 2012 and March 2010. Our inability to renegotiate these agreements as they expire, any work stoppages or other labor disturbances at these facilities could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. In addition, employees who are not currently represented by labor unions may seek union representation in the future, and any renegotiation of current collective bargaining agreements may result in terms that are less favorable to us.
 
The operating results for our fuels segment and the asphalt we produce and sell are seasonal and generally lower in the first and fourth quarters of the year.
 
The operating results for the fuel products segment and the selling prices of asphalt products we produce can be seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters due to the seasonality of road construction. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months. Our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year as a result of this seasonality.
 
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately, or prevent fraud which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
 
Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, annually to review and report on, and our independent registered public accounting firm annually to attest to, our internal control over financial reporting. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.


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Risks Inherent in an Investment in Us
 
The families of our chairman and chief executive officer and president, The Heritage Group and certain of their affiliates own a 58.2% limited partner interest in us and own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to other unitholders’ detriment.
 
The families of our chairman and chief executive officer and president, the Heritage Group, and certain of their affiliates own a 58.2% limited partner interest in us. In addition, The Heritage Group and the families of our chairman and chief executive officer and president own our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
 
  •  our general partner is allowed to take into account the interests of parties other than us, such as its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
 
  •  our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
 
  •  our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to unitholders;
 
  •  our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
 
  •  our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a capital expenditure for acquisitions or capital improvements, which does not. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;
 
  •  our general partner has the flexibility to cause us to enter into a broad variety of derivative transactions covering different time periods, the net cash receipts from which will increase operating surplus and adjusted operating surplus, with the result that our general partner may be able to shift the recognition of operating surplus and adjusted operating surplus between periods to increase the distributions it and its affiliates receive on their subordinated units and incentive distribution rights or to accelerate the expiration of the subordination period; and
 
  •  in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
 
The Heritage Group and certain of its affiliates may engage in limited competition with us.
 
Pursuant to the omnibus agreement we entered into in connection with our initial public offering, The Heritage Group and its controlled affiliates have agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental United States (“restricted business”) for so long as it controls us. This restriction does not apply to certain assets and businesses which are more fully described under Item 13 “Certain Relationships, Related Party Transactions and Director Independence — Omnibus Agreement.”
 
Although Mr. Grube is prohibited from competing with us pursuant to the terms of his employment agreement, the owners of our general partner, other than The Heritage Group, are not prohibited from competing with us.


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Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
 
  •  Permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment of our partnership agreement;
 
  •  Provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
 
  •  Generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
 
  •  Provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.
 
In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.
 
Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our general partner or its board of directors, and have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.
 
The unitholders are unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. The owners of our general partner and certain of their affiliates own 58.2% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.


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Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner during the subordination period because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
 
Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
 
Control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby control the decisions taken by the board of directors.
 
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs.
 
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs. We can provide no assurance that our general partner will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If our general partner fails to provide us with adequate personnel, our operations could be adversely impacted and our cash available for distribution to unitholders could be reduced.
 
We may issue additional common units without unitholder approval, which would dilute our current unitholders’ existing ownership interests.
 
In general, during the subordination period, we may issue up to 6,533,000 additional common units without obtaining unitholder approval, which units we refer to as the “basket.” Our general partner can also issue an unlimited number of common units in connection with accretive acquisitions and capital improvements that increase cash flow from operations per unit on an estimated pro forma basis. We can also issue additional common units if the proceeds are used to repay certain of our indebtedness.
 
The issuance of additional common units or other equity securities of equal or senior rank to the common units will have the following effects:
 
  •  our unitholders’ proportionate ownership interest in us may decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished;
 
  •  the market price of the common units may decline; and
 
  •  the ratio of taxable income to distributions may increase.


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After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.
 
Our general partner’s determination of the level of cash reserves may reduce the amount of available cash for distribution to unitholders.
 
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement also permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These reserves will affect the amount of cash available for distribution to unitholders.
 
Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to unitholders.
 
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Any such reimbursement will be determined by our general partner and will reduce the cash available for distribution to unitholders. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read Item 13 “Certain Relationships, Related Party Transactions and Director Independence.”
 
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80% of the issued and outstanding common units, our general partner will have the right, but not the obligation, which right it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units to our general partner, its affiliates or us at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. Our general partner and its affiliates own approximately 31.7% of the common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 59.4% of the common units.
 
Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as if they were a general partner if:
 
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  unitholders’ right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.


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Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we call the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of the units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
 
Our common units have a limited trading history compared to other units representing limited partner interests.
 
Our common units are traded publicly on the NASDAQ Global Market under the symbol “CLMT.” However, our common units have a limited trading history and low average daily trading volume compared to many other units representing limited partner interests quoted on the NASDAQ. The price of our common units may continue to be volatile.
 
The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:
 
  •  our quarterly distributions;
 
  •  our quarterly or annual earnings or those of other companies in our industry;
 
  •  changes in commodity prices or refining margins;
 
  •  loss of a large customer;
 
  •  announcements by us or our competitors of significant contracts or acquisitions;
 
  •  changes in accounting standards, policies, guidance, interpretations or principles;
 
  •  general economic conditions;
 
  •  the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
 
  •  future sales of our common units; and
 
  •  the other factors described in Item 1A “Risk Factors” of this Annual Report on Form 10-K.
 
Tax Risks to Common Unitholders
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to additional amounts of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to common unitholders.
 
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could


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cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At a state level, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, beginning in 2008, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to unitholders.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the considered legislation would not have appeared to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
 
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.


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Tax gain or loss on disposition of common units could be more or less than expected.
 
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount they realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to unitholders if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if unitholders sell their units they may incur a tax liability in excess of the amount of cash they receive from the sale.
 
Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
 
Investment in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing in our common units.
 
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.
 
We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level income taxes.
 
We conduct all or a portion of our operations in which we market finished petroleum products to certain end-users through a subsidiary that is organized as a corporation. We may elect to conduct additional operations through this corporate subsidiary in the future. This corporate subsidiary is subject to corporate-level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that this corporation has more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.


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A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
 
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methodologies, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
 
Unitholders may be subject to state and local taxes and return filing requirements.
 
In addition to federal income taxes, our common unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if unitholders do not live in any of those jurisdictions. Our common unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject


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to penalties for failure to comply with those requirements. We own assets and/or do business in Arkansas, Arizona, California, Connecticut, Delaware, Florida, Georgia, Indiana, Illinois, Kansas, Kentucky, Louisiana, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, Ohio, Oregon, Pennsylvania, South Carolina, Texas, Utah, Virginia and Wisconsin. Each of these states, other than Texas and Florida, currently imposes a personal income tax as well as an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is the responsibility of our common unitholders to file all United States federal, foreign, state and local tax returns.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 3.   Legal Proceedings
 
We are not a party to any material litigation. 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. Please see Items 1 and 2 “Business and Properties — Environmental Matters” for a description of our current regulatory matters related to the environment.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
None.
 
PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
 
Market Information
 
Our common units are quoted and traded on the NASDAQ Global Market under the symbol “CLMT.” Our common units began trading on January 26, 2006 at an initial public offering price of $21.50. Prior to that date, there was no public market for our common units. The following table shows the low and high sales prices per common unit, as reported by NASDAQ, for the periods indicated. Cash distributions presented below represent amounts declared subsequent to each respective quarter end based on the results of that quarter. During each quarter in the years ended December 31, 2008 and 2007, identical cash distributions per unit were paid among all outstanding common and subordinated units.
 
                         
                Cash Distribution
 
    Low     High     per Unit  
 
Year ended December 31, 2007:
                       
First quarter
  $ 39.64     $ 48.50     $ 0.60  
Second quarter
  $ 46.36     $ 55.26     $ 0.60  
Third quarter
  $ 42.27     $ 52.90     $ 0.63  
Fourth quarter
  $ 32.87     $ 50.99     $ 0.63  
Year ended December 31, 2008:
                       
First quarter
  $ 22.60     $ 37.88     $ 0.45  
Second quarter
  $ 11.19     $ 23.50     $ 0.45  
Third quarter
  $ 11.46     $ 15.40     $ 0.45  
Fourth quarter
  $ 5.77     $ 15.35     $ 0.45  
 
As of February 26, 2009, there were approximately 23 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. As of February 26, 2009, there were 32,232,000 units outstanding. The number of units outstanding on this date includes the 13,066,000 subordinated units for which there is no


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established trading market. The last reported sale price of our common units by NASDAQ on February 26, 2009 was $12.16.
 
On November 20, 2007, we completed a follow-on public offering of common units in which we sold 2,800,000 common units to the underwriters of this offering at a price to the public of $36.98 per common unit and received net proceeds of $98.2 million. Additionally, the general partner contributed an additional $2.1 million to us to retain its 2% general partner interest.
 
Cash Distribution Policy
 
General.  Within 45 days after the end of each quarter, we distribute our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date.
 
Available Cash.  Available cash generally means, for any quarter, all cash on hand at the end of the quarter:
 
  •  less the amount of cash reserves established by our general partner to:
 
  •  provide for the proper conduct of our business;
 
  •  comply with applicable law, any of our debt instruments or other agreements; or
 
  •  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
 
  •  plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
 
Intent to Distribute the Minimum Quarterly Distribution.  We distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.45 per unit, or $1.80 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreements. Please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for a discussion of the restrictions in our credit agreements that restrict our ability to make distributions. On February 13, 2009, we paid a quarterly cash distribution of $0.45 per unit on all outstanding units totaling $14.8 million for the quarter ended December 31, 2008 to all unitholders of record as of the close of business on February 3, 2009.
 
General Partner Interest and Incentive Distribution Rights.  Our general partner is entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest is represented by 657,796 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined below) in excess of $0.45 per unit. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest, and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on units that it owns. We paid $1.0 million to our general partner in incentive distributions pursuant to its incentive distribution rights during the year ended December 31, 2008.


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Operating Surplus and Capital Surplus
 
General.  All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.
 
Operating Surplus.  Operating surplus generally consists of:
 
  •  our cash balance on the closing date of the initial public offering; plus
 
  •  $10.0 million (as described below); plus
 
  •  all of our cash receipts after the closing of the initial public offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus
 
  •  working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less
 
  •  all of our operating expenditures after the closing of the initial public offering (including the repayment of working capital borrowings, but not the repayment of other borrowings) and maintenance capital expenditures; less
 
  •  the amount of cash reserves established by our general partner for future operating expenditures.
 
Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand the existing operating capacity of our assets or to expand the operating capacity or revenues of existing or new assets, whether through construction or acquisition. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as operations and maintenance expenses as we incur them. Our partnership agreement provides that our general partner determines how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.
 
Capital Surplus.  Capital surplus consists of:
 
  •  borrowings other than working capital borrowings;
 
  •  sales of our equity and debt securities; and
 
  •  sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.
 
Characterization of Cash Distributions.  We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $10.0 million. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.
 
Subordination Period
 
General.  Our partnership agreement provides that, during the subordination period (defined below), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.45 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash


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from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the existence of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. All of the outstanding subordinated units are owned by affiliates of our general partner.
 
Subordination Period.  The subordination period will extend until the first day of any quarter beginning after December 31, 2010 that each of the following tests are met:
 
  •  distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distributions on such common units, subordinated units and general partner units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and
 
  •  there are no arrearages in payment of minimum quarterly distributions on the common units.
 
Expiration of the Subordination Period.  When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:
 
  •  the subordination period will end and each subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
 
Adjusted Operating Surplus.  Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:
 
  •  operating surplus generated with respect to that period; less
 
  •  any net increase in working capital borrowings with respect to that period; less
 
  •  any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •  any net decrease in working capital borrowings with respect to that period; plus
 
  •  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
 
Distributions of Available Cash from Operating Surplus During the Subordination Period
 
We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
 
  •  first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;


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  •  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
 
  •  third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— Incentive Distribution Rights” below.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
 
Distributions of Available Cash from Operating Surplus After the Subordination Period
 
We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
 
  •  first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— Incentive Distribution Rights” below.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
 
Incentive Distribution Rights
 
Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.
 
If for any quarter:
 
  •  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
 
  •  we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
 
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:
 
  •  first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.495 per unit for that quarter (the “first target distribution”);
 
  •  second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.563 per unit for that quarter (the “second target distribution”);
 
  •  third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.675 per unit for that quarter (the “third target distribution”); and
 
  •  thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.
 
In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.


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Percentage Allocations of Available Cash from Operating Surplus
 
The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.
 
                     
        Marginal Percentage
 
    Total Quarterly
  Interest in
 
    Distribution
  Distributions  
   
Target Amount
  Unitholders     General Partner  
 
Minimum Quarterly Distribution
  $0.45     98 %     2 %
First Target Distribution
  up to $0.495     98 %     2 %
Second Target Distribution
  above $0.495 up to $0.563     85 %     15 %
Third Target Distribution
  above $0.563 up to $0.675     75 %     25 %
Thereafter
  above $0.675     50 %     50 %
 
Distributions from Capital Surplus
 
How Distributions from Capital Surplus Will Be Made.  Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:
 
  •  first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to the initial public offering price;
 
  •  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
 
  •  thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.
 
Effect of a Distribution from Capital Surplus.  Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
 
Once we distribute capital surplus on a unit in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.


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Equity Compensation Plans
 
The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this item is incorporated by reference into Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” of this Annual Report on Form 10-K.
 
Sales of Unregistered Securities
 
None.
 
Issuer Purchases of Equity Securities
 
None.


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Item 6.   Selected Financial Data
 
The following table shows selected historical consolidated financial and operating data of Calumet Specialty Products Partners, L.P. and its consolidated subsidiaries (“Calumet”) and Calumet Lubricants Co., Limited Partnership (“Predecessor”). The selected historical financial data as of December 31, 2008 includes the operations acquired as part of the Penreco acquisition from their date of acquisition, January 3, 2008. The selected historical financial data as of December 31, 2005 and 2004 and for the years ended December 31, 2005 and 2004, are derived from the consolidated financial statements of the Predecessor. The results of operations for the years ended December 31, 2006 for Calumet include the results of operations of the Predecessor for the period of January 1, 2006 through January 31, 2006.
 
The following table includes the non-GAAP financial measures EBITDA and Adjusted EBITDA. For a reconciliation of EBITDA and Adjusted EBITDA to net income 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.”
 
We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K except for operating data such as sales volume, feedstock runs and production. The table also should be read together with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (Dollars in thousands, except per unit data)  
 
Summary of Operations Data:
                                       
Sales
  $ 2,488,994     $ 1,637,848     $ 1,641,048     $ 1,289,072     $ 539,616  
Cost of sales
    2,235,111       1,456,492       1,436,108       1,147,117       501,973  
                                         
Gross profit
    253,883       181,356       204,940       141,955       37,643  
Operating costs and expenses:
                                       
Selling, general and administrative
    34,267       19,614       20,430       22,126       13,133  
Transportation
    84,702       54,026       56,922       46,849       33,923  
Taxes other than income taxes
    4,598       3,662       3,592       2,493       2,309  
Other
    1,576       2,854       863       871       839  
Restructuring, decommissioning and asset impairments (1)
                      2,333       317  
                                         
Operating income (loss)
    128,740       101,200       123,133       67,283       (12,878 )
                                         
Other income (expense):
                                       
Equity in loss of unconsolidated affiliates
                            (427 )
Interest expense
    (33,938 )     (4,717 )     (9,030 )     (22,961 )     (9,869 )
Interest income
    388       1,944       2,951       204       17  
Debt extinguishment costs
    (898 )     (352 )     (2,967 )     (6,882 )      
Realized gain (loss) on derivative instruments
    (58,833 )     (12,484 )     (30,309 )     2,830       39,160  
Unrealized gain (loss) on derivative instruments
    3,454       (1,297 )     12,264       (27,586 )     (7,788 )
Gain on sale of mineral rights
    5,770                          
Other
    11       (919 )     (274 )     38       66  
                                         
Total other income (expense)
    (84,046 )     (17,825 )     (27,365 )     (54,357 )     21,159  
                                         
Net income before income taxes
    44,694       83,375       95,768       12,926       8,281  
Income tax expense
    257       501       190              
                                         
Net income
  $ 44,437     $ 82,874     $ 95,578     $ 12,926     $ 8,281  
                                         


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    Calumet     Predecessor  
    Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (Dollars in thousands, except per unit data)  
 
Basic and diluted net income per limited partner unit:
                                       
Common
  $ 2.41     $ 2.63     $ 2.84                  
Subordinated
  $ (1.00 )   $ 1.86     $ 2.20                  
Weighted average units:
                                       
Common — basic
    19,166       16,678       14,642                  
Subordinated — basic
    13,066       13,066       13,066                  
Common — diluted
    19,166       16,680       14,642                  
Subordinated — diluted
    13,066       13,066       13,066                  
Cash distribution declared per common and subordinated unit
  $ 1.98     $ 2.46     $ 1.90                  
Balance Sheet Data (at period end):
                                       
Property, plant and equipment, net
  $ 659,684     $ 442,882     $ 191,732     $ 127,846     $ 126,585  
Total assets
    1,081,062       678,857       531,651       401,924       319,396  
Accounts payable
    93,855       167,977       78,752       44,759       58,027  
Long-term debt
    465,091       39,891       49,500       267,985       214,069  
Total partners’ capital
    473,212       399,644       385,267       43,940       37,802  
Cash Flow Data:
                                       
Net cash flow provided by (used in):
                                       
Operating activities
  $ 130,341     $ 167,546     $ 166,768     $ (34,001 )   $ (612 )
Investing activities
    (480,461 )     (260,875 )     (75,803 )     (12,903 )     (42,930 )
Financing activities
    350,133       12,409       (22,183 )     40,990       61,561  
Other Financial Data:
                                       
EBITDA
  $ 135,575     $ 102,719     $ 119,586     $ 53,155     $ 25,077  
Adjusted EBITDA
    128,075       104,272       104,458       85,821       34,711  
Operating Data (bpd):
                                       
Total sales volume (2)
    56,232       47,663       50,345       46,953       24,658  
Total feedstock runs (3)
    56,243       48,354       51,598       50,213       26,205  
Total production (4)
    55,330       47,736       50,213       48,331       26,297  
 
 
(1) Incurred in connection with the decommissioning of the Rouseville, Pennsylvania facility, the termination of the Bareco joint venture and the closing of the Reno, Pennsylvania facility, none of which were contributed to Calumet Specialty Products Partners, L.P. in connection with the closing of our initial public offering on January 31, 2006.
 
(2) Total sales volume includes sales from the production of our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements, and sales of inventories.
 
(3) Feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements.
 
(4) Total production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements. The difference between total 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.

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Non-GAAP Financial Measures
 
We include in this Annual Report on Form 10-K the non-GAAP financial measures EBITDA and Adjusted EBITDA, and provide reconciliations of EBITDA and Adjusted EBITDA to net income 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 and Adjusted EBITDA 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, support our indebtedness, and meet minimum quarterly distributions;
 
  •  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 define EBITDA as net income plus interest expense (including debt issuance and extinguishment costs), taxes and depreciation and amortization. We define Adjusted EBITDA to be Consolidated EBITDA as defined in our credit facilities. Consistent with that definition, Adjusted EBITDA means, for any period: (1) net income plus (2)(a) interest expense; (b) taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) unrealized items decreasing net income (including the non-cash impact of restructuring, decommissioning and asset impairments in the periods presented); and (f) other non-recurring expenses reducing net income which do not represent a cash item for such period; minus (3)(a) tax credits; (b) unrealized items increasing net income (including the non-cash impact of restructuring, decommissioning and asset impairments in the periods presented); (c) unrealized gains from mark to market accounting for hedging activities; and (d) 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 are required to report Adjusted EBITDA to our lenders under our credit facilities and it is used to determine our compliance with the consolidated leverage and consolidated interest coverage tests thereunder. On January 3, 2008, we entered into a new senior secured term loan credit facility and amended our existing senior secured revolving credit facility. Please refer to Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” within this item for additional details regarding our credit agreements.
 
EBITDA and Adjusted EBITDA should not be considered alternatives to net income, operating income, net cash provided by (used in) operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA and Adjusted EBITDA in the same manner. The following table presents a reconciliation of both net income to EBITDA and Adjusted EBITDA and Adjusted


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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.
 
                                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands)  
 
Reconciliation of net income to EBITDA and Adjusted EBITDA:
                                       
Net income
  $ 44,437     $ 82,874     $ 95,578     $ 12,926     $ 8,281  
Add:
                                       
Interest expense and debt extinguishment costs
    34,836       5,069       11,997       29,843       9,869  
Depreciation and amortization
    56,045       14,275       11,821       10,386       6,927  
Income tax expense
    257       501       190              
                                         
EBITDA
  $ 135,575     $ 102,719     $ 119,586     $ 53,155     $ 25,077  
                                         
Add:
                                       
Unrealized losses (gains) from mark to market accounting for hedging activities
  $ (11,509 )   $ 3,487     $ (13,145 )   $ 27,586     $ 7,788  
Non-cash impact of restructuring, decommissioning and asset impairments
                      1,766       (1,276 )
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays
    4,009       (1,934 )     (1,983 )     3,314       3,122  
                                         
Adjusted EBITDA
  $ 128,075     $ 104,272     $ 104,458     $ 85,821     $ 34,711  
                                         
 


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    Calumet     Predecessor  
    Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands)  
 
Reconciliation of Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities:
                                       
Adjusted EBITDA
  $ 128,075     $ 104,272     $ 104,458     $ 85,821     $ 34,711  
Add:
                                       
Unrealized (losses) gains from mark to market accounting for hedging activities
    11,509       (3,487 )     13,145       (27,586 )     (7,788 )
Non-cash impact of restructuring, decommissioning and asset impairments
                      (1,766 )     1,276  
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays
    (4,009 )     1,934       1,983       (3,314 )     (3,122 )
                                         
EBITDA
  $ 135,575     $ 102,719     $ 119,586     $ 53,155     $ 25,077  
                                         
Add:
                                       
Cash interest expense and debt extinguishment costs
    (31,440 )     (4,638 )     (11,997 )     (29,843 )     (9,869 )
Unrealized (gains) losses on derivative instruments
    (3,454 )     1,297       (12,264 )     27,586       7,788  
Income taxes
    (257 )     (501 )     (190 )            
Restructuring charge
                      1,693        
Provision for doubtful accounts
    1,448       41       172       294       216  
Equity in loss of unconsolidated affiliates
                            427  
Dividends received from unconsolidated affiliates
                            3,470  
Debt extinguishment costs
    898       352       2,967       4,173        
Changes in assets and liabilities:
                                       
Accounts receivable
    45,042       (15,038 )     16,031       (56,878 )     (19,399 )
Inventory
    55,532       3,321       (2,554 )     (25,441 )     (20,304 )
Other current assets
    1,834       (4,121 )     16,183       569       (11,596 )
Derivative activity
    41,757       2,121       (879 )     4,012       (2,742 )
Accounts payable
    (103,136 )     89,225       33,993       (13,268 )     25,764  
Accrued liabilities
    (1,284 )     (4,150 )     657       5,293       957  
Other, including changes in noncurrent assets and liabilities
    (12,174 )     (3,082 )     5,063       (5,346 )     (401 )
                                         
Net cash provided by (used in) operating activities
  $ 130,341     $ 167,546     $ 166,768     $ (34,001 )   $ (612 )
                                         

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The historical consolidated financial statements included in this Annual Report on Form 10-K reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet”). The following discussion analyzes the financial condition and results of operations of Calumet for the years ended December 31, 2008, 2007, and 2006. The financial condition and results of operations for the year ended December 31, 2006 are of Calumet and include the results of operation of the Calumet Lubricants Co., Limited Partnership, our predecessor, from January 1, 2006 to January 31, 2006. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Calumet in conjunction with the historical consolidated financial statements and notes of Calumet included elsewhere in this Annual Report on Form 10-K.
 
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 Dickinson, Texas, 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. The asphalt and other by-products produced in connection with the production of specialty products at our Princeton, Cotton Valley and Shreveport refineries are included in our specialty products segment. The by-products produced in connection with the production of fuel products at our Shreveport refinery are included in our fuel products segment. The fuels produced in connection with the production of specialty products at our Princeton and Cotton Valley refineries are included in our specialty products segment. In 2008, approximately 73.9% of our gross profit was generated from our specialty products segment and approximately 26.1% of our gross profit was generated from our fuel products segment.
 
Industry Dynamics
 
The specialty petroleum products refining industry and, in general, the overall refining industry experienced significant volatility during 2008, which created many challenges for refiners. We faced the same economic challenges that affected most companies in the industry, primarily driven by the extreme fluctuations in crude oil and other feedstock prices during the year. As a whole, the specialty petroleum products refining industry increased prices significantly for specialty products during the first half of 2008, but these product price increases lagged the unprecedented pace of increases in the price of crude oil. The historic increase in crude oil to approximately $145 per barrel on the NYMEX in June 2008 was followed by a decrease in crude oil prices even more severe than the increase. In December 2008, crude oil prices on the NYMEX averaged approximately $42 per barrel. As a result, in 2008, most companies in the industry experienced cash flow volatility, significant fluctuations in gross profit, significant hedging losses in the second half of the year and increased liquidity issues due to the devaluation in the market prices of inventories of crude oil and refined products. Calumet was no different, as our specialty products segment gross profit on a quarterly basis experienced volatility as it was $22.3 million, $21.5 million, $66.1 million and $77.7 million in the first, second, third and fourth quarters of 2008, respectively.
 
Related to specialty products crude oil hedging, our realized hedging results fluctuated from a gain of $22.8 million through the six months ended June 30, 2008 as compared to a loss of $47.9 million for the six months ended December 31, 2008. Most recently, the industry has experienced bankruptcy filings of certain refiners and chemical companies due to this period of difficult industry dynamics. Given the current fuel products crack spread being at a much lower level than in recent years and the demand impact of the economic downturn, the upcoming period will likely continue to be challenging for refiners, including specialty products refiners like us.
 
Calumet has sought to differentiate itself from its competitors and mitigate the impacts of the challenging economic environment through modifications to our hedging program, continued focus on specialty products,


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working capital reduction initiatives, reducing our quarterly cash distributions to the minimum quarterly distribution early in 2008, and other initiatives to help improve liquidity.
 
Acquisition and Refinery Expansion
 
On January 3, 2008, we acquired Penreco, a Texas general partnership, for $269.1 million. Penreco was owned by ConocoPhillips and M.E. Zukerman Specialty Oil Corporation. Penreco manufactures and markets highly refined products and specialty solvents including white mineral oils, petrolatums, natural petroleum sulfonates, cable-filling compounds, refrigeration oils, food-grade compressor lubricants and gelled products. The acquisition included facilities in Karns City, Pennsylvania and Dickinson, Texas, as well as several long-term supply agreements with ConocoPhillips. We funded the transaction through a portion of the combined proceeds from a public equity offering and a new senior secured first lien term loan facility. For further discussion please read “Liquidity and Capital Resources — Debt and Credit Facilities.” We believe that this acquisition provides several key long term strategic benefits, including market synergies within our solvents and lubricating oil product lines, additional operational and logistics flexibility and overhead cost reductions. The acquisition has broadened our customer base and has given the Company access to new markets.
 
In the second quarter of 2008 we completed a $374.0 million expansion project at our Shreveport refinery to increase aggregate crude oil throughput capacity from approximately 42,000 bpd to approximately 60,000 bpd and improve feedstock flexibility. For further discussion of this project, please read “Liquidity and Capital Resources — Capital Expenditures.”
 
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 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 which do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Item 7a “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” As of December 31, 2008, we have hedged approximately 18.5 million barrels of fuel products through December 2011 at an average refining margin of $11.48 per barrel with average refining margins ranging from a low of $11.32 in 2010 to a high of $11.99 in 2011. During the fourth quarter of 2008, we entered into derivative transactions for 5,000 bpd in 2009 to sell crude oil and buy gasoline which economically secured existing gains on the derivative position of $9.70 per barrel. As a result of these positions, we are now economically exposed to deterioration of gasoline crack spreads below $(2.13) per barrel for 5,000 bpd in 2009. As of December 31, 2008, we have 0.7 million barrels of crude oil options through March 2009 to hedge our purchases of crude oil for specialty products production. The strike prices and types of crude oil options vary. Please refer to Item 7a “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk — Existing Commodity Derivative Instruments” for a detailed listing of 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.


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Sales volumes.  We view the volumes of specialty products and fuels 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.  We seek the optimal product mix for each barrel of crude oil we refine, which we refer to as production yield, in order to maximize our gross profit and minimize lower margin by-products.
 
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 include 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.
 
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, Calumet GP, LLC.
 
High crude oil prices and the volatility of crude oil prices posed significant challenges for us during 2008. The average of the prompt month NYMEX contract for crude oil, which approximates our cost of crude oil, has fluctuated significantly throughout 2008 as follows:
 
         
    Average
 
    NYMEX Price
 
Quarter Ended:
  of Crude Oil Per Barrel  
 
March 31, 2008
  $ 97.82  
June 30, 2008
    123.80  
September 30, 2008
    118.22  
December 31, 2008
    59.42  
 
As a result, we have experienced significant volatility in our gross profit and realized hedging results throughout the year. In response to this volatility, we implemented multiple rounds of specialty product price increases to customers during the first three quarters of 2008 and implemented reductions in our specialty products pricing being during the fourth quarter of 2008 in line with the substantial decline in the price of crude oil. Also, we continue to work diligently on other strategic initiatives, including optimizing our new assets from our Shreveport refinery expansion project and Penreco acquisition, using derivative instruments to mitigate the risk of price fluctuations in crude oil input prices, and maintaining our working capital reductions we achieved during the 2008 fiscal year. For further discussion of our strategic initiatives and our progress on such initiatives during the fourth quarter of 2008, please read “Liquidity and Capital Resources.” While we are taking steps to mitigate the adverse impact of this volatile environment on our operating results, we can provide no assurances as to the sustainability of the improvements in our operating results and to the extent we experience further periods of rapidly escalating or declining crude oil prices, our operating results and liquidity could be adversely affected.


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Results of Operations
 
The following table sets forth information about our combined operations. Facility production volume differs from sales volume due to changes in inventory.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In bpd)  
 
Total sales volume (1)
    56,232       47,663       50,345  
Total feedstock runs (2)
    56,243       48,354       51,598  
Facility production (3):
                       
Specialty products:
                       
Lubricating oils
    12,462       10,734       11,436  
Solvents
    8,130       5,104       5,361  
Waxes
    1,736       1,177       1,157  
Fuels
    1,208       1,951       2,038  
Asphalt and other by-products
    6,623       6,157       6,596  
                         
Total
    30,159       25,123       26,588  
                         
Fuel products:
                       
Gasoline
    8,476       7,780       9,430  
Diesel
    10,407       5,736       6,823  
Jet fuel
    5,918       7,749       6,911  
By-products
    370       1,348       461  
                         
Total
    25,171       22,613       23,625  
                         
Total facility production
    55,330       47,736       50,213  
                         
 
 
(1) Total sales volume includes sales from the production of our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements, and sales of inventories.
 
(2) Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements. The increase in feedstock runs for 2008 is primarily due to the acquisition of the Karns City, PA and the Dickinson, TX facilities as part of the Penreco acquisition and the completion of the Shreveport expansion project in May 2008. These increases were offset by decreases in production rates in the fourth quarter due to scheduled turnarounds at our Princeton, Cotton Valley and Shreveport refineries.
 
(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, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements. The difference between total 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.


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The following table sets forth information about the sales of our principal products.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In millions)  
 
Specialty products:
                       
Lubricating oils
  $ 841.2     $ 478.1     $ 509.9  
Solvents
    419.8       199.8       201.9  
Waxes
    142.5       61.6       61.2  
Fuels
    30.4       52.5       41.3  
Asphalt and other by-products
    144.1       74.7       98.8  
                         
Total
    1,578.0       866.7       913.1  
                         
Fuel products:
                       
Gasoline
    332.7       307.1       336.7  
Diesel
    379.7       203.7       207.1  
Jet fuel
    186.7       225.9       176.4  
By-products
    11.9       34.4       7.7  
                         
Total
    911.0       771.1       727.9  
                         
Consolidated sales
  $ 2,489.0     $ 1,637.8     $ 1,641.0  
                         


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The following table reflects our consolidated results of operations.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In millions)  
 
Sales
  $ 2,489.0     $ 1,637.8     $ 1,641.0  
Cost of sales
    2,235.1       1,456.4       1,436.1  
                         
Gross profit
    253.9       181.4       204.9  
                         
Operating costs and expenses:
                       
Selling, general and administrative
    34.3       19.6       20.4  
Transportation
    84.7       54.0       56.9  
Taxes other than income taxes
    4.6       3.7       3.6  
Other
    1.6       2.9       0.9  
                         
Operating income
    128.7       101.2       123.1  
                         
Other income (expense):
                       
Interest expense
    (33.9 )     (4.7 )     (9.0 )
Interest income
    0.4       1.9       3.0  
Debt extinguishment costs
    (0.9 )     (0.4 )     (3.0 )
Realized loss on derivative instruments
    (58.8 )     (12.5 )     (30.3 )
Unrealized gain (loss) on derivative instruments
    3.5       (1.3 )     12.3  
Gain on sale of mineral rights
    5.8              
Other
    (0.1 )     (0.8 )     (0.3 )
                         
Total other expense
    (84.0 )     (17.8 )     (27.3 )
                         
Net income before income taxes
    44.7       83.4       95.8  
Income tax expense
    (0.3 )     (0.5 )     (0.2 )
                         
Net income
  $ 44.4     $ 82.9     $ 95.6  
                         


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Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
 
Sales.  Sales increased $851.1 million, or 52.0%, to $2,489.0 million in 2008 from $1,637.8 million in 2007. Sales for each of our principal product categories in these periods were as follows:
 
                         
    Year Ended December 31,  
    2008     2007     % Change  
    (Dollars in millions)  
 
Sales by segment:
                       
Specialty products:
                       
Lubricating oils
  $ 841.2     $ 478.1       75.9 %
Solvents
    419.8       199.8       110.1 %
Waxes
    142.5       61.6       131.3 %
Fuels (1)
    30.4       52.5       (42.1 )%
Asphalt and by-products (2)
    144.1       74.7       92.9 %
                         
Total specialty products
    1,578.0       866.7       82.1 %
                         
Total specialty products sales volume (in barrels)
    10,289,000       8,410,000       22.3 %
Fuel products:
                       
Gasoline
  $ 332.7     $ 307.1       8.3 %
Diesel
    379.7       203.7       86.5 %
Jet fuel
    186.7       225.9       (17.4 )%
By-products (3)
    11.9       34.4       (65.5 )%
                         
Total fuel products
    911.0       771.1       18.1 %
                         
Total fuel products sales volume (in barrels)
    10,292,000       8,987,000       14.5 %
Total sales
  $ 2,489.0     $ 1,637.8       52.0 %
                         
Total sales volume (in barrels)
    20,581,000       17,397,000       18.3 %
                         
 
 
(1) Represents fuels produced in connection with the production of specialty products at the Princeton and Cotton Valley 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.
 
This $851.1 million increase in sales resulted from a $711.3 million increase in sales in the specialty products segment and a $139.8 increase in sales in the fuel products segment.
 
Specialty products segment sales for 2008 increased $711.3 million, or 82.1%, primarily due to a 22.3% increase in volumes sold, from approximately 8.4 million barrels in 2007 to 10.3 million barrels in 2008 primarily due to an additional 2.4 million barrels of sales volume of lubricating oils, solvents and waxes from our operations acquired in the Penreco acquisition. Excluding sales volume associated with Penreco, our specialty products sales volume decreased 6.0% primarily due to lower fuels and solvents sales volume due to lower production at our Cotton Valley refinery. These decreases were partially offset by increased asphalt and by-products sales due to increased production from the Shreveport refinery expansion project. Specialty products segment sales were also positively affected by a 39.2% increase in the average selling price per barrel of specialty products at our Shreveport, Princeton and Cotton Valley refineries compared to the prior period due to price increases in all specialty products, with lubricating oils and asphalt and by-products experiencing the largest sales price increases. The sales price increases were implemented in response to the rising cost of crude oil experienced early in 2008 as the cost of crude oil per barrel increased 40.2% over 2007.
 
Fuel products segment sales for 2008 increased $139.8 million, or 18.1%, due to a 31.1% increase in the average selling price per barrel as compared to 2007. This increase compares to a 40.3% increase in the average cost


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of crude oil per barrel over 2007. The increased sales price per barrel was a result of increases in all fuel products as prices increased in relation to the increase in the price of crude oil. Gasoline prices increased at rates lower than the overall increase in the crude oil price per barrel due primarily to the decline in gasoline demand throughout 2008. Fuel products segment sales were also positively affected by a 14.5% increase in sales volumes, from approximately 9.0 million barrels in 2007 to 10.3 million barrels in 2008, primarily driven by diesel sales volume. The increase in diesel sales volume was due primarily to the startup of the Shreveport refinery expansion project in May 2008 and shifts in product mix to diesel during various points throughout 2008. Our Shreveport refinery has the ability to switch portions of its production between diesel and other fuel and specialty products to allow it to take advantage of the most advantageous markets. The increased sales volume and sales prices were offset by a $263.7 million increase in derivative losses on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for the net impact of our crude oil and fuel products derivative instruments designated as hedges.
 
Gross Profit.  Gross profit increased $72.5 million, or 40.0%, to $253.9 million for 2008 from $181.4 million for 2007. Gross profit for our specialty and fuel products segments were as follows:
 
                         
    Year Ended December 31,  
    2008     2007     % Change  
    (Dollars in millions)  
 
Gross profit by segment:
                       
Specialty products
  $ 187.6     $ 115.4       62.6 %
Percentage of sales
    11.9 %     13.3 %        
Fuel products
  $ 66.3     $ 66.0       0.5 %
Percentage of sales
    7.3 %     8.6 %        
Total gross profit
  $ 253.9     $ 181.4       40.0 %
Percentage of sales
    10.2 %     11.1 %        
 
This $72.5 million increase in total gross profit includes an increase in gross profit of $72.2 million in the specialty products segment and a $0.3 million increase in gross profit in the fuel products segment.
 
The increase in specialty products segment gross profit was primarily due to a 22.3% increase in sales volume primarily due to an additional 2.4 million barrels of sales volume from our operations acquired in the Penreco acquisition. Negatively impacting our gross profit was the effect of our specialty products sales price increases not keeping pace with the rising cost of crude oil late in 2007 and in the first half of 2008. During the last six months of 2007, our specialty products sales prices increased by 7.9% and our average cost of crude oil increased by approximately 28.8%. This trend continued during the first six months of 2008 as our specialty products sales prices, excluding Penreco, increased by 18.3% and our average cost of crude oil increased by 31.3%. As crude oil prices started falling late in 2008, we benefited from price increases during the last six months of 2008 resulting in our specialty products sales prices increasing 25.5% while the average cost of crude oil decreased by 13.8%. Further lowering our gross profit was a reduction in the cost of sales benefit of $5.5 million in 2008 as compared to 2007 from the liquidation of lower cost inventory layers. These decreases were offset by increased derivative gains of $19.8 million in 2008 as compared to 2007. Additionally, in 2008 we entered into derivative contracts to economically hedge specialty crude purchases which were not designated as hedges in accordance with SFAS 133, Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138 and in May 2003 by SFAS No. 149 (collectively referred to as “SFAS 133”). The impacts of these hedges which settled in 2008 was a realized loss of $47.0 million which is recorded in realized loss on derivative instruments in our statements of operations as discussed below.
 
Fuel products segment gross profit was positively impacted by a 14.5% increase in fuel products sales volume as discussed above. This increase was partially offset by the rising cost of crude oil outpacing increases in the selling price per barrel of our fuel products. The average cost of crude oil increased by approximately 40.3% from 2007 to 2008 while the average selling price per barrel of our fuel products increased by only 31.1% primarily due to gasoline sales prices increasing at rates lower than the overall increase in the crude oil price per barrel due to the decline in gasoline demand throughout 2008. Additionally, lowering our gross profit was a reduction in the cost of sales benefit of $8.9 million in 2008 as compared to 2007 from the liquidation of lower cost inventory layers.


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Selling, general and administrative.  Selling, general and administrative expenses increased $14.7 million, or 74.7%, to $34.3 million in 2008 from $19.6 million in 2007. This increase is primarily due to additional selling, general and administrative expenses associated with Penreco. Selling, general and administrative expenses also increased due to additional accrued incentive compensation costs in 2008 as compared to 2007.
 
Transportation.  Transportation expenses increased $30.7 million, or 56.8%, to $84.7 million in 2008 from $54.0 million in 2007. This increase is primarily related to additional transportation expenses associated with Penreco.
 
Interest expense.  Interest expense increased $29.2 million, or 619.5%, to $33.9 million in 2008 from $4.7 million in 2007. This increase was primarily due to an increase in indebtedness as a result of a new senior secured term loan facility, which closed on January 3, 2008 and includes a $385.0 million term loan partially used to finance the acquisition of Penreco, as well as increased borrowings on our revolving credit facility primarily due to higher than expected capital expenditures to complete the Shreveport refinery expansion project. This increase was partially offset by an increase in capitalized interest as a result of increased capital expenditures on the Shreveport refinery expansion project.
 
Interest income.  Interest income decreased $1.6 million to $0.4 million in 2008 from $1.9 million in 2007. This decrease was primarily due to a larger average cash and cash equivalents balance during 2007 as compared to 2008 due to the utilization of cash for capital expenditures on the Shreveport refinery expansion project.
 
Debt extinguishment costs.  Debt extinguishment costs increased $0.5 million in 2008 as compared to $0.4 million in 2007. This increase was primarily due to the repayment of our prior senior secured term loan facility with a portion of the proceeds of our new senior secured term loan facility. The increase was also the result of debt extinguishment costs recognized in conjunction with the repayment of a portion of our new senior secured term loan facility using the proceeds of the sale of mineral rights on our real property at our Shreveport and Princeton refineries.
 
Realized loss on derivative instruments.  Realized loss on derivative instruments increased $46.3 million to $58.8 million in 2008 from $12.5 million in 2007. This increased loss was primarily the result of the unfavorable settlement of certain derivative instruments not designated as cash flow hedges in 2008 as compared to 2007 as crude oil prices declined rapidly in the third and fourth quarters of 2008. These derivative instruments were primarily combinations of crude oil options related to our specialty products segment crude oil purchases and are utilized to economically offset our exposure to rising crude oil prices.
 
Unrealized gain (loss) on derivative instruments.  Unrealized gain on derivative instruments increased $4.8 million, to $3.5 million in 2008 from a loss of $1.3 million in 2007. This increased gain is primarily due to the increase in gain ineffectiveness related to derivative instruments in our fuel products segment in 2008 as compared to 2007. This was offset by the unfavorable mark-to-market changes for certain derivative instruments in our specialty products segment not designated as cash flow hedges, including crude oil collars, natural gas swap contracts, and interest rate swap contracts, being recorded to unrealized loss on derivative instruments in 2008 as compared 2007.
 
Gain on sale of mineral rights.  We recorded a $5.8 million gain in 2008 resulting from the lease of mineral rights on the real property at our Shreveport and Princeton refineries to an unaffiliated third party which has been accounted for as a sale. We have retained a royalty interest in any future production associated with these mineral rights.


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Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
Sales.  Sales decreased $3.2 million, or 0.2%, to $1,637.8 million in 2007 from $1,641.0 million in 2006. Sales for each of our principal product categories in these periods were as follows:
 
                         
    Year Ended December 31,  
    2007     2006     % Change  
    (Dollars in millions)  
 
Sales by segment:
                       
Specialty products:
                       
Lubricating oils
  $ 478.1     $ 509.9       (6.2 )%
Solvents
    199.8       201.9       (1.0 )%
Waxes
    61.6       61.2       0.7 %
Fuels (1)
    52.5       41.3       27.1 %
Asphalt and by-products (2)
    74.7       98.8       (24.4 )%
                         
Total specialty products
    866.7       913.1       (5.1 )%
                         
Total specialty products sales volume (in barrels)
    8,410,000       9,165,000       (8.2 )%
Fuel products:
                       
Gasoline
  $ 307.1     $ 336.7       (8.8 )%
Diesel
    203.7       207.1       (1.7 )%
Jet fuel
    225.9       176.4       28.1 %
By-products (3)
    34.4       7.7       347.3 %
                         
Total fuel products
    771.1       727.9       5.9 %
                         
Total fuel products sales volume (in barrels)
    8,987,000       9,211,000       (2.4 )%
Total sales
  $ 1,637.8     $ 1,641.0       (0.2 )%
                         
Total sales volume (in barrels)
    17,397,000       18,376,000       (5.3 )%
                         
 
 
(1) Represents fuels produced in connection with the production of specialty products at the Princeton and Cotton Valley 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.
 
This $3.2 million decrease in sales resulted from a $46.4 million decrease in sales in the specialty products segment and a $43.2 increase in sales in the fuel products segment.
 
Specialty products segment sales for 2007 decreased $46.4 million, or 5.1%, primarily due to a 8.2% decrease in volumes sold, from approximately 9.2 million barrels in 2006 to approximately 8.4 million barrels in 2007. Decreased volumes were driven by lower sales of lubricating oils and asphalt and by-products. Lubricating oils sales volume decreased primarily due to higher demand for certain lubricating oils at the Princeton refinery due to the hurricane season of 2005 creating a brief decline in supply from our competitors in 2006 combined with reduced production at our Shreveport refinery. The reduced production at our Shreveport refinery was due to our decision to reduce production levels during the third and fourth quarters of 2007 due to the unfavorable incremental refining margins related to the rising cost of crude oil as well as unscheduled downtime of certain units at our Shreveport refinery in the first quarter of 2007. This decrease was partially offset by a 3.4% increase in the average selling price per barrel of specialty products. Average selling prices per barrel for lubricating oils, solvents, waxes, fuels, and asphalt and by-products all individually increased at rates below the overall 10.4% increase in our cost of crude oil per barrel during the period due to the rapidly changing and volatile market conditions.
 
Fuel products segment sales for 2007 increased $43.2 million, or 5.9%, due to an 13.3% increase in the average selling price per barrel, which exceeded the overall 10.4% increase in the cost of crude oil per barrel for the period.


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This increase was partially offset by a 2.4% decrease in fuel products sales volumes sold attributable to lower production at our Shreveport refinery. The reduced production at our Shreveport refinery was due to our decision to reduce production levels during the third and fourth quarters of 2007 as a result of the unfavorable incremental refining margins related to the rising cost of crude oil as well as unscheduled downtime of certain units at our Shreveport refinery in the first quarter of 2007. Fuel products segment sales were also negatively affected by increased derivative losses of $33.6 million on our fuel products cash flow hedges recorded to sales for 2007 as compared to the prior year.
 
Gross Profit.  Gross profit decreased $23.6 million, or 11.5%, to $181.4 million for 2007 from $204.9 million for 2006. Gross profit for our specialty and fuel products segments were as follows:
 
                         
    Year Ended December 31,  
    2007     2006     % Change  
    (Dollars in millions)  
 
Gross profit by segment:
                       
Specialty products
  $ 115.4     $ 154.0       (25.1 )%
Percentage of sales
    13.3 %     16.9 %        
Fuel products
  $ 66.0     $ 50.9       29.6 %
Percentage of sales
    8.6 %     7.0 %        
Total gross profit
  $ 181.4     $ 204.9       (11.5 )%
Percentage of sales
    11.1 %     12.5 %        
 
This $23.6 million decrease in total gross profit includes a decrease in gross profit of $38.7 million in the specialty products segment offset by a $15.1 million increase in gross profit in the fuel products segment.
 
The decrease in the specialty products segment gross profit was primarily due the rising cost of crude oil outpacing increases in the selling price per barrel of our specialty products, decreased sales volumes and increased operating costs due to higher maintenance expense. The cost of crude oil increased by approximately 10.4% over prior year while the average selling price per barrel increased by only 3.4%. Sales volume decreased 8.2% primarily related to lubricating oils as well as asphalt and by-products. These decreases in segment gross profit were partially offset by increased derivative gains of $10.6 million on our cash flow hedges of crude oil and natural gas purchases for 2007 as compared to the prior year as well as increased LIFO gains of $10.6 million from the liquidation of lower cost layers of inventory as compared to current costs.
 
The increase in the fuel products segment gross profit of $15.1 million was primarily the result of the average selling price increasing by 13.3% as compared to the increase in our average cost of crude of 10.4%. Additionally, we experienced higher material costs in 2006 from the use of certain gasoline blendstocks to maintain compliance with environmental regulations in the fourth quarter of 2006, with no such activity in 2007. These increases were partially offset by a 2.4% decrease in fuel sales volumes and increased derivative losses on our fuel products hedges of $11.4 million. In addition, for 2007 the fuel products segment recognized increased LIFO gains of $7.1 million from the liquidation of lower cost layers of inventory as compared to current costs.
 
Selling, general and administrative.  Selling, general and administrative expenses decreased $0.8 million, or 4.0%, to $19.6 million in 2007 from $20.4 million in 2006. This decrease is primarily due to decreased annual incentive bonuses to our executive management, as no incentive bonuses were earned by executive management for 2007. This decrease was partially offset by increased costs associated with compliance with Section 404 of the Sarbanes-Oxley Act of 2002.
 
Transportation.  Transportation expenses decreased $2.9 million, or 5.1%, to $54.0 million in 2007 from $56.9 million in 2006. This decrease is primarily related to decreased Company sales volume on specialty products, which decreased by 8.2% over the prior year, which was partially offset by higher rail rates.
 
Interest expense.  Interest expense decreased $4.3 million, or 47.8%, to $4.7 million in 2007 from $9.0 million in 2006. This decrease was primarily due to increased capitalized interest as a result of capital expenditures on the Shreveport refinery expansion project.


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Interest income.  Interest income decreased $1.0 million to $1.9 million in 2007 from $3.0 million in 2006. This decrease was primarily due to a larger average cash and cash equivalents balance in the year ended December 31, 2006 as compared to 2007 due to the proceeds from the public equity offering in July 2006, of which the entire $103.5 million was utilized on the Shreveport refinery expansion project during 2006 and 2007.
 
Debt extinguishment costs.  Debt extinguishment costs decreased to $0.4 million in 2007 compared to $3.0 million in 2006. Debt extinguishment costs were $0.4 million for the year ended December 31, 2007 due to the repayment of approximately $19.0 million of borrowings under the Company’s term loan facility in the third quarter of 2007 in connection with an amendment to our credit facilities. For 2006, the debt extinguishment costs of $3.0 million resulted from the repayment of a portion of borrowings under Calumet’s term loan and revolving credit facilities using the proceeds of the initial public offering, which closed on January 31, 2006.
 
Realized loss on derivative instruments.  Realized loss on derivative instruments decreased $17.8 million to a $12.5 million loss in 2007 from a $30.3 million loss in 2006. This decreased loss primarily was the result of the unfavorable settlement in 2006 on certain derivatives not designated as cash flow hedges with no similar settlements in 2007.
 
Unrealized gain (loss) on derivative instruments.  Unrealized gain (loss) on derivative instruments decreased $13.6 million, to a $1.3 million loss in 2007 from a $12.3 million gain in 2006. This decrease is primarily due to the unfavorable mark-to-market change related to the ineffective portion of certain derivative instruments designated as cash flow hedges. Unrealized loss on derivative instruments was also negatively affected by an unfavorable market change on our interest rate swap, which is not designated as a cash flow hedge due to the impact of the refinancing of our term loan debt on January 3, 2008.
 
Liquidity and Capital Resources
 
Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions and debt service. We expect that our principal uses of cash in the future will be for working capital as we continue to increase our throughput rate at the Shreveport refinery, distributions to our limited partners and general partner, debt service, and capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and cause us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs. Given the current credit environment and our continued efforts to reduce leverage to ensure continued covenant compliance under our credit facilities, we do not anticipate completing any significant acquisitions, internal growth projects or replacement and environmental capital expenditures which would cause total spending to exceed $25.0 million during 2009. With the uncertain status of the credit and equity markets we anticipate future capital expenditures will be funded with current cash flows from operations and borrowings under our existing revolving credit facility.
 
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 change 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.


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The following table summarizes our primary sources and uses of cash in each of the most recent three years:
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In millions)  
 
Net cash provided by operating activities
  $ 130.3     $ 167.5     $ 166.8  
Net cash used in investing activities
  $ (480.5 )   $ (260.9 )   $ (75.8 )
Net cash provided by (used in) financing activities
  $ 350.1     $ 12.4     $ (22.2 )
 
Operating Activities.  Operating activities provided $130.3 million in cash during 2008 compared to $167.5 million during 2007. The decrease in cash provided by operating activities during 2008 was primarily due to increased working capital of $35.5 million, combined with a decrease of net income, after adjusting for non-cash items, of $1.7 million. The increase in working capital was due primarily to the decrease in accounts payable resulting from significantly lower crude oil and other feedstock prices at December 31, 2008 as compared to December 31, 2007 and the impacts of derivative activity. The reduction in accounts payable was partially offset by significant decreases in inventory and accounts receivable as a result of our working capital reduction initiatives and lower crude oil prices and fuel products selling prices.
 
Operating activities provided $167.5 million in cash during 2007 compared to $166.8 million in cash during 2006. The cash provided by operating activities during 2007 primarily consisted of net income, after adjusting for non-cash items, of $101.4 million and $66.1 million of reductions in working capital. Net income, after adjustments for non-cash items, decreased by $12.5 million in 2007 from $113.9 million in 2006. The reduction in working capital was primarily due to an incremental $55.2 million increase in accounts payable compared to 2006 primarily as a result of improvements in payment terms with crude oil suppliers combined with rising crude oil costs. This increase in accounts payable was offset by a $31.1 million increase in accounts receivable primarily as a result of higher sales prices in the fourth quarter of 2007 as compared to the same period in 2006.
 
Investing Activities.  Cash used in investing activities increased to $480.5 million during 2008 compared to $260.9 million during 2007. This increase was primarily due to the acquisition of Penreco for $269.1 million. Also increasing the use of cash for investing activities was the settlement of $49.7 million of derivative instruments utilized to economically hedge the risk of rising crude oil prices. As crude oil prices declined significantly during the last six months of 2008, the realized losses on these derivative instruments increased. Offsetting this increased use of cash was a decrease of $93.3 million in capital expenditures in 2008 compared to 2007. The majority of the capital expenditures were incurred at our Shreveport refinery, with $119.6 million related to the Shreveport refinery expansion project incurred in 2008 as compared to $188.9 million incurred in 2007. The remaining decrease in capital expenditures of $24.0 million primarily related to lower spending on various other capital projects at our Shreveport refinery compared to the prior year. Further offsetting the increased use of cash was the $6.1 million of cash proceeds received as a result of selling certain mineral rights on our real property at our Shreveport and Princeton refineries to a third party during the second quarter of 2008.
 
Cash used in investing activities increased to $260.9 million during 2007 as compared to $75.8 million during 2006. This increase was primarily due to an increase of $185.0 million in capital expenditures over 2006. The majority of the capital expenditures were incurred at our Shreveport refinery, with $188.9 million related to the Shreveport refinery expansion project incurred in 2007 as compared to $65.5 million incurred in 2006 for this project. The remaining increase of $61.6 million related primarily to various other capital projects at our Shreveport refinery to replace certain assets, improve efficiency, de-bottleneck certain specialty products operating units and for new product development.
 
Financing Activities.  Financing activities provided cash of $350.1 million during 2008 as compared to $12.4 million during 2007. This change was primarily due to borrowings under the new senior secured term loan credit facility along with associated debt issuance costs. A portion of the new term loan proceeds of $385.0 million was used to finance the acquisition of Penreco. The increase was also due to a $88.6 million increase in borrowings on our revolving credit facility, primarily due to spending on the Shreveport refinery expansion project. These increases were offset by uses of cash to repay our old term loan of $10.7 million, increased debt issuance costs of $9.3 million and repayments under the new term loan of $9.9 million. The repayments under the new term loan are approximately $1.0 million per quarter. We sold certain mineral rights and our term loan credit agreement required


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that the proceeds of $6.1 million be used to repay an equal portion of the term loan. Our distributions to partners decreased $10.9 million as we reduced our distribution early in 2008 to our minimum quarterly distribution of $0.45 per unit.
 
Financing activities provided cash of $12.4 million during 2007 compared to using $22.2 million during 2006. This increase is primarily related to decreased repayments on debt in 2007 as compared to 2006 as well as reduced proceeds from public offerings of $100.3 million. These increases were offset by an increase in distributions to partners of $38.8 million.
 
On January 22, 2009, the Company declared a quarterly cash distribution of $0.45 per unit on all outstanding units, or $14.8 million, for the quarter ended December 31, 2008. The distribution was paid on February 13, 2009 to unitholders of record as of the close of business on February 3, 2009. This quarterly distribution of $0.45 per unit equates to $1.80 per unit, or $59.2 million, 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 and to expand existing facilities, such as projects that increase operating capacity. 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.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    ( In millions)  
 
Capital improvement expenditures
  $ 161.6     $ 248.8     $ 69.9  
Replacement capital expenditures
    4.4       10.9       4.5  
Environmental expenditures
    1.7       1.3       1.7  
                         
Total
  $ 167.7     $ 261.0     $ 76.1  
                         
 
We anticipate that future capital expenditure requirements will be provided through cash provided by operations and available borrowings under our revolving credit facility unless the debt and equity capital markets improve in the near term. Management expects to invest up to $10 million in expenditures at its various locations during 2009 to complete the majority of our items in construction in progress related to improving our product mix or operating cost leverage. In addition, management estimates its replacement and environmental capital expenditures to be approximately $3.5 million per quarter. Our Shreveport refinery expansion project and the Penreco acquisition have demonstrated an increase in cash flow from operations on a per unit basis which has restored our ability to issue common units in certain circumstances back to the maximum level defined in our partnership agreement, or 6,533,000 common units.
 
During the last three years, we invested significantly in expanding and enhancing the operations at our facilities, primarily at our Shreveport refinery. We invested a total of approximately $161.6 million, $248.8 million and $69.9 million during 2008, 2007 and 2006, respectively. Of these investments during these periods, $374.0 million relates to our Shreveport refinery expansion project.
 
The Shreveport refinery expansion project was completed and operational in May 2008. The Shreveport expansion project has increased this refinery’s throughput capacity from 42,000 bpd to 60,000 bpd. For 2008, the Shreveport refinery had total feedstock runs of 37,096 bpd, which represents an increase of approximately 2,744 bpd from 2007, before completion of the Shreveport expansion project. The Shreveport refinery did not achieve the expected significant increase in feedstock runs year over year due primarily to unscheduled downtime due to hurricane Ike and scheduled downtime in the fourth quarter to complete a three-week turnaround. In 2009, feedstock run rates at Shreveport have averaged approximately 50,000 bpd.


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As part of this expansion project, we enhanced the Shreveport refinery’s ability to process sour crude oil. During the fourth quarter of 2008, we processed approximately 12,400 bpd of sour crude oil at the Shreveport refinery and we anticipate running up to 19,000 bpd of sour crude oil at the Shreveport refinery in the current environment. In certain operating scenarios where overall throughput is reduced, we expect we will be able to increase sour crude oil throughput rates up to approximately 25,000 bpd.
 
Additionally, for 2008 and 2007, we invested $40.8 million and $65.6 million, respectively, in our Shreveport refinery for other capital expenditures, including projects to improve efficiency, de-bottleneck certain operating units and for new product development. These expenditures are anticipated to enhance and improve our product mix and operating cost leverage, but will not significantly increase the feedstock throughput capacity of the Shreveport refinery. We estimate that by March 31, 2009 we will have placed in service $19.3 million of our total $25.1 million in construction in progress.
 
Debt and Credit Facilities
 
On January 3, 2008, we repaid all of our indebtedness under our previous senior secured first lien term loan credit facility, entered into new senior secured first lien term loan facility and amended our existing senior secured revolving credit facility. As of December 31, 2008, our credit facilities consist of:
 
  •  a $375.0 million senior secured revolving credit facility, subject to borrowing base restrictions, with a standby letter of credit sublimit of $300.0 million; and
 
  •  a $435.0 million senior secured first lien credit facility consisting of a $385.0 million term loan facility and a $50.0 million letter of credit facility to support crack spread hedging. In connection with the execution of the above senior secured first lien credit facility, we incurred total debt issuance costs of $23.4 million, including $17.4 million of issuance discounts.
 
Borrowings under the amended revolving credit facility are limited by advance rates of percentages of eligible accounts receivable and inventory (the borrowing base) as defined by the revolving credit 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. The borrowing base cannot exceed the total commitments of the lender group. The lender group under our revolving credit facility is comprised of a syndicate of nine lenders with total commitments of $375.0 million. The number of lenders in our facility has been reduced from ten due to an acquisition. If further acquisitions occur, we will increase the concentration of our exposure to certain financial institutions. Currently, the largest member of our bank group provides a commitment for $87.5 million. The smallest commitment is $15 million and the median commitment is $42.5 million. In the event of a default by one of the lenders in the syndicate, the total commitments under the revolving credit facility would be reduced by the defaulting lenders’ commitment, unless another lender or a combination of lenders increase their commitments to replace the defaulting lender. In the alternative, the revolving credit facility also permits us to replace a defaulting lender. Although we do not expect any current lenders to default under the revolving credit facility, we can provide no assurances. Also, our borrowing base at December 31, 2008 was $175.8 million, thus, we would have to experience defaults in commitments totaling $199.2 million from our lender group before it would impact our liquidity as of December 31, 2008. This would require at least three of our nine lenders to default in order for it to impact our current liquidity position under the revolving credit facility.
 
The revolving credit facility, which is our primary source of liquidity for cash needs in excess of cash generated from operations, currently bears interest at prime plus a basis points margin or LIBOR plus a basis points margin, at our option. This margin is currently at 50 basis points for prime and 200 basis points for LIBOR; however, it fluctuates based on measurement of our Consolidated Leverage Ratio discussed below. The revolving credit facility has a first priority lien on our cash, accounts receivable and inventory and a second priority lien on our fixed assets and matures in January 2013. On December 31, 2008, we had availability on our revolving credit facility of $51.9 million, based upon a $175.8 million borrowing base, $21.4 million in outstanding standby letters of credit, and outstanding borrowings of $102.5 million. The recent drop in crude oil prices has improved our gross profit; however, it has also caused a reduction in the market value of our inventory and resulted in a lower borrowing base. After paying our quarterly distribution of $14.8 million on February 13, 2009, our availability under the revolving credit facility was consistent with December 31, 2008. We believe that we have sufficient cash flow from operations


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and borrowing capacity to meet our financial commitments, debt service obligations, contingencies 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 or a significant, sustained decline 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. Further substantial declines in crude oil prices, if sustained, may materially diminish our borrowing base which is based, in part, on the value of our crude oil inventory and could result in a material reduction in our borrowing capacity under our revolving credit facility.
 
The term loan facility, fully drawn at $385.0 million on January 3, 2008, bears interest at a rate of LIBOR plus 400 basis points or prime plus 300 basis points, at our option. Management has historically kept the outstanding balance on a LIBOR basis, however, that decision is evaluated every three months to determine if a portion is to be converted back to the prime rate. Each lender under this facility has a first priority lien on our fixed assets and a second priority lien on our cash, accounts receivable and inventory. Our term loan facility matures in January 2015. Under the terms of our term loan facility, we applied a portion of the net proceeds from the term loan facility to the acquisition of Penreco. We are required to make mandatory repayments of approximately $1.0 million at the end of each fiscal quarter, beginning with the fiscal quarter ended March 31, 2008 and ending with the fiscal quarter ending September 30, 2014, with the remaining balance due at maturity on January 3, 2015. In June 2008, we received lease bonuses of $6.1 million associated with the sale of mineral rights on our real property at our Shreveport and Princeton refineries to a non-affiliated third party. As a result of these transactions, we recorded a gain of $5.8 million in other income (expense) in the consolidated statements of operations. Under the term loan agreement, cash proceeds resulting from the disposition of our property, plant and equipment generally must be used as a mandatory prepayment of the term loan. As a result, we made a prepayment of $6.1 million in June 2008 on the term loan.
 
Our letter of credit facility to support crack spread hedging bears interest at a rate of 4.0% and is secured by a first priority lien on our fixed assets. We have issued a letter of credit in the amount of $50.0 million, the full amount available under this letter of credit facility, to one counterparty. As long as this first priority lien is in effect and such counterparty remains the beneficiary of the $50.0 million letter of credit, we will have no obligation to post additional cash, letters of credit or other collateral with such counterparty to provide additional credit support for a mutually-agreed maximum volume of executed crack spread hedges. In the event such counterparty’s exposure to us exceeds $100.0 million, we would be required to post additional credit support to enter into additional crack spread hedges up to the aforementioned maximum volume. In addition, we have other crack spread hedges in place with other approved counterparties under the letter of credit facility whose credit exposure to us is also secured by a first priority lien on our fixed assets.
 
The credit facilities permit us to make distributions to our unitholders as long as we are not in default and would not be in default following the distribution. Under the credit facilities, we are obligated to comply with certain financial covenants requiring us to maintain a Consolidated Leverage Ratio of no more than 4.0 to 1 and a Consolidated Interest Coverage Ratio of no less than 2.50 to 1 (as of the end of each fiscal quarter and after giving effect to a proposed distribution or other restricted payments as defined in the credit agreement) and Available Liquidity of at least $35.0 million (after giving effect to a proposed distribution or other restricted payments as defined in the credit agreements). Both the Consolidated Leverage Ratio steps down from 4.0 to 1 to 3.75 to 1 and the Consolidated Interest Coverage Ratio steps up from 2.50 to 1 to 2.75 to 1 effective with the quarter ended June 30, 2009. The Consolidated Leverage Ratio is defined under our credit agreements to mean the ratio of our Consolidated Debt (as defined in the credit agreements) as of the last day of any fiscal quarter to our Adjusted EBITDA (as defined below) for the last four fiscal quarter periods ending on such date. During fiscal year 2008, the credit facilities permitted the inclusion of a prorated portion of Penreco’s estimated Adjusted EBITDA from 2007 in measuring compliance with these covenants. The Consolidated Interest Coverage Ratio is defined as the ratio of Consolidated EBITDA for the last four fiscal quarters to Consolidated Interest Charges for the same period. Available Liquidity is a measure used under our revolving credit facility and is the sum of the cash and borrowing capacity that we have as of a given date. Adjusted EBITDA means Consolidated EBITDA as defined in our credit facilities to mean, for any period: (1) net income plus (2)(a) interest expense; (b) taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) unrealized items


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decreasing net income (including the non-cash impact of restructuring, decommissioning and asset impairments in the periods presented); (f) other non-recurring expenses reducing net income which do not represent a cash item for such period; and (g) all non-recurring restructuring charges associated with the Penreco acquisition minus (3)(a) tax credits; (b) unrealized items increasing net income (including the non-cash impact of restructuring, decommissioning and asset impairments in the periods presented); (c) unrealized gains from mark to market accounting for hedging activities; and (d) other non-recurring expenses and unrealized items that reduced net income for a prior period, but represent a cash item in the current period.
 
In addition, if at any time that our borrowing capacity under our revolving credit facility falls below $35.0 million, meaning we have Available Liquidity of less than $35.0 million, we will be required to immediately measure and maintain a Fixed Charge Coverage Ratio of at least 1 to 1 (as of the end of each fiscal quarter). The Fixed Charge Coverage Ratio is defined under our credit agreements to mean the ratio of (a) Adjusted EBITDA minus Consolidated Capital Expenditures minus Consolidated Cash Taxes, to (b) Fixed Charges (as each such term is defined in our credit agreements).
 
During 2008, we experienced adverse financial conditions primarily attributable with historically high crude oil price volatility, which negatively affected our operations during 2008. Also contributing to these adverse financial conditions were higher borrowings required to fund the completion of the Shreveport refinery expansion project. Compliance with the financial covenants pursuant to our credit agreements is measured quarterly based upon performance over the most recent four fiscal quarters, and as of December 31, 2008, we were in compliance with all financial covenants under our credit agreements. We are continuing to take steps to ensure that we continue to meet the requirements of our credit agreements and currently believe that we will be in compliance for all future measurement dates. These steps include the following:
 
Increased Flexibility in Our Crude Oil Price Hedging for Specialty Products Segment
 
We remain committed to an active hedging program to manage commodity price risk in both our specialty products and fuel products segments. Due to the volatility of the price of crude oil and the impact such volatility has had on our short-term cash flows, we modified our hedging strategy to allow increased flexibility in the overall portion of input prices for specialty products we may hedge, the time horizon we may hedge and the types of derivative instruments we may use. Specifically, we have targeted the use of derivative instruments, primarily combinations of options, to mitigate our exposure to changes in crude oil prices for up to 75% of our specialty products production as conditions warrant. Generally, we believe that a time horizon of hedging crude oil purchases ranging from 3 to 9 months forward for our specialty products segment is appropriate given our general ability to manage our specialty products prices. We continue to consider current crude oil prices, specialty products gross profit expectations and liquidity as the primary factors to determine the volume, time horizon and type of derivative instruments we may execute. We plan to continue to use derivative instruments to achieve our goal of limiting crude oil price volatility in our operations. Due to the current economic environment and the complexities around derivative instruments, we intend to maintain flexibility in the manner in which we hedge. At December 31, 2008, we had approximately 7,700 barrels per day of crude oil hedges in January 2009 through March 2009 and are at the lower end of our targeted volume range of hedges for our specialty products segment. Through February 26, 2009, we have added no additional crude oil hedges for our specialty products segment.
 
During the last five fiscal quarters, October 1, 2007 through December 31, 2008, we have experienced significant crude oil price volatility. As a result, we have realized derivative gains (losses) in our specialty products segment over these five quarters of $5.3 million, $6.4 million, $16.4 million, $(7.3) million and $(40.6) million, respectively, for a total loss during the period of $(19.8) million. This loss includes approximately $15.8 million of losses related to crude oil derivatives related to 2009 that were early settled during the fourth quarter of 2008. We believe that our hedging program has been effective at offsetting a portion of volatility in our specialty products segment’s quarterly gross profit.
 
As of December 31, 2008 and February 26, 2009, we have provided cash margin of $4.0 million and $0.4 million, respectively, in credit support to certain of our hedging counterparties. Currently, we do not expect to have a significant exposure to additional margin calls from our derivative counterparties due to the reduced number of barrels hedged and the use of 4-way collars that have a limited exposure to crude oil price decreases. Please read


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Item 7A “Quantitative and Qualitative Disclosures about Market Risk — Existing Commodity Derivative Instruments” for derivative instruments outstanding as of December 31, 2008.
 
Working Capital Reduction
 
We continue to implement strategies to reduce our working capital requirements across all of our operations and we expect to maintain prudent levels of working capital to enhance liquidity given our plans for higher Shreveport refinery run rates in 2009. As an example, effective May 1, 2008 we entered into a crude oil supply agreement with an affiliate of our general partner to purchase crude oil used at our Princeton refinery on a just-in-time basis, which significantly reduced crude oil inventory historically maintained for this refinery by approximately 200,000 barrels. Excluding inventory related to the Penreco acquisition, we have reduced our total inventory levels by approximately 640,000 barrels, or approximately 29.8% as of December 31, 2008 as compared to December 31, 2007. Additionally, on January 26, 2009 we entered into a second crude oil supply agreement with the same affiliate of our general partner to supply a portion of the crude oil for our Shreveport refinery with favorable payment terms that will allow us to further reduce our working capital requirements and enhance liquidity.
 
Continued Integration of the Penreco Acquisition
 
During the first nine months of 2008, we implemented multiple price increases for various specialty product lines acquired in the Penreco acquisition to attempt to keep pace with rising feedstock costs. In addition, we have implemented a pricing policy which we believe is more responsive to rising feedstock prices to limit the time between feedstock price increases and product price increases to customers. We are also implementing operational strategies, including using various existing Calumet refinery products as feedstocks in the acquired Penreco plant operations, and we have reduced headcount by approximately 50 employees.
 
While assurances cannot be made regarding our future compliance with these covenants and being cognizant of the general uncertain economic environment, we anticipate that our strategic initiatives discussed above will allow us to maintain compliance with such financial covenants and improve our Adjusted EBITDA, liquidity and distributable cash flows.
 
Failure to achieve our anticipated results may result in a breach of certain of the financial covenants contained in our credit agreements. If this occurs, we will enter into discussions with our lenders to either modify the terms of the existing credit facilities or obtain waivers of non-compliance with such covenants. There can be no assurances of the timing of the receipt of any such modification or waiver, the term or costs associated therewith or our ultimate ability to obtain the relief sought. Our failure to obtain a waiver of non-compliance with certain of the financial covenants or otherwise amend the credit facilities would constitute an event of default under our credit facilities and would permit the lenders to pursue remedies. These remedies could include acceleration of maturity under our credit facilities and limitations on, or the elimination of, our ability to make distributions to our unitholders. If our lenders accelerate maturity under our credit facilities, a significant portion of our indebtedness may become due and payable immediately. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. If we are unable to make these accelerated payments, our lenders could seek to foreclose on our assets.
 
In addition, our credit agreements contain various covenants that limit our ability, among other things, to: incur indebtedness; grant liens; make certain acquisitions and investments; make capital expenditures above specified amounts; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; enter into a merger, consolidation or sale of assets; and cease our refining margin hedging program (our lenders have required us to obtain and maintain derivative contracts for fuel products margins in our fuel products segment for a rolling period of 1 to 12 months for at least 60% and no more than 90% of our anticipated fuels production, and for a rolling 13-24 months forward for at least 50% and no more than 90% of our anticipated fuels production).
 
If an event of default exists under our credit agreements, the lenders will be able to accelerate the maturity of the credit facilities and exercise other rights and remedies. An event of default is defined as 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 credit agreement or other loan documents, subject to


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certain grace periods; payment defaults in respect of other indebtedness; cross-defaults in other indebtedness if the effect of such default is to cause the acceleration of such indebtedness under any material agreement if such default could have a material adverse effect on us; bankruptcy or insolvency events; monetary judgment defaults; asserted invalidity of the loan documentation; and a change of control in us. We believe we are in compliance with all debt covenants and have adequate liquidity to conduct our business as of December 31, 2008.
 
Contractual Obligations and Commercial Commitments
 
A summary of our total contractual cash obligations as of December 31, 2008, is as follows:
 
                                         
          Payments Due by Period  
          Less Than
    1-3
    3-5
    More Than
 
    Total     1 Year     Years     Years     5 Years  
    (In thousands)  
 
Long-term debt obligations
  $ 477,624     $ 3,850     $ 7,700     $ 110,239     $ 355,835  
Interest on long-term debt at contractual rates
    165,267       30,808       59,972       49,674       24,813  
Capital lease obligations
    2,640       961       1,354       325        
Operating lease obligations (1)
    45,688       12,665       18,287       10,661       4,075  
Letters of credit (2)
    71,355       21,355             50,000        
Purchase commitments (3)
    149,613       149,613                    
Pension obligations
    13,000             8,000       5,000        
Employment agreements (4)
    773       371       402              
                                         
Total obligations
  $ 925,960     $ 219,623     $ 95,715     $ 225,899     $ 384,723  
                                         
 
 
(1) We have various operating leases for the use of land, storage tanks, pressure stations, railcars, equipment, precious metals and office facilities that extend through August 2015.
 
(2) Letters of credit supporting crude oil purchases, precious metals leasing and hedging activities.
 
(3) Purchase commitments consist of obligations to purchase fixed volumes of crude oil from various suppliers based on current market prices at the time of delivery.
 
(4) Annual compensation under the employment agreement of F. William Grube, chief executive officer and president.
 
In connection with the closing of the Penreco acquisition 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 are obligated to purchase $37.4 million of feedstock for the LVT unit in each of the next four years based on pricing estimates as of December 31, 2008. 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
 
Our discussion and analysis of results of operations and financial condition are based upon our consolidated financial statements for the years ended December 31, 2008, 2007 and 2006. These consolidated financial statements have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in those financial statements. On an ongoing basis, we evaluate estimates and base our estimates on historical experience and assumptions believed to be reasonable under the circumstances. Those estimates form the basis for our judgments that affect the amounts


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reported in the financial statements. Actual results could differ from our estimates under different assumptions or conditions. Our significant accounting policies, which may be affected by our estimates and assumptions, are more fully described in Note 2 to our consolidated financial statements in Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.
 
Revenue Recognition
 
We recognize revenue on orders received from our customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under our normal billing and credit terms, and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.
 
Income Taxes
 
As previously disclosed in our Annual Report on Form 10-K for the year ending December 31, 2007, we requested a ruling from the IRS with respect to the qualifying nature of income generated from the Penreco assets and business operations. In the fourth quarter of 2008, the IRS provided a favorable ruling, upon which we will rely to own the Penreco assets and operate the Penreco business within our existing flow-through tax structure.
 
Inventories
 
The cost of inventories is determined using the last-in, first-out (LIFO) method. Costs include crude oil and other feedstocks, labor and refining overhead costs. We review our inventory balances quarterly for excess inventory levels or obsolete products and write down, if necessary, the inventory to net realizable value. The replacement cost of our inventory, based on current market values, would have been $27.5 million and $107.9 million higher at December 31, 2008 and 2007, respectively.
 
Fair Value of Financial Instruments
 
In accordance with Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138 and in May 2003 by SFAS No. 149 (collectively referred to as “SFAS 133”), the Company recognizes all derivative transactions as either assets or liabilities at fair value on the consolidated balance sheets. The Company utilized third party valuations and published market data to determine the fair value of these derivatives and thus does not directly rely on market indices. The Company performs an independent verification of the third party valuation statements to validate inputs for reasonableness and completes a comparison of implied crack spread mark-to-market valuations among our counterparties.
 
The Company’s derivative instruments, consisting of derivative assets and derivative liabilities of $71.2 million and $15.8 million, respectively, as of December 31, 2008, are valued at Level 1, Level 2, and Level 3 fair value measurement under SFAS No. 157, Fair Value Measurements, depending upon the degree by which inputs are observable. The Company’s derivative instruments are the only assets and liabilities measured at fair value as of December 31, 2008. The Company recorded unrealized gains of derivative instruments and realized losses on derivative instruments of $3.5 million and $58.8 million, respectively, on our derivative instruments in 2008. The increase in the fair market value of our outstanding derivative instruments from a net liability of $57.5 million as of December 31, 2007 to a net asset of $55.4 million as of December 31, 2008 was primarily due to decreases in the forward market values of fuel products margins, or cracks spreads, relative to our hedged fuel products margins. The Company believes that the fair values of our derivative instruments may diverge materially from the amounts currently recorded to fair value at settlement due to the volatility of commodity prices.


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Holding all other variables constant, we expect a $1 increase in these commodity prices would change our recorded mark-to-market valuation by the following amounts based upon the volume hedged as of December 31, 2008:
 
         
    In millions  
 
Crude oil swaps
  $ (18.5 )
Diesel swaps
  $ 11.9  
Gasoline swaps
  $ 6.7  
Crude oil collars
  $ (0.7 )
Natural gas swaps
  $ (0.3 )
 
The Company enters into crude oil, gasoline, and diesel hedges to hedge an implied crack spread. Therefore, any increase in crude oil swap mark-to-market valuation due to changes in commodity prices will generally be accompanied by a decrease in gasoline and diesel swap mark-to-market valuation.
 
Recent Accounting Pronouncements
 
In September 2006, the FASB issued FASB Statement No. 157, Fair Value Measurements (the “Statement”). The Statement applies to assets and liabilities required or permitted to be measured at fair value under other accounting pronouncements. The Statement defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements about fair value, but does not provide guidance whether assets and liabilities are required or permitted to be measured at fair value. The Statement was effective for fiscal years beginning after November 15, 2007. The Company adopted the Statement on January 1, 2008 and applied the various disclosures as required by the Statement. The Statement did not have a material affect on our financial position, results of operations or cash flows. In February 2008, the FASB agreed to defer for one year the effective date of the Statement for certain nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.
 
In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (the “Position”), which amends certain aspects of FASB Interpretation Number 39, Offsetting of Amounts Related to Certain Contracts. The Position permits companies to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The Position is effective for fiscal years beginning after November 15, 2007. The Company adopted the Position on January 1, 2008 and the adoption did not have a material effect on our financial position, results of operations, or cash flows.
 
In December 2007, the FASB issued FASB Statement No. 141(R), Business Combinations (the “Statement”). The Statement applies to the financial accounting and reporting of business combinations. The Statement is effective for business combination transactions for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company anticipates that the Statement will not have a material effect on its financial position, results of operations, or cash flows.
 
In March 2008, the FASB issued FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS 133 have been applied, and the impact that hedges have on an entity’s financial position, results of operations, and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company currently provides an abundance of information about its hedging activities and use of derivatives in its quarterly and annual filings with the SEC, including many of the disclosures contained within SFAS 161. Thus, the Company currently does not anticipate the adoption of SFAS 161 will have a material impact on the disclosures already provided.
 
In March 2008, FASB issued Emerging Issues Task Force Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“EITF 07-4”). EITF 07-4 requires master limited


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partnerships to treat incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to pay IDRs. EITF 07-4 requires that undistributed earnings be allocated to the partnership interests based on the allocation of earnings to capital accounts as specified in the respective partnership agreement. When distributions exceed earnings, EITF 07-4 requires that net income be reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the respective partnership agreement. EITF 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Company is evaluating the potential impacts of EITF 07-4 and will adopt the new requirements for all future reporting periods.
 
In April 2008, the FASB issued FASB Staff Position No. 142-3, Determination of the Useful Life of Intangible Assets, (“FSP No. 142-3”) that amends the factors considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). FSP No. 142-3 requires a consistent approach between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of an asset under SFAS No. 141(R), Business Combinations. FSP No. 142-3 also requires enhanced disclosures when an intangible asset’s expected future cash flows are affected by an entity’s intent and/or ability to renew or extend the arrangement. FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and is applied prospectively. Early adoption is prohibited. The Company does not expect the adoption of FSP No. 142-3 to have a material impact on its consolidated results of operations or financial condition.
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
Commodity Price Risk
 
Both our profitability and our cash flows are affected by volatility in prevailing crude oil, gasoline, diesel, jet fuel, and natural gas prices which is consistent with prior years. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with the cost of crude oil and natural gas and sales prices of our fuel products.
 
Crude Oil Price Volatility
 
We are exposed to significant fluctuations in the price of crude oil, our principal raw material. Given the historical volatility of crude oil prices, this exposure can significantly impact product costs and gross profit. Holding all other variables constant, and excluding the impact of our current hedges, we expect a $1.00 change in the per barrel price of crude oil would change our specialty product segment cost of sales by $10.7 million and our fuel product segment cost of sales by $10.7 million based on our sales volumes for 2008.
 
Crude Oil Hedging Policy
 
Because we typically do not set prices for our specialty products in advance of our crude oil purchases, we can generally take into account the cost of crude oil in setting specialty products prices. However, during periods such as 2008 when crude oil prices ranged from a low of approximately $42 per barrel to a high of approximately $145 per barrel, we are not always able to adjust our sales prices as quickly as increases in the price of crude oil. Due to this lack of correlation between our specialty products sales prices and crude oil in periods of high volatility, we further manage our exposure to fluctuations in crude oil prices in our specialty products segment through the use of derivative instruments, which can include both swaps and options, generally executed in the over-the-counter (OTC) market. Our policy is generally to enter into crude oil derivative contracts that match our expected future cash out flows for up to 70% of our anticipated crude oil purchases related to our specialty products production. These positions generally will be short term in nature and expire within three to nine months from execution; however, we may execute derivative contracts for up to two years forward if our expected future cash flows support lengthening our position. During the first three quarters of 2008, we both lengthened the transaction period and increased the volume hedged to near these maximum levels of up to two years and for up to 70% of our projected crude oil purchasing volume for our specialty products segment. In the fourth quarter of 2008, we settled the majority of these forward positions and as of December 31, 2008 we are hedged at the lower end of our guideline


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and at a hedge percentage of approximately 25% of forecasted production through March 31, 2009. Our fuel products sales are based on market prices at the time of sale. Accordingly, in conjunction with our fuel products hedging policy discussed below, we enter into crude oil derivative contracts related to our fuel products segment for up to five years and no more than 75% of our fuel products sales on average for each fiscal year.
 
Natural Gas Price Volatility
 
Since natural gas purchases comprise a significant component of our cost of sales, changes in the price of natural gas also significantly affect our profitability and our cash flows. Holding all other cost and revenue variables constant, and excluding the impact of our current hedges, we expect a $0.50 change per MMBtu (one million British Thermal Units) in the price of natural gas would change our cost of sales by $3.7 million based on our results for the year ended December 31, 2008.
 
Natural Gas Hedging Policy
 
We enter into derivative contracts to manage our exposure to natural gas prices. Our policy is generally to enter into natural gas swap contracts during the summer months for up to approximately 50% of our anticipated natural gas requirements for the upcoming fall and winter months with time to expiration not to exceed three years.
 
Fuel Products Selling Price Volatility
 
We are exposed to significant fluctuations in the prices of gasoline, diesel, and jet fuel. Given the historical volatility of gasoline, diesel, and jet fuel prices, this exposure can significantly impact sales and gross profit. Holding all other variables constant, and excluding the impact of our current hedges, we expect that a $1 change in the per barrel selling price of gasoline, diesel, and jet fuel would change our fuel products segment sales by $10.3 million based on our results for the year ended December 31, 2008.
 
Fuel Products Hedging Policy
 
In order to manage our exposure to changes in gasoline, diesel, and jet fuel selling prices, our policy is generally to enter into derivative contracts to hedge our fuel products sales for a period no greater than five years forward and for no more than 75% of anticipated fuels sales on average for each fiscal year, which is consistent with our crude oil purchase hedging policy for our fuel products segment discussed above. We believe this policy lessens the volatility of our cash flows. In addition, in connection with our credit facilities, our lenders require us to obtain and maintain derivative contracts to hedge our fuel products margins for a rolling period of 1 to 12 months forward for at least 60% and no more than 90% of our anticipated fuels production, and for a rolling 13 to 24 months forward for at least 50% and no more than 90% of our anticipated fuels production. As of December 31, 2008, we were over 60% hedged for both the forward 12 and 24 month periods. We are currently hedging in calendar year 2011, with no positions currently in 2012 or 2013.
 
The unrealized gain or loss on derivatives at a given point in time is not necessarily indicative of the results realized when such contracts mature. The increase in the fair market value of our outstanding derivative instruments from a net liability of $57.5 million as of December 31, 2007 to a net asset of $55.4 million as of December 31, 2008 was primarily due to decreases in the forward market values of fuel products margins, or cracks spreads, relative to our hedged fuel products margins, offset by the impact of decreases in crude oil prices on our specialty products segment crude oil derivatives. Please read Note 2 — Derivatives in the notes to our consolidated financial statements for a discussion of the accounting treatment for the various types of derivative transactions, and a further discussion of our hedging policies.
 
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.


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We are exposed to market risk from fluctuations in interest rates. As of December 31, 2008, we had approximately $477.6 million of variable rate debt. Holding other variables constant (such as debt levels), a one hundred basis point change in interest rates on our variable rate debt as of December 31, 2008 would be expected to have an impact on net income and cash flows for 2008 of approximately $4.8 million.
 
We have a $375.0 million revolving credit facility as of December 31, 2008, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had borrowings of $102.5 million outstanding under this facility as of December 31, 2008, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin.
 
Existing Interest Rate Derivative Instruments
 
In 2008, the Company entered into a forward swap contract to manage interest rate risk related to its current variable rate senior secured first lien term loan which closed January 3, 2008. The Company has hedged the future interest payments related to $150.0 million and $50.0 million of the total outstanding term loan indebtedness in 2009 and 2010, respectively, pursuant to this forward swap contract.
 
This swap contract is designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at 3.09%, and 3.66% per annum in 2009 and 2010, respectively.
 
Existing Commodity Derivative Instruments
 
Fuel Products Segment
 
As a result of our fuel products hedging activity, we recorded a loss of $297.3 million and a gain of $285.0 million, to sales and cost of sales, respectively, in the consolidated statements of operations for 2008.
 
The following tables provide information about our derivative instruments related to our fuel products segment as of December 31, 2008:
 
                         
    Barrels
             
Crude Oil Swap Contracts by Expiration Dates
  Purchased     BPD     ($/Bbl)  
 
First Quarter 2009
    2,025,000       22,500     $ 66.26  
Second Quarter 2009
    2,047,500       22,500       66.26  
Third Quarter 2009
    2,070,000       22,500       66.26  
Fourth Quarter 2009
    2,070,000       22,500       66.26  
Calendar Year 2010
    7,300,000       20,000       67.29  
Calendar Year 2011
    3,009,000       8,244       76.98  
                         
Totals
    18,521,500                  
Average price
                  $ 68.41  
 
                         
Diesel Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    1,170,000       13,000     $ 80.51  
Second Quarter 2009
    1,183,000       13,000       80.51  
Third Quarter 2009
    1,196,000       13,000       80.51  
Fourth Quarter 2009
    1,196,000       13,000       80.51  
Calendar Year 2010
    4,745,000       13,000       80.41  
Calendar Year 2011
    2,371,000       6,496       90.58  
                         
Totals
    11,861,000                  
Average price
                  $ 82.48  
 


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Gasoline Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    855,000       9,500     $ 73.83  
Second Quarter 2009
    864,500       9,500       73.83  
Third Quarter 2009
    874,000       9,500       73.83  
Fourth Quarter 2009
    874,000       9,500       73.83  
Calendar Year 2010
    2,555,000       7,000       75.28  
Calendar Year 2011
    638,000       1,748       83.42  
                         
Totals
    6,660,500                  
Average price
                  $ 75.30  
 
The following table provides a summary of these derivatives and implied crack spreads for the crude oil, diesel and gasoline swaps disclosed above, all of which are designated as hedges.
 
                         
    Barrels
          Implied Crack
 
Swap Contracts by Expiration Dates
  Purchased     BPD     Spread ($/Bbl)  
 
First Quarter 2009
    2,025,000       22,500     $ 11.43  
Second Quarter 2009
    2,047,500       22,500       11.43  
Third Quarter 2009
    2,070,000       22,500       11.43  
Fourth Quarter 2009
    2,070,000       22,500       11.43  
Calendar Year 2010
    7,300,000       20,000       11.32  
Calendar Year 2011
    3,009,000       8,244       11.99  
                         
Totals
    18,521,500                  
Average price
                  $ 11.48  
 
At December 31, 2008, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $14.3 million of unrealized gains in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008. Refer to the gasoline swap contracts table below with corresponding barrel per day amounts for the related transactions.
 
                         
Crude Oil Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    450,000       5,000     $ 62.66  
Second Quarter 2009
    455,000       5,000       62.66  
Third Quarter 2009
    460,000       5,000       62.66  
Fourth Quarter 2009
    460,000       5,000       62.66  
                         
Totals
    1,825,000                  
Average price
                  $ 62.66  

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At December 31, 2008, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $15.9 million of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008. Refer to the crude oil swap contracts table above with corresponding barrel per day amounts for the related transactions.
 
                         
    Barrels
             
Gasoline Swap Contracts by Expiration Dates
  Purchased     BPD     ($/Bbl)  
 
First Quarter 2009
    450,000       5,000     $ 60.53  
Second Quarter 2009
    455,000       5,000       60.53  
Third Quarter 2009
    460,000       5,000       60.53  
Fourth Quarter 2009
    460,000       5,000       60.53  
                         
Totals
    1,825,000                  
Average price
                  $ 60.53  
 
To summarize at December 31, 2008, the Company had the following crude oil and gasoline derivative instruments not designated as hedges in its fuel products segment. These trades were used to economically freeze a portion of the mark-to-market valuation gain for the above crack spread trades.
 
                         
    Barrels
          Implied Crack
 
Swap Contracts by Expiration Dates
  Purchased     BPD     Spread ($/Bbl)  
 
First Quarter 2009
    450,000       5,000     $ (2.13 )
Second Quarter 2009
    455,000       5,000       (2.13 )
Third Quarter 2009
    460,000       5,000       (2.13 )
Fourth Quarter 2009
    460,000       5,000       (2.13 )
                         
Totals
    1,825,000                  
Average price
                  $ (2.13 )
 
The above derivative instruments to purchase the crack spread have effectively locked in a gain of $9.70 per barrel on approximately 1.8 million barrels, or $17.7 million, to be recognized in 2009.
 
As of February 26, 2009, the Company has also added the following crude oil and gasoline derivative instruments, none of which are designated as hedges, to the above transactions for our fuel products segment crack spread trades:
 
                         
    Barrels
          Implied Crack
 
Swap Contracts by Expiration Dates
  Purchased     BPD     Spread ($/Bbl)  
 
First Quarter 2010
    135,000       1,500     $ 0.17  
Second Quarter 2010
    136,500       1,500       0.17  
Third Quarter 2010
    138,000       1,500       0.17  
Fourth Quarter 2010
    138,000       1,500       0.17  
                         
Totals
    547,500                  
Average price
                  $ 0.17  
 
The above derivative instruments to purchase the crack spread have effectively locked in a gain of $7.82 per barrel on approximately 0.5 million barrels, or $4.3 million, to be recognized in 2010.


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Specialty Products Segment
 
As a result of our specialty products crude oil hedging activity, we recorded a gain of $21.9 million and a loss $47.0 million, to cost of goods sold and realized loss on derivative instruments, respectively, in the consolidated statements of operations for 2008. As of December 31, 2008 and February 26, 2009, we have provided cash margin of $4.0 million and $0.4 million, respectively, in credit support to certain of our hedging counterparties. At December 31, 2008, the Company had the following four-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $2.1 million of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.
 
                                                 
                Average
    Average
    Average
    Average
 
                Lower Put
    Upper Put
    Lower Call
    Upper Call
 
Crude Oil Put/Call Spread Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)     ($/Bbl)     ($/Bbl)     ($/Bbl)  
 
January 2009
    217,000       7,000     $ 50.32     $ 60.32     $ 70.32     $ 80.32  
February 2009
    84,000       3,000       38.33       48.33       58.33       68.33  
                                                 
Totals
    301,000                                          
Average price
                  $ 46.98     $ 56.98     $ 66.98     $ 76.98  
 
At December 31, 2008, the Company had the following two-way crude oil collar derivatives related to crude oil purchases in our specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $10.3 million of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.
 
                                 
                Average
    Average
 
                Sold Put
    Bought Call
 
Crude Oil Put/Call Spread Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)     ($/Bbl)  
 
January 2009
    186,000       6,000     $ 68.57     $ 90.83  
February 2009
    112,000       4,000       74.85       96.25  
March 2009
    93,000       3,000       79.37       101.67  
                                 
Totals
    391,000                          
Average price
                  $ 72.94     $ 94.96  
 
At December 31, 2008, the Company had the following derivatives related to natural gas purchases, of which 90,000 MMBtus are designated as hedges. As a result of a portion of these derivatives not being designated as hedges, the Company recognized $1.2 million of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for 2008.
 
                 
Natural Gas Swap Contracts by Expiration Dates
  MMBtus     $/MMBtu  
 
First Quarter 2009
    330,000     $ 10.38  
                 
Totals
    330,000          
Average price
          $ 10.38  


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Item 8.   Financial Statements and Supplementary Data
 
Report of Independent Registered Public Accounting Firm
 
The Board of Directors of Calumet GP, LLC
General Partner of Calumet Specialty Products Partners, L.P.
 
We have audited the accompanying consolidated balance sheets of Calumet Specialty Products Partners, L.P. as of December 31, 2008 and 2007, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Calumet Specialty Products Partners, L.P. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Calumet Specialty Products Partners L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009 expressed an unqualified opinion thereon.
 
/s/   Ernst & Young LLP
 
Indianapolis, Indiana
February 27, 2009


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
CONSOLIDATED BALANCE SHEETS
 
                 
    Year Ended December 31,  
    2008     2007  
    (In thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 48     $ 35  
Accounts receivable:
               
Trade, less allowance for doubtful accounts of $2,121 and $786, respectively
    103,962       109,501  
Other
    5,594       4,496  
                 
      109,556       113,997  
                 
Inventories
    118,524       107,664  
Derivative assets
    71,199        
Prepaid expenses and other current assets
    1,803       7,567  
Deposits
    4,021       21  
                 
Total current assets
    305,151       229,284  
Property, plant and equipment, net
    659,684       442,882  
Goodwill
    48,335        
Other intangible assets, net
    49,502       2,460  
Other noncurrent assets, net
    18,390       4,231  
                 
Total assets
  $ 1,081,062     $ 678,857  
                 
 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
               
Accounts payable
  $ 87,460     $ 167,977  
Accounts payable — related party
    6,395        
Accrued salaries, wages and benefits
    6,865       2,745  
Taxes payable
    6,833       6,215  
Other current liabilities
    9,662       4,882  
Current portion of long-term debt
    4,811       943  
Derivative liabilities
    15,827       57,503  
                 
Total current liabilities
    137,853       240,265  
Pension and postretirement benefit obligations
    9,717        
Long-term debt, less current portion
    460,280       38,948  
                 
Total liabilities
    607,850       279,213  
                 
Commitments and contingencies
               
Partners’ capital:
               
Common unitholders (19,166,000 units authorized, issued and outstanding)
    363,935       375,925  
Subordinated unitholders (13,066,000 units authorized, issued and outstanding)
    35,778       43,996  
General partner’s interest
    17,933       19,364  
Accumulated other comprehensive income (loss)
    55,566       (39,641 )
                 
Total partners’ capital
    473,212       399,644  
                 
Total liabilities and partners’ capital
  $ 1,081,062     $ 678,857  
                 
 
See accompanying notes to consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands, except per unit data)  
 
Sales
  $ 2,488,994     $ 1,637,848     $ 1,641,048  
Cost of sales
    2,235,111       1,456,492       1,436,108  
                         
Gross profit
    253,883       181,356       204,940  
                         
Operating costs and expenses:
                       
Selling, general and administrative
    34,267       19,614       20,430  
Transportation
    84,702       54,026       56,922  
Taxes other than income taxes
    4,598       3,662       3,592  
Other
    1,576       2,854       863  
                         
Operating income
    128,740       101,200       123,133  
                         
Other income (expense):
                       
Interest expense
    (33,938 )     (4,717 )     (9,030 )
Interest income
    388       1,944       2,951  
Debt extinguishment costs
    (898 )     (352 )     (2,967 )
Realized loss on derivative instruments
    (58,833 )     (12,484 )     (30,309 )
Unrealized gain (loss) on derivative instruments
    3,454       (1,297 )     12,264  
Gain on sale of mineral rights
    5,770              
Other
    11       (919 )     (274 )
                         
Total other expense
    (84,046 )     (17,825 )     (27,365 )
                         
Net income before income taxes
    44,694       83,375       95,768  
Income tax expense
    257       501       190  
                         
Net income
  $ 44,437     $ 82,874     $ 95,578  
                         
Allocation of net income:
                       
Net income applicable to Predecessor for the period through January 31, 2006
                4,408  
                         
Net income applicable to Calumet
    44,437       82,874       91,170  
Minimum quarterly distribution to common unitholders
    (34,500 )     (30,021 )     (24,413 )
General partner’s incentive distribution rights
    (10,996 )     (14,102 )     (18,912 )
General partner’s interest in net income
    (334 )     (939 )     (845 )
Common unitholders’ share of income in excess of minimum quarterly distribution
    (11,706 )     (13,592 )     (18,312 )
                         
Subordinated unitholders’ interest in net income (loss)
    (13,099 )     24,220       28,688  
Basic net income per limited partner unit:
                       
Common
  $ 2.41     $ 2.63     $ 2.84  
Subordinated
  $ (1.00 )   $ 1.86     $ 2.20  
Diluted net income per limited partner unit:
                       
Common
  $ 2.41     $ 2.63     $ 2.84  
Subordinated
  $ (1.00 )   $ 1.86     $ 2.20  
Weighted average limited partner common units outstanding — basic
    19,166       16,678       14,642  
Weighted average limited partner subordinated units outstanding — basic
    13,066       13,066       13,066  
Weighted average limited partner common units outstanding — diluted
    19,166       16,680       14,642  
Weighted average limited partner subordinated units outstanding — diluted
    13,066       13,066       13,066  
Cash distributions declared per common and subordinated unit
  $ 1.98     $ 2.43     $ 1.30  
 
See accompanying notes to consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 
                                                 
          Accumulated Other
    Partners’ Capital        
    Predecessor
    Comprehensive
    General
    Limited Partners        
    Partners’ Capital     Income (Loss)     Partner     Common     Subordinated     Total  
    (In thousands)  
 
Balance at January 1, 2006
  $ 43,443     $ 497     $     $     $     $ 43,940  
Comprehensive income through January 31, 2006 for the Predecessor:
                                               
Net income through January 31, 2006
    4,408                                       4,408  
Cash flow hedge (gain)/loss reclassified to net income
            (497 )                             (497 )
Change in fair value of cash flow hedges through January 31, 2006
            1,578                               1,578  
                                                 
Comprehensive income through January 31, 2006 for the Predecessor
                                            5,489  
Distributions to Predecessor partners
    (6,900 )                                     (6,900 )
Assets and liabilities not contributed to Calumet
    (5,626 )                                     (5,626 )
Allocation of Predecessor’s capital
    (35,325 )             3,053       10,423       21,849        
Proceeds from initial public offering, net
                            138,743               138,743  
Contribution from Calumet GP, LLC
                    375                       375  
Comprehensive income from February 1, 2006 through December 31, 2006 for Calumet:
                                               
Net income from February 1, 2006 through December 31, 2006
                    11,317       42,368       37,485       91,170  
Change in fair value of cash flow hedges from February 1, 2006 through December 31, 2006
          50,673                         50,673  
                                                 
Comprehensive income from February 1, 2006 through December 31, 2006 for Calumet
                                            141,843  
Proceeds from follow-on public offering, net
                            103,479               103,479  
Contribution from Calumet GP, LLC
                    2,218                       2,218  
Units repurchased for phantom unit grants
                            (69 )             (69 )
Amortization of vested phantom units
                            61               61  
Distributions to partners
                    (1,013 )     (20,286 )     (16,987 )     (38,286 )
                                                 
Balance at December 31, 2006
          52,251       15,950       274,719       42,347       385,267  
Comprehensive loss:
                                               
Net income
                    5,944       43,139       33,791       82,874  
Cash flow hedge gain reclassified to net income
            (13,880 )                             (13,880 )
Change in fair value of cash flow hedges
            (78,012 )                             (78,012 )
                                                 
Comprehensive loss
                                            (9,018 )
Proceeds from follow-on public offering, net
                            98,206               98,206  
Contribution from Calumet GP, LLC
                    2,113                       2,113  
Amortization of vested phantom units
                            121               121  
Distributions to partners
                    (4,643 )     (40,260 )     (32,142 )     (77,045 )
                                                 
Balance at December 31, 2007
          (39,641 )     19,364       375,925       43,996       399,644  
Comprehensive income:
                                               
Net income
                    889       25,895       17,653       44,437  
Cash flow hedge loss reclassified to net income
            17,472                               17,472  
Change in fair value of cash flow hedges
            83,959                               83,959  
Minimum pension liability adjustment
            (6,224 )                             (6,224 )
                                                 
Comprehensive income
                                            139,644  
Units repurchased for phantom unit grants
                            (115 )             (115 )
Amortization of vested phantom units
                            179               179  
Distributions to partners
                    (2,320 )     (37,949 )     (25,871 )     (66,140 )
                                                 
Balance at December 31, 2008
  $     $ 55,566     $ 17,933     $ 363,935     $ 35,778     $ 473,212  
                                                 
 
See accompanying notes to consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Operating activities
                       
Net income
  $ 44,437     $ 82,874     $ 95,578  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    59,261       14,585       11,760  
Amortization of turnaround costs
    2,468       3,190       3,267  
Provision for doubtful accounts
    1,448       41       172  
Non-cash debt extinguishment costs
    898       352       2,967  
Unrealized (gain)/loss on derivative instruments
    (3,454 )     1,297       (12,264 )
Gain on sale of mineral rights
    (5,770 )            
Other non-cash activities
    1,712       358       152  
Changes in assets and liabilities:
                       
Accounts receivable
    45,042       (15,038 )     16,031  
Inventories
    55,532       3,321       (2,554 )
Prepaid expenses and other current assets
    5,834       (6,061 )     9,293  
Derivative activity
    41,757       2,121       (879 )
Deposits
    (4,000 )     1,940       6,890  
Other assets
    (10,211 )     (6,510 )     1,705  
Accounts payable
    (103,136 )     89,225       33,993  
Accrued salaries, wages and benefits
    (1,657 )     (2,930 )     (2,489 )
Taxes payable
    618       (823 )     2,962  
Other current liabilities
    (245 )     (396 )     184  
Pension and postretirement benefit obligations
    (193 )            
                         
Net cash provided by operating activities
    130,341       167,546       166,768  
Investing activities
                       
Additions to property, plant and equipment
    (167,702 )     (261,015 )     (76,064 )
Acquisition of Penreco, net of cash acquired
    (269,118 )            
Settlement of derivative instruments
    (49,746 )            
Proceeds from sale of mineral rights
    6,065              
Proceeds from disposal of property, plant and equipment
    40       140       261  
                         
Net cash used in investing activities
    (480,461 )     (260,875 )     (75,803 )
Financing activities
                       
Proceeds from borrowings — revolving credit facility
    1,424,732       303,380       335,069  
Repayments of borrowings — revolving credit facility
    (1,329,150 )     (296,423 )     (428,054 )
Repayments of borrowings — prior term loan credit facilities
    (30,099 )     (19,401 )     (125,500 )
Proceeds from borrowings — new term loan credit facility
    385,000              
Discount on new term loan
    (17,400 )            
Debt issuance costs
    (9,633 )     (369 )      
Repayments of borrowings — new term loan credit facility
    (9,915 )            
Payments on capital lease obligation
    (618 )     (906 )      
Proceeds from public equity offerings, net
          98,206       242,222  
Contributions from Calumet GP, LLC
          2,113       2,593  
Cash distribution to Calumet Holding, LLC
                (3,258 )
Change in bank overdraft. 
    3,471       2,854        
Purchase of common units for unit grants
    (115 )           (69 )
Distributions to Predecessor partners
                (6,900 )
Distributions to partners
    (66,140 )     (77,045 )     (38,286 )
                         
Net cash provided by (used in) financing activities
    350,133       12,409       (22,183 )
                         
Net increase (decrease) in cash and cash equivalents
    13       (80,920 )     68,782  
Cash and cash equivalents at beginning of year
    35       80,955       12,173  
                         
Cash and cash equivalents at end of year
  $ 48     $ 35     $ 80,955  
                         
Supplemental disclosure of cash flow information
                       
Interest paid, net of capitalized interest
  $ 33,667     $ 4,080     $ 11,986  
Income taxes paid
  $ 30     $ 150     $ 175  
                         
Supplemental disclosure of noncash financing and investing activities
                       
Equipment acquired under capital lease
  $ 171     $ 3,565     $  
                         
 
See accompanying notes to consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except operating, unit and per unit data)
 
1.   Description of the Business
 
Calumet Specialty Products Partners, L.P. (Calumet, Partnership, or the Company) is a Delaware limited partnership. The general partner is Calumet GP, LLC, a Delaware limited liability company. On January 31, 2006, the Partnership completed the initial public offering of its common units. At that time, substantially all of the assets or liabilities of Calumet Lubricants Co., Limited Partnership and its subsidiaries (Predecessor) were contributed to Calumet. References to the Predecessor in these consolidated financial statements refer to Calumet Lubricants Co., Limited Partnership and its subsidiaries. On July 5, 2006 and November 20, 2007, the Partnership completed follow-on public offerings of its common units. As of December 31, 2008, Calumet had 19,166,000 common units, 13,066,000 subordinated units, and 657,796 general partner equivalent units outstanding. The general partner owns 2% of Calumet while the remaining 98% is owned by limited partners. On January 3, 2008 the Company closed on the acquisition of Penreco, a Texas general partnership, for approximately $269,118. Calumet is engaged in the production and marketing of crude oil-based specialty lubricating oils, white mineral oils, solvents, petrolatums, waxes and fuels. Calumet owns facilities located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport, Louisiana, Karns City, Pennsylvania, and Dickinson, Texas, and a terminal located in Burnham, Illinois.
 
2.   Summary of Significant Accounting Policies
 
Consolidation
 
The consolidated financial statements of Calumet include the accounts of Calumet Specialty Products Partners, L.P. and its wholly-owned operating subsidiaries, Calumet Lubricants Co., Limited Partnership, Calumet Sales Company Incorporated, Calumet Penreco, LLC and Calumet Shreveport, LLC. Calumet Shreveport, LLC’s wholly-owned operating subsidiaries are Calumet Shreveport Fuels, LLC and Calumet Shreveport Lubricants & Waxes, LLC. All intercompany transactions and accounts have been eliminated. Hereafter, the consolidated companies are referred to as the Company.
 
Use of Estimates
 
The Company’s financial statements are prepared in conformity with U.S. generally accepted accounting principles which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Cash and Cash Equivalents
 
Cash and cash equivalents includes all highly liquid investments with a maturity of three months or less at the time of purchase.
 
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.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
Inventories consist of the following:
 
                 
    December 31,  
    2008     2007  
 
Raw materials
  $ 24,955     $ 20,887  
Work in process
    43,735       21,325  
Finished goods
    49,834       65,452  
                 
    $ 118,524     $ 107,664  
                 
 
The replacement cost of these inventories, based on current market values, would have been $27,517 and $107,885 higher as of December 31, 2008 and 2007, respectively. During the years ended December 31, 2008, 2007 and 2006, the Company recorded $5,446, $19,834 and $2,127, respectively, of gains in cost of sales in the consolidated statements of operations due to the liquidation of lower cost inventory layers.
 
Accounts Receivable
 
The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are generally due within 30 days for the specialty products segment and 10 days for the fuel products segment. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical credit experience and expected future trends. The activity in the allowance for doubtful accounts was as follows:
 
                         
    December 31,  
    2008     2007     2006  
 
Beginning balance
  $ 786     $ 782     $ 750  
Provision
    1,448       41       172  
Write-offs, net
    (113 )     (37 )     (140 )
                         
Ending balance
  $ 2,121     $ 786     $ 782  
                         
 
Property, Plant and Equipment
 
Property, plant and equipment are stated on the basis of cost. Depreciation is calculated generally on composite groups, using the straight-line method over the estimated useful lives of the respective groups.
 
Property, plant and equipment, including depreciable lives, consists of the following:
 
                 
    December 31,  
    2008     2007  
 
Land
  $ 3,249     $ 1,169  
Buildings and improvements (10 to 40 years)
    6,626       2,050  
Machinery and equipment (10 to 20 years)
    711,122       225,096  
Furniture and fixtures (5 to 10 years)
    2,682       1,261  
Assets under capital leases (4 years)
    4,015       3,565  
Construction-in-progress
    25,065       264,052  
                 
      752,759       497,193  
Less accumulated depreciation
    (93,075 )     (54,311 )
                 
    $ 659,684     $ 442,882  
                 


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related accumulated depreciation are retired, and any gain or loss is reflected in earnings.
 
During the years ended December 31, 2008, 2007, and 2006, the Company incurred $41,159, $9,328, and $10,998, respectively, of interest expense of which $7,221, $4,611, and $1,968, respectively, was capitalized as a component of property, plant and equipment.
 
The Company has not recorded an asset retirement obligation as of December 31, 2008 or 2007 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.
 
Accumulated depreciation above includes $669 of depreciation expense related to the Company’s capitalized lease assets.
 
Goodwill
 
Goodwill represents the excess of purchase price over fair value of the net assets acquired in the Penreco acquisition. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, goodwill and other intangible assets are not amortized, but are tested for impairment at least annually and when indicators dictate, such as adverse changes in business climate, market value of long-lived assets or a change in the structure of the Company. The Company performs its annual impairment review in the fourth quarter of each fiscal year, unless circumstances dictate more frequent assessments. The 2008 annual impairment review resulted in no impairment charge. For more information, refer to Note 6.
 
Other Intangible Assets
 
Other intangible assets primarily consist of supply agreements, customer relationships, non-compete agreements and patents acquired in the Penreco acquisition. These assets are being amortized using the discounted estimated future cash flows method over the term of the related agreements. Intangible assets associated with customer relationships of Penreco are being amortized using the discounted estimated future cash flows method based upon an assumed rate of annual customer attrition. For more information, refer to Note 6.
 
Impairment of Long-Lived Assets
 
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In such an event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair market value of the long-lived asset. Fair market value is determined primarily using anticipated cash flows discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.
 
Revenue Recognition
 
The Company recognizes revenue on orders received from its customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under the Company’s normal billing and credit terms, all of the Company’s obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
Concentrations of Credit Risk
 
The Company performs periodic credit evaluations of its customers’ financial condition and generally does not require collateral. The Company maintains allowances for doubtful customer accounts for estimated losses resulting from the inability of its customers to make required payments. The allowance for doubtful accounts is developed based on several factors including customers’ credit quality, historical write-off experience, age of accounts receivable, default percentages provided by a third party and any known specific issues or disputes which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, the Company has significant derivative assets with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s SFAS No. 157, Fair Value Measurements, valuations to determine the impact of counterparty credit risk on the valuation of its derivative instruments.
 
Income Taxes
 
The Company, as a partnership, is not liable for income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries Calumet Lubricants Co., Limited Partnership and Calumet Shreveport, LLC. However, Calumet Sales Company Incorporated (“Calumet Sales Company”), a wholly-owned subsidiary of the Company, is a corporation and as a result, is liable for income taxes on its earnings. Income taxes on the earnings of the Company, with the exception of Calumet Sales Company, are the responsibility of the partners, with earnings of the Company included in partners’ earnings.
 
In the event that the Company’s taxable income did not meet certain qualification requirements, the Company would be taxed as a corporation. Related to these qualifications, the Company requested a ruling from the Internal Revenue Service (“IRS”) with respect to the qualifying nature of income generated from the Penreco assets and business operations. In the fourth quarter of 2008, the IRS provided a favorable ruling. Interest and penalties related to income taxes, if any, would be recorded in income tax expense. The Company had no unrecognized tax benefits as of December 31, 2008 and 2007. The Company’s income taxes generally remain subject to examination by major tax jurisdictions for a period of three years.
 
Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the Company’s partnership agreement. Individual partners have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each partner’s tax accounting, which is partially dependent upon the partner’s tax position, differs from the accounting followed in the consolidated financial statements. Accordingly, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in the partnership is not readily available.
 
Effective January 1, 2007, the Company adopted the provisions of Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes (the “Interpretation”), an interpretation of SFAS Statement No. 109, Accounting for Income Taxes. The Interpretation clarifies the accounting for uncertainty in income taxes by prescribing a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position to be taken or expected to be taken in a tax return. The implementation of the Interpretation did not have a material effect on the Company’s financial position, results of operations or cash flows.
 
Excise and Sales Taxes
 
The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of jet fuel. Excise taxes and sales taxes assessed and collected from customers are recorded on a net basis within sales in the Company’s consolidated statements of operations.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
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. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133, and in May 2003 by SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, (collectively referred to as “SFAS 133”), the Company recognizes all derivative instruments as either assets or liabilities at fair value on the balance sheets. The Company utilizes third party valuations and published market data to determine the fair value of these derivative instruments. To the extent a derivative instrument is designated 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 instrument is deferred in accumulated other comprehensive income (loss), a component of partners’ capital. The Company accounts for certain derivatives hedging purchases of crude oil and natural gas, the sale of gasoline, diesel and jet fuel, and the payment of interest as cash flow hedges. The derivative instruments designated as hedging purchases and sales are recorded to cost of sales and sales, respectively, in the consolidated statements of operations, upon recording the related hedged transaction in sales or cost of sales. The derivative instruments designated as hedging payments of interest are recorded in interest expense in the consolidated statements of operations. For the years ended December 31, 2008, 2007 and 2006, the Company has recorded derivative losses of $297,319 and $33,576 and a gain of $6, respectively, to sales and derivative gains of $306,079 and $21,653 and a loss of $11,070, respectively, to cost of sales in the consolidated statements of operations. During the years ended December 31, 2008, 2007 and 2006, the Company recorded a loss of $49,746, a gain of $29 and $0, respectively, on crude oil collar, interest rate swap and natural gas swap derivative settlements in realized gain (loss) on derivative instruments in the consolidated statements of operations due to the derivative transactions not being designated as cash flow hedges. An interest rate swap loss of $554, a gain of $3 and a loss of $7 for the years ended December 31, 2008, 2007 and 2006, respectively, was recorded to interest expense in the consolidated statements of operations. 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 or loss on derivative instruments in the 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 loss on derivative instruments in the consolidated statements of operations.
 
The Company assesses, both at inception of the hedge and on an ongoing basis, whether the derivative instruments that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company’s estimate of the ineffective portion of the hedges for the years ended December 31, 2008, 2007 and 2006, were gains of $3,730, losses of $5,979 and gains of $4,071, respectively, which were recorded to unrealized gain (loss) on derivative instruments and realized loss on derivative instruments in the consolidated statements of operations. The Company recorded the time value on its crude oil collar derivative instruments, which is excluded from the assessment of hedge effectiveness, of $0, a gain of $709 and a loss of $444, respectively, to unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the years ended December 31, 2008, 2007 and 2006.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
The effective portion of the hedges classified in accumulated other comprehensive income (loss) is $61,790 as of December 31, 2008 and, absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2011 with balances being recognized as follows:
 
         
    Accumulated Other
 
    Comprehensive
 
Year
  Income (Loss)  
 
2009
  $ 24,878  
2010
    27,102  
2011
    9,810  
2012
     
         
Total
  $ 61,790  
 
The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative instruments. The Company executes all its derivative instruments with a small number of counterparties, the majority of which are large financial institutions with ratings of at least A1 and A+ by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on a derivative instrument’s 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. The Company’s contracts with these counterparties allow for netting of derivative instrument positions executed under each contract. The Company does not expect nonperformance on any derivative instrument.
 
Other Noncurrent Assets
 
Other noncurrent assets consist of deferred debt issuance costs, turnaround costs and deferred transaction costs. Deferred debt issuance costs were $8,899 and $1,358 as of December 31, 2008 and 2007, respectively, and are being amortized on a straight-line basis over the lives of the related debt instruments. These amounts are net of accumulated amortization of $2,160 and $990 at December 31, 2008 and 2007, respectively.
 
Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $9,491 and $682 as of December 31, 2008 and 2007, respectively. The Company capitalizes these costs and amortizes the cost on a straight-line basis over the life of the turnaround assets. These amounts are net of accumulated amortization of $2,586 and $2,930 at December 31, 2008 and 2007, respectively.
 
Deferred transaction costs primarily represent costs incurred by the Company as a result of its acquisition of Penreco and were $0 and $2,191 at December 31, 2008 and 2007, respectively.
 
Earnings per Unit
 
The Partnership calculates earnings per unit in accordance with SFAS No. 128, Earnings Per Share, as interpreted by Emerging Issues Task Force (EITF) Issue No. 03-06, Participating Securities and the Two — Class Method under FASB Statement No. 128. Under this pronouncement, common and subordinated limited units represent separate classes of limited partner units that require two-class presentation under SFAS No. 128. Therefore, the Partnership calculates basic and diluted earnings per unit on a discrete quarterly basis assuming the minimum quarterly distribution, prorated if necessary, is paid on all common units outstanding and that all undistributed earnings or losses in the period are fully allocated to limited partner units and the general partner based on their contractual participation rights as if all of the earnings or losses for the period had been distributed.
 
Shipping and Handling Costs
 
The Company adheres to EITF 00-10, Accounting for Shipping and Handling Fees and Costs. This EITF requires the classification of shipping and handling costs billed to customers in sales and the classification of


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
shipping and handling costs incurred in cost of sales, or to be disclosed if classified elsewhere. The Company has reflected $84,702, $54,026, and $56,922, respectively, for the years ended December 31, 2008, 2007, and 2006, in transportation expense in the consolidated statements of operations, of which a significant portion is billed to customers.
 
New Accounting Pronouncements
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (the “Statement”). The Statement applies to assets and liabilities required or permitted to be measured at fair value under other accounting pronouncements. The Statement defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements about fair value, but does not provide guidance whether assets and liabilities are required or permitted to be measured at fair value. The Statement is effective for fiscal years beginning after November 15, 2007. The Company adopted the Statement on January 1, 2008 and applied the various disclosures as required by the Statement. The adoption of this Statement did not have a material affect on the Company’s financial position or results of operations. In February 2008, the FASB agreed to defer for one year the effective date of the Statement for certain nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.
 
In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (the “Position”), which amends certain aspects of FASB Interpretation Number 39, Offsetting of Amounts Related to Certain Contracts. The Position permits companies to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The Position is effective for fiscal years beginning after November 15, 2007. The Company’s accounting policy is to not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. As of December 31, 2008, the Company has provided cash margin of $4.0 million in credit support to certain of its hedging counterparties.
 
In December 2007, the FASB issued FASB Statement No. 141(R), Business Combinations (the “Statement”). The Statement applies to the financial accounting and reporting of business combinations. The Statement is effective for business combination transactions for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company anticipates that the Statement will not have a material effect on its financial position, results of operations, or cash flows.
 
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS 133 have been applied, and the impact that hedges have on an entity’s financial position, results of operations, and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company currently provides an abundance of information about its hedging activities and use of derivatives in its quarterly and annual filings with the SEC, including many of the disclosures contained within SFAS 161. Thus, the Company currently does not anticipate the adoption of SFAS 161 will have a material impact on the disclosures already provided.
 
In March 2008, the FASB issued EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“EITF 07-4”). EITF 07-4 requires master limited partnerships to treat incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to pay IDRs. EITF 07-4 requires that


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
undistributed earnings be allocated to the partnership interests based on the allocation of earnings to capital accounts as specified in the respective partnership agreement. When distributions exceed earnings, EITF 07-4 requires that net income be reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the respective partnership agreement. EITF 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Company is evaluating the potential impacts of EITF 07-4.
 
In April 2008, the FASB issued FASB Staff Position No. 142-3, Determination of the Useful Life of Intangible Assets, (“FSP No. 142-3”) that amends the factors considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). FSP No. 142-3 requires a consistent approach between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of an asset under SFAS No. 141(R), Business Combinations. FSP No. 142-3 also requires enhanced disclosures when an intangible asset’s expected future cash flows are affected by an entity’s intent and/or ability to renew or extend the arrangement. FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and is applied prospectively. Early adoption is prohibited. The Company does not expect the adoption of FSP No. 142-3 will have a material impact on its consolidated results of operations or financial condition.
 
3.   Acquisition of Penreco
 
On January 3, 2008 the Company acquired Penreco, a Texas general partnership, for $269,118, net of the cash acquired. Penreco was owned by ConocoPhillips Company and M.E. Zukerman Specialty Oil Corporation. Penreco manufactures and markets highly-refined products and specialty solvents, including white mineral oils, petrolatums, natural petroleum sulfonates, cable-filling compounds, refrigeration oils, food-grade compressor lubricants and gelled products. The acquisition included facilities in Karns City, Pennsylvania and Dickinson, Texas, as well as several long-term supply agreements with ConocoPhillips Company.
 
The Company believes that this acquisition provides several key strategic benefits, including market synergies within its solvents and lubricating oil product lines, additional operational and logistics flexibility and overhead cost reductions resulting from the acquisition. The acquisition also broadens the Company’s customer base and gives the Company access to new markets.
 
As a result of the acquisition, the assets and liabilities previously held by Penreco and results of the operations of these assets have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. The unaudited pro forma summary results of operations for the year ended December 31, 2007 below combine the results of operations of Calumet and Penreco as if the acquisition had occurred on January 1, 2007.
 
         
    For the Year Ended
 
    December 31, 2007  
    (Unaudited)  
 
Sales
  $ 2,069,832  
Net income
  $ 100,915  
Basic and diluted net income per limited partner unit
  $ 2.85  


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
The Company recorded $48,335 of goodwill as a result of this acquisition, all of which was recorded within the Company’s specialty products segment. The allocation of the aggregate purchase price is as follows:
 
         
    Allocation of
 
    Purchase Price  
Accounts receivable
  $ 42,049  
Inventories
    66,392  
Prepaid expenses and other current assets
    70  
Property, plant and equipment
    91,790  
Other noncurrent assets
    288  
Intangibles
    59,325  
Goodwill
    48,335  
Accounts payable
    (29,014 )
Other current liabilities
    (7,331 )
Other noncurrent liabilities
    (2,786 )
         
Total purchase price, net of cash acquired
  $ 269,118  
         
 
The components of intangible assets listed in the table above as of January 3, 2008, based upon a third party appraisal, were as follows:
                 
    Amount     Life  
 
Customer relationships
  $ 28,482       20  
Supplier agreements
    21,519       4  
Patents
    1,573       12  
Non-competition agreements
    5,732       5  
Distributor agreements
    2,019       3  
                 
Total
  $ 59,325          
                 
Weighted average amortization period
            12  
 
The Company formulated its plan associated with the involuntary termination of certain non-union Penreco employees and accrued $1,829 for such costs, which are included in the acquisition liabilities. All affected employees have been terminated and substantially all liabilities have been paid as of December 31, 2008.
 
4.   Sale of Mineral Rights
 
In June 2008, the Company received $6,065 associated with the lease of mineral rights on the real property at the Shreveport and Princeton refineries to an unaffiliated third party which have been accounted for as a sale. The Company has retained a royalty interest in any future production associated with these mineral rights. As a result of these transactions, the Company recorded a gain of $5,770 in other income (expense) in the consolidated statements of operations. Under the term loan agreement, cash proceeds resulting from this disposition of property, plant and equipment were used as a mandatory prepayment of the term loan.
 
5.   Shreveport Refinery Expansion
 
As of December 31, 2007, the Company had invested $254,414 in its Shreveport refinery expansion project. Through December 31, 2008, the Company has invested an additional $119,630 for a total of $374,044 in its Shreveport refinery expansion project. The project was completed and operational in May 2008. Additionally, for the years ended December 31, 2007 and 2008, the Company had invested $65,633 and $40,753, respectively, in the


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
Shreveport refinery for other capital expenditures including projects to improve efficiency, de-bottleneck certain operating units and for new product development.
 
6.   Goodwill and Other Intangible Assets
 
The Company has recorded $48,335 of goodwill as a result of the Penreco acquisition, all of which is recorded within the Company’s specialty products segment.
 
Other intangible assets consist of the following:
                                         
          December 31, 2008     December 31, 2007  
    Weighted
    Gross
    Accumulated
    Gross
    Accumulated
 
    Average Life     Amount     Amortization     Amount     Amortization  
 
Customer relationships
    20     $ 28,482     $ (4,071 )   $ 2,276     $ (2,165 )
Supplier agreements
    4       21,519       (7,539 )            
Patents
    12       1,573       (313 )            
Non-competition agreements
    5       5,732       (768 )            
Distributor agreements
    3       2,019       (758 )            
Royalty agreements
    19       4,116       (490 )     2,679       (330 )
                                         
      12     $ 63,441     $ (13,939 )   $ 4,955     $ (2,495 )
                                         
 
Intangible assets associated with supplier agreements, non-competition agreements, patents and distributor agreements are being amortized on an accelerated basis in order to properly match expense with the estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships of Penreco are being amortized using the discounted estimated future cash flows based upon an assumed rate of annual customer attrition. For the year ended December 31, 2008, the Company recorded amortization expense of intangible assets of $13,721, as compared to $719 and $521 for the years ended December 31, 2007 and 2006, respectively. The Company estimates that amortization of intangible assets will be $11,409, $8,808, $6,972, and $5,728 for the years ended December 31, 2009, 2010, 2011, and 2012, respectively.
 
7.   Commitments and Contingencies
 
Operating Leases
 
The Company has various operating leases for the use of land, storage tanks, compressor stations, railcars, equipment, precious metals, operating unit catalyst and office facilities that extend through August 2015. Renewal options are available on certain of these leases in which the Company is the lessee. Rent expense for the years ended December 31, 2008, 2007, and 2006 was $16,003, $10,277 and $10,894, respectively.
 
As of December 31, 2008, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows:
 
         
    Operating
 
Year
  Leases  
 
2009
  $ 12,665  
2010
    10,154  
2011
    8,133  
2012
    6,223  
2013
    4,438  
Thereafter
    4,075  
         
Total
  $ 45,688  
         


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
Historically, the Company has purchased a portion of its crude oil under a contract that contained minimum purchase requirements. This contract expired during 2008 and the Company has fulfilled all commitments under the contract. Total purchases under this contract were $690,359, $515,268 and $470,538 for the years ended December 31, 2008, 2007 and 2006, respectively. The Company is currently purchasing all of its crude oil under evergreen contracts or on a spot basis. As of December 31, 2008, the estimated minimum purchase requirements under our crude oil contracts were as follows:
 
         
Year
  Commitment  
 
2009
  $ 149,613  
2010
     
2011
     
2012
     
2013
     
Thereafter
     
         
Total
  $ 149,613  
         
 
In connection with the closing of the Penreco acquisition on January 3, 2008, the Company 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, the Company is obligated to purchase $37,365 of feedstock for the LVT unit in each of the next four years based on pricing estimates as of December 31, 2008. 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 the Company as liquidated damages.
 
Labor Matters
 
The Company has approximately 360 employees out of a total of approximately 630 covered by various collective bargaining agreements. These agreements have expiration dates of March 31, 2010, April 30, 2010, October 31, 2011 and January 31, 2012.
 
Contingencies
 
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxing and regulatory authorities, such as the Louisiana Department of Environmental Quality (“LDEQ”), Environmental Protection Agency (“EPA”), IRS and Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position, results of operations or cash flow.
 
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


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
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 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. In particular, the LDEQ has proposed penalties totaling approximately $400 and supplemental projects 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. The Company anticipates that any penalties that may be assessed due to the alleged violations will be consolidated in a settlement agreement that the Company anticipates executing with the LDEQ in connection with the agency’s “Small Refinery and Single Site Refinery Initiative” described below. The Company has recorded a liability for the proposed penalty within other current liabilities on the consolidated balance sheets. Environmental expenses are recorded within other expenses in the consolidated statements of operations.
 
The Company is party to ongoing discussions on a voluntary basis with the LDEQ regarding the Company’s participation in that agency’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 Company expects that the LDEQ’s primary focus under the state initiative will be on four compliance and enforcement concerns: (i) Prevention of Significant Deterioration/New Source Review; (ii) New Source Performance Standards for fuel gas combustion devices, including flares, heaters and boilers; (iii) Leak Detection and Repair requirements; and (iv) Benzene Waste Operations National Emission Standards for Hazardous Air Pollutants. The Company is in discussions with the LDEQ regarding its participation in this regulatory initiative and the Company anticipates that it will be entering into a settlement agreement with the LDEQ pursuant to which the Company will be required to make emissions reductions requiring capital investments between approximately $1,000 and $3,000 in total over a three to five year period at its three Louisiana refineries. Because the settlement agreement is also expected to resolve the alleged air emissions issues at the Company’s Cotton Valley and Princeton refineries and consolidate any penalties associated with such issues, the Company further anticipates that a penalty of approximately $400 will be assessed in connection with this settlement agreement.
 
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. During 2008, the Company determined that it will incur approximately $700 of costs during 2009 at its Cotton Valley refinery in connection with continued remediation of groundwater impacts at that site.
 
The Company also is in separate discussions with the EPA to resolve alleged deficiencies in risk management planning in connection with a fire-related incident arising out of tank cleaning and vacuum truck operations at its


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
Shreveport refinery on October 30, 2008. The incident involved a third-party contractor and resulted in damage to an on-site aboveground storage tank. Following an investigation of the matter, EPA issued five violations against the Company, alleging, among other things, inadequate contractor training and oversight, and has proposed a penalty of $230. The Company is currently evaluating its response to the EPA with respect to the matter.
 
The Company is indemnified by Shell Oil Company (“Shell”), 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.
 
The Company is indemnified on a limited basis by ConocoPhillips Company and M.E. Zuckerman Specialty Oil Corporation, former owners of Penreco, for pending, threatened, contemplated or contingent environmental claims against Penreco, if any, that were not known and identified as of the Penreco acquisition date. A significant portion of these indemnifications will expire two years from January 1, 2008 if there are no claims asserted by the Company and are generally subject to a $2,000 limit.
 
Health and Safety
 
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, state and local government authorities and citizens. 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 commissioned studies to assess the adequacy of its process safety management practices at its Shreveport refinery. Depending on the findings made in these studies, the Company may incur capital expenditures over the next several years to enhance these practices so that it may maintain its compliance with applicable OSHA regulations at the refinery. While the Company does not expect these expenditures to be material at this time, it has not yet received the reports from the engineering firms conducting the studies to reach final resolution. The Company believes that its operations are in substantial compliance with OSHA and similar state laws.
 
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 December 31, 2008 and 2007, the Company had outstanding standby letters of credit of $21,355 and $96,676, respectively, under its senior secured revolving credit facility. The maximum amount of letters of credit the Company can issue is limited to its borrowing capacity under its revolving credit facility or $300,000, whichever is lower. As of December 31, 2008 and 2007, the Company had availability to issue letters of credit of $51,865 and $103,324, respectively, under its revolving credit facility. As discussed in Note 8, as of December 31, 2008 the Company also had a $50,000 letter of credit outstanding under its senior secured first lien letter of credit facility for its fuels hedging program, which bears interest at 4.0%.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
8.   Long-Term Debt
 
Long-term debt consisted of the following:
 
                 
    December 31,  
    2008     2007  
 
Borrowings under new senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 4.00% (6.15% at December 31, 2008), interest and principal payments quarterly with borrowings due January 2015, effective interest rate of 7.84%
  $ 375,085     $  
Borrowings under senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 3.50% (8.74% at December 31, 2007), interest and principal payments quarterly with borrowings due December 2012
          30,099  
Borrowings under senior secured revolving credit agreement with third-party lenders, interest at prime plus 0.50% (3.75% and 7.25% at December 31, 2008 and 2007, respectively), interest payments monthly, borrowings due January 2013
    102,539       6,958  
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly with borrowings due January 2012
    2,640       2,834  
Less unamortized discount on new senior secured first lien term loan with third-party lenders
    (15,173 )      
                 
Total long-term debt
    465,091       39,891  
Less current portion of long-term debt
    4,811       943  
                 
    $ 460,280     $ 38,948  
                 
 
The borrowing capacity at December 31, 2008 under the revolving credit facility was $175,759 with $51,865 available for additional borrowings based on collateral and specified availability limitations. The revolving credit facility has a first priority lien on the Company’s cash, accounts receivable and inventory and a second priority lien on the Company’s fixed assets.
 
On January 3, 2008, the Partnership closed a new $435,000 senior secured first lien term loan facility which includes a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. The proceeds of the term loan were used to (i) finance a portion of the acquisition of Penreco, (ii) fund the anticipated growth in working capital and remaining capital expenditures associated with the Shreveport refinery expansion project, (iii) refinance the existing term loan and (iv) to the extent available, for general partnership purposes. The new term loan bears interest at a rate equal (i) with respect to a Eurodollar Loan, the Eurodollar Rate plus 400 basis points and (ii) with respect to a Base Rate Loan, the Base Rate plus 300 basis points (as defined in the term loan credit agreement). The letter of credit facility to support crack spread hedging bears interest at 4.0%.
 
Lenders under the term loan facility have a first priority lien on the Company’s fixed assets and a second priority lien on its cash, accounts receivable, inventory and other personal property. The term loan facility matures in January 2015. The term loan facility requires quarterly principal payments of $963 until maturity on September 30, 2014, with the remaining balance due at maturity on January 3, 2015.
 
On January 3, 2008, the Partnership amended its existing senior secured revolving credit facility dated as of December 9, 2005, Pursuant to this amendment, the revolving credit facility lenders agreed to, among other things, (i) increase the total availability under the revolving credit facility up to $375,000 and (ii) conformed certain of the financial covenants and other terms in the revolving credit facility to those contained in the term loan credit agreement. The existing senior secured revolving credit facility matures on January 3, 2013.
 
During 2008, the Company has experienced adverse financial conditions primarily attributable with historically high crude oil costs and the impact of the Shreveport refinery expansion project cost overruns and the delay in


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
the startup of the expansion project. Compliance with the financial covenants pursuant to the Company’s credit agreements is tested quarterly based upon performance over the most recent four fiscal quarters, and as of December 31, 2008, it was in compliance with all financial covenants under its credit agreements. The Company’s ability to maintain compliance with these financial covenants in the quarter ended December 31, 2008 was substantially enhanced by the significant increase in specialty products segment gross profit during the third and fourth quarters resulting from increased selling prices for specialty products in the third quarter and reductions in the cost of crude oil throughout the third and fourth quarters. The Company is continuing to take steps to ensure that it meets the requirements of its credit agreements and currently forecasts that it will be in compliance on future measurement dates. These steps have included increasing specialty products sales prices, increasing crude oil price hedging for the specialty products segment and reducing working capital.
 
While assurances cannot be made regarding its future compliance with the financial covenants in its credit agreements and being cognizant of the general uncertain economic environment, the Company anticipates that its strategic initiatives listed above will allow it to maintain compliance with such financial covenants and to continue to improve its Adjusted EBITDA, liquidity and distributable cash flow.
 
Failure to achieve the Company’s anticipated results may result in a breach of certain of the financial covenants contained in its credit agreements. If this occurs, the Company will enter into discussions with its lenders to either modify the terms of the existing credit facilities or obtain waivers of non-compliance with such covenants. There can be no assurances of the timing of the receipt of any such modification or waiver, the term or costs associated therewith or our ultimate ability to obtain the relief sought. The Company’s failure to obtain a waiver of non-compliance with certain of the financial covenants or otherwise amend the credit facilities would constitute an event of default under its credit facilities and would permit the lenders to pursue remedies. These remedies could include acceleration of maturity under the credit facilities and limitations or the elimination of the Company’s ability to make distributions to its unitholders. If the Company’s lenders accelerate maturity under its credit facilities, a significant portion of its indebtedness may become due and payable immediately. The Company might not have, or be able to obtain, sufficient funds to make these accelerated payments. If the Company is unable to make these accelerated payments, its lenders could seek to foreclose on its assets.
 
As of December 31, 2008, maturities of the Company’s long-term debt is as follows:
 
         
Year
  Maturity  
 
2009
  $ 4,811  
2010
    4,594  
2011
    4,460  
2012
    4,175  
2013
    106,389  
Thereafter
    355,835  
         
Total
  $ 480,264  
         
 
In 2007, the Company entered into a capital lease for catalyst which will expire in 2012. Assets recorded under this capital lease obligation are included in property, plant and equipment consists of $3,736 and $3,565 as of December 31, 2008 and 2007, respectively. As of December 31, 2008 and 2007, the Company had recorded $669 and $0, respectively, in amortization for capital lease assets. The assets were placed in service in 2008.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
As of December 31, 2008, the Company had estimated minimum commitments for the payment of rentals under capital leases as follows:
 
         
    Capital
 
Year
  Leases  
 
2009
  $ 1,133  
2010
    845  
2011
    660  
2012
    330  
2013
     
         
Total minimum lease payments
    2,968  
Less amount representing interest
    328  
         
Capital lease obligation
    2,640  
Less obligations due within one year
    961  
         
Long-term capital lease obligation
  $ 1,679  
         
 
9.   Derivatives
 
The Company had the following derivative instruments outstanding as of December 31, 2008 and 2007.
 
Crude Oil Collar and Swap Contracts — Specialty Products Segment
 
The Company utilizes combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty products segment. The Company’s policy is generally to enter into crude oil derivative contracts that match its expected future cash out flows for up to 70% of its anticipated crude oil purchases related to its specialty products production. At December 31, 2008, the Company had approximately 7,700 barrels per day of crude oil hedges expiring in January 2009 through March 2009 and is at the lower end of its targeted volume range of hedges for the specialty products segment. These positions generally will be short term in nature and expire within three to nine months from execution; however, the Company may execute derivative contracts for up to two years forward if its expected future cash flows support lengthening its position.
 
At December 31, 2008, the Company had the following four-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $2,067 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.
 
                                                 
                Average
    Average
    Average
    Average
 
                Lower Put
    Upper Put
    Lower Call
    Upper Call
 
Crude Oil Put/Call Spread Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)     ($/Bbl)     ($/Bbl)     ($/Bbl)  
 
January 2009
    217,000       7,000     $ 50.32     $ 60.32     $ 70.32     $ 80.32  
February 2009
    84,000       3,000       38.33       48.33       58.33       68.33  
                                                 
Totals
    301,000                                          
Average price
                  $ 46.98     $ 56.98     $ 66.98     $ 76.98  
 
At December 31, 2008, the Company had the following two-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $10,277 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.
 


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
                                 
                Average
    Average
 
                Sold Put
    Bought Call
 
Crude Oil Put/Call Spread Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)     ($/Bbl)  
 
January 2009
    186,000       6,000     $ 68.57     $ 90.83  
February 2009
    112,000       4,000       74.85       96.25  
March 2009
    93,000       3,000       79.37       101.67  
                                 
Totals
    391,000                          
Average price
                  $ 72.94     $ 94.96  
 
At December 31, 2007, the Company had the following derivatives related to crude oil purchases in its specialty products segment, all of which were designated as hedges.
 
                                                 
                Average
    Average
    Average
    Average
 
Crude Oil Put/Call Spread
              Lower Put
    Upper Put
    Lower Call
    Upper Call
 
Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)     ($/Bbl)     ($/Bbl)     ($/Bbl)  
 
January 2008
    248,000       8,000     $ 67.85     $ 77.85     $ 87.85     $ 97.85  
February 2008
    232,000       8,000       76.13       86.13       96.13       106.13  
March 2008
    248,000       8,000       77.63       87.63       97.63       107.63  
April 2008
    60,000       2,000       74.30       84.30       94.30       104.30  
May 2008
    62,000       2,000       74.30       84.30       94.30       104.30  
June 2008
    60,000       2,000       74.30       84.30       94.30       104.30  
July 2008
    62,000       2,000       74.30       84.30       94.30       104.30  
August 2008
    62,000       2,000       74.30       84.30       94.30       104.30  
September 2008
    60,000       2,000       74.30       84.30       94.30       104.30  
                                                 
Totals
    1,094,000                                          
Average price
                  $ 74.01     $ 84.01     $ 94.01     $ 104.01  
 
                         
Crude Oil Swap Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)  
 
First Quarter 2008
    91,000       1,000       90.92  
                         
 
Crude Oil Swap Contracts— Fuel Products Segment
 
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 purchases used in fuels production. At December 31, 2008, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as hedges
 
                         
    Barrels
             
Crude Oil Swap Contracts by Expiration Dates
  Purchased     BPD     ($/Bbl)  
 
First Quarter 2009
    2,025,000       22,500     $ 66.26  
Second Quarter 2009
    2,047,500       22,500       66.26  
Third Quarter 2009
    2,070,000       22,500       66.26  
Fourth Quarter 2009
    2,070,000       22,500       66.26  
Calendar Year 2010
    7,300,000       20,000       67.29  
Calendar Year 2011
    3,009,000       8,244       76.98  
                         
Totals
    18,521,500                  
Average price
                  $ 68.41  

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
At December 31, 2008, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $14,278 of unrealized gains in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.
 
                         
Crude Oil Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    450,000       5,000     $ 62.66  
Second Quarter 2009
    455,000       5,000       62.66  
Third Quarter 2009
    460,000       5,000       62.66  
Fourth Quarter 2009
    460,000       5,000       62.66  
                         
Totals
    1,825,000                  
Average price
                  $ 62.66  
 
At December 31, 2007, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which were designated as hedges.
 
                         
    Barrels
             
Crude Oil Swap Contracts by Expiration Dates
  Purchased     BPD     ($/Bbl)  
 
First Quarter 2008
    2,184,000       24,000       67.87  
Second Quarter 2008
    2,184,000       24,000       67.87  
Third Quarter 2008
    2,208,000       24,000       66.54  
Fourth Quarter 2008
    2,116,000       23,000       66.49  
Calendar Year 2009
    8,212,500       22,500       66.26  
Calendar Year 2010
    7,482,500       20,500       67.27  
Calendar Year 2011
    2,096,500       5,744       67.70  
                         
Totals
    26,483,500                  
Average price
                  $ 66.97  
 
Fuels Product Swap Contracts
 
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 and gasoline swap contracts for a period no greater than five years forward and for no more than 75% of forecasted fuels sales.
 
Diesel Swap Contracts
 
At December 31, 2008, 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.
 
                         
Diesel Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    1,170,000       13,000     $ 80.51  
Second Quarter 2009
    1,183,000       13,000       80.51  
Third Quarter 2009
    1,196,000       13,000       80.51  
Fourth Quarter 2009
    1,196,000       13,000       80.51  
Calendar Year 2010
    4,745,000       13,000       80.41  
Calendar Year 2011
    2,371,000       6,496       90.58  
                         
Totals
    11,861,000                  
Average price
                  $ 82.48  


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
At December 31, 2007, 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 except for 42,520 barrels in 2008. As a result of certain of these barrels not being designated as hedges, the Company recognized $941 of losses in unrealized (loss) gain on derivative instruments in the consolidated statements of operations.
 
                         
Diesel Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2008
    1,319,500       14,500       82.81  
Second Quarter 2008
    1,319,500       14,500       82.81  
Third Quarter 2008
    1,334,000       14,500       81.42  
Fourth Quarter 2008
    1,334,000       14,500       81.42  
Calendar Year 2009
    4,745,000       13,000       80.51  
Calendar Year 2010
    4,745,000       13,000       80.41  
Calendar Year 2011
    1,641,000       4,496       79.93  
                         
Totals
    16,438,000                  
Average price
                  $ 80.94  
 
Gasoline Swap Contracts
 
At December 31, 2008, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as hedges.
 
                         
Gasoline Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    855,000       9,500     $ 73.83  
Second Quarter 2009
    864,500       9,500       73.83  
Third Quarter 2009
    874,000       9,500       73.83  
Fourth Quarter 2009
    874,000       9,500       73.83  
Calendar Year 2010
    2,555,000       7,000       75.28  
Calendar Year 2011
    638,000       1,748       83.42  
                         
Totals
    6,660,500                  
Average price
                  $ 75.30  
 
At December 31, 2008, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $15,851 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.
 
                         
    Barrels
             
Gasoline Swap Contracts by Expiration Dates
  Purchased     BPD     ($/Bbl)  
 
First Quarter 2009
    450,000       5,000     $ 60.53  
Second Quarter 2009
    455,000       5,000       60.53  
Third Quarter 2009
    460,000       5,000       60.53  
Fourth Quarter 2009
    460,000       5,000       60.53  
                         
Totals
    1,825,000                  
Average price
                  $ 60.53  


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
At December 31, 2007, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as hedges.
 
                         
Gasoline Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2008
    864,500       9,500       76.98  
Second Quarter 2008
    864,500       9,500       76.98  
Third Quarter 2008
    874,000       9,500       74.79  
Fourth Quarter 2008
    782,000       8,500       74.62  
Calendar Year 2009
    3,467,500       9,500       73.83  
Calendar Year 2010
    2,737,500       7,500       75.10  
Calendar Year 2011
    455,500       1,248       74.98  
                         
Totals
    10,045,500                  
Average price
                  $ 74.91  
 
Natural Gas Swap Contracts
 
The Company utilizes swap contracts to manage natural gas price risk and volatility of cash flows. Certain of these swap contracts are designated as cash flow hedges of the future purchase of natural gas. The Company’s policy is generally to enter into natural gas derivative contracts to hedge approximately 50% or more of its upcoming fall and winter months’ anticipated natural gas requirement for a period no greater than three years forward. At December 31, 2008, the Company had the following derivatives related to natural gas purchases, of which 90,000 MMBtus are designated as hedges. As a result of a portion of these derivative instruments not being designated as hedges, the Company recognized $1,223 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.
 
                 
Natural Gas Swap Contracts by Expiration Dates
  MMBtus     $/MMBtu  
 
First Quarter 2009
    330,000     $ 10.38  
                 
Totals
    330,000          
Average price
          $ 10.38  
 
At December 31, 2007, the Company had the following derivatives related to natural gas purchases, all of which are designated as hedges.
 
                 
Natural Gas Swap Contracts by Expiration Dates
  MMBtu     $/MMBtu  
 
First Quarter 2008
    850,000     $ 8.76  
Third Quarter 2008
    60,000     $ 8.30  
Fourth Quarter 2008
    90,000     $ 8.30  
First Quarter 2009
    90,000     $ 8.30  
                 
Totals
    1,090,000          
Average price
          $ 8.66  
 
Interest Rate Swap Contracts
 
In 2008, the Company entered into a forward swap contract to manage interest rate risk related to its current variable rate senior secured first lien term loan which closed January 3, 2008. The Company has hedged the future interest payments related to $150,000 and $50,000 of the total outstanding term loan indebtedness in 2009 and 2010, respectively, pursuant to this forward swap contract.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
This swap contract is designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at 3.09% and 3.66% per annum in 2009 and 2010, respectively.
 
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 the 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 gain (loss) on derivative instruments in the consolidated statements of operations as of December 31, 2008. For the year ended December 31, 2008, the Company recorded $2,188 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008. 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 which is not designated as a cash flow hedge.
 
10.   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 value 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 consolidated financial statements at fair value in accordance with SFAS No. 157, Fair Value Measurements. The fair value of our long-term debt was $305,084 at December 31, 2008. The fair value of long-term debt materially approximated the carrying value at December 31, 2007. In addition, based upon fees charged for similar agreements, the face values of outstanding standby letters of credit approximated their fair value at December 31, 2008 and 2007.
 
11.   Fair Value Measurements
 
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. The Company has adopted the provisions of SFAS 157 as of January 1, 2008 for financial instruments. In February 2008, the FASB agreed to defer for one year the effective date of SFAS 157 for certain nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.
 
SFAS 157 establishes 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, as required by SFAS No. 157, 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 December 31, 2008, the Company held certain assets 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, natural gas and interest rates, and investments associated with the Company’s non-contributory defined benefit plan (“Pension Plan”).


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
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 single A or better. The fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, natural gas 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 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 December 31, 2008, the Company’s asset was reduced by approximately $6,186 and its liability was reduced by $564. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for gasoline 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 consist of mutual funds that are publicly traded and for which market prices are readily available, thus these investments are categorized as Level 1.
 
The Company’s assets measured at fair value on a recurring basis subject to the disclosure requirements of SFAS 157 at December 31, 2008 were as follows:
 
                                 
    Fair Value Measurements  
    Level 1     Level 2     Level 3     Total  
 
Assets:
                               
Crude oil swaps
  $     $      —     $     $  
Gasoline swaps
                103,780       103,780  
Diesel swaps
                90,337       90,337  
Natural gas swaps
                       
Crude oil options
                       
Pension plan investments
    12,018                   12,018  
                                 
Total assets at fair value
  $ 12,018     $     $ 194,117     $ 206,135  
                                 
Liabilities:
                               
Crude oil swaps
  $     $     $ (119,202 )   $ (119,202 )
Gasoline swaps
                       
Diesel swaps
                       
Natural gas swaps
                (1,429 )     (1,429 )
Crude oil options
                (12,345 )     (12,345 )
Interest rate swaps
                (5,769 )     (5,769 )
Pension plan investments
                       
                                 
Total liabilities at fair value
  $     $     $ (138,745 )   $ (138,745 )
                                 


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
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 year ended December 31, 2008:
 
         
    Derivative
 
    Instruments, Net  
 
Fair value at January 1, 2008
  $ (600,051 )
Realized losses
    58,833  
Unrealized gains (losses)
    17,141  
Comprehensive income (loss)
    58,610  
Purchases, issuances and settlements
    (21,709 )
Transfers in (out) of Level 3
    542,548  
         
Fair value at December 31, 2008
  $ 55,372  
         
Total gains or losses included in net income attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of December 31, 2008
  $ 3,454  
         
 
All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges as defined in SFAS 133, are included in sales for gasoline and diesel derivatives, cost of sales for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in the consolidated financial statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments, as defined in SFAS 133, are recorded in earnings immediately in unrealized gain (loss) on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments. See Note 9 for further information on SFAS 133 and hedging.
 
12.   Partners’ Capital
 
On November 20, 2007, the Partnership completed an offering of its common units in which it sold 2,800,000 common units to the underwriters of the offering at a price to the public of $36.98 per common unit. This issuance was made pursuant to the Partnership’s Registration Statement on Form S-3 (File No. 333-145657) declared effective by the Securities and Exchange Commission on November 9, 2007. The proceeds received by the Partnership (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) from this offering were $98,206. The use of proceeds from the offering was to: (i) repay all its borrowings under its revolving credit facility, which were approximately $59,300 on November 20, 2007, (ii) fund approximately $25,100 of the purchase price for the Penreco acquisition and (iii) to the extent available, for general partnership purposes. Underwriting discounts totaled $4,401. The general partner contributed $2,113 to retain its 2% general partner interest.
 
Of the 19,166,000 common units outstanding at December 31, 2008, 13,085,985 are held by the public, with the remaining 6,080,015 held by the Company’s affiliates. All of the 13,066,000 subordinated units are held by the Company’s affiliates. The Company’s ability to issue new units is limited to 6,533,000 units in certain circumstances where the use of proceeds is not deemed to be accretive to existing unitholders at the time of the offering.
 
Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash as defined in the Company’s partnership agreement. The subordination period will end on the first day of any quarter beginning after


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
December 31, 2010 in which the Company meets certain financial tests provided for in its partnership agreement. Significant information regarding rights of the limited partners include the following:
 
  •  Rights to receive distributions of available cash within 45 days after the end of each quarter, to the extent the Company has sufficient cash from operations after the establishment of cash reserves.
 
  •  Limited partners have limited voting rights on matters affecting the Company’s business. The general partner may consider only the interests and factors that it desires, and has no duty or obligation to give any consideration of any interests of, the Company’s limited partners. Limited partners have no right to elect the board of directors of the Company’s general partner.
 
  •  The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Any holder, other than the general partner or the general partner’s affiliates, that owns 20% or more of any class of units outstanding, cannot vote on any matter.
 
  •  During the subordination period, the general partner, without approval of the limited partners, may cause the Company to issue up to 6,533,000 of additional common units. After the subordination period, the Company may issue an unlimited number of limited partner interests without the approval of the limited partners.
 
  •  Limited partners may be required to sell their units to the general partner if at any time the general partner owns more than 80% of the issued and outstanding common units.
 
The Company’s general partner is entitled to incentive distributions if the amount it distribute to unitholders with respect to any quarter exceeds specified target levels shown below:
 
                     
        Marginal Percentage
 
    Total Quarterly
  Interest in
 
    Distribution   Distributions  
    Target Amount   Unitholders     General Partner  
 
Minimum Quarterly Distribution
  $0.45     98 %     2 %
First Target Distribution
  up to $0.495     98 %     2 %
Second Target Distribution
  above $0.495 up to $0.563     85 %     15 %
Third Target Distribution
  above $0.563 up to $0.675     75 %     25 %
Thereafter
  above $0.675     50 %     50 %
 
The Company’s ability to make distributions is limited by its credit agreements. The credit agreements permit the Company to make distributions to its unitholders as long as it is not in default and would not be in default following the distribution. Under the credit facilities, the Company is obligated to comply with certain financial covenants requiring it to maintain a Consolidated Leverage Ratio of no more than 4.0 to 1 and a Consolidated Interest Coverage Ratio of no less than 2.50 to 1 (as of the end of each fiscal quarter and after giving effect to a proposed distribution or other restricted payments as defined in the credit agreement) and available liquidity of at least $35.0 million (after giving effect to a proposed distribution or other restricted payments as defined in the credit agreements). The Consolidated Leverage Ratio steps down from 4.0 to 1 to 3.75 to 1 and the Consolidated Interest Coverage Ratio steps up from 2.50 to 1 to 2.75 to 1 effective with the quarter ended June 30, 2009.
 
Calumet’s distribution policy is as defined in its partnership agreement. For the years ended December 31, 2008 and 2007, Calumet made distributions of $66,140 and $77,045, respectively, to its partners.
 
13.   Unit-Based Compensation
 
The Company’s general partner originally adopted a Long-Term Incentive Plan (the “Plan”) on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Plan provides for the grant of restricted units, phantom


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by the compensation committee of the Company’s general partner’s board of directors.
 
On December 28, 2007 and December 30, 2008, non-employee directors of our general partner were granted phantom units under the terms of the Plan as part of their director compensation package related to fiscal years 2007 and 2008, respectively. These phantom units have a four year service period, beginning on January 1, with one quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant. The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and selling, general and administrative expense in the consolidated statements of operations using the straight-line method over the four year vesting period, as it expects these units to fully vest.
 
A summary of the Company’s nonvested units as of December 31, 2008, and the changes during the years ended December 31, 2008, 2007 and 2006, are presented below:
 
                 
          Weighted-Average
 
          Grant Date
 
Nonvested Phantom Units
  Grant     Fair Value  
 
Nonvested at January 1, 2006
        $  
Granted
    7,296       33.63  
Vested
    (1,824 )     33.63  
Forfeited
           
                 
Nonvested at December 31, 2006
    5,472     $ 33.63  
Granted
    6,480       37.00  
Vested
    (3,444 )     35.22  
Forfeited
           
                 
Nonvested at December 31, 2007
    8,508     $ 35.56  
Granted
    30,192       7.79  
Vested
    (10,992 )     16.38  
Forfeited
           
                 
Nonvested at December 31, 2008
    27,708     $ 12.91  
                 
 
For the years ended December 31, 2008, 2007 and 2006, compensation expense of $179, $121 and $61, respectively, was recognized in the consolidated statements of operations related to vested unit grants. As of December 31, 2008 and 2007, there was a total of $358 and $303 of unrecognized compensation costs related to nonvested unit grants. These costs are expected to be recognized over a weighted-average period of three years. The total fair value of phantom units vested during the years ended December 31, 2008 and 2007, was $86 and $128.
 
14.   Employee Benefit Plans
 
The Company has a defined contribution plan administered by its general partner. All full-time employees who have completed at least one hour of service are eligible to participate in the plan. Participants are allowed to contribute 0% to 100% of their pre-tax earnings to the plan, subject to government imposed limitations. The


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
Company matches 100% of each 1% contribution by the participant up to 4% and 50% of each additional 1% contribution up to 6% for a maximum contribution by the Company of 5% per participant. The Company’s matching contribution was $1,782, $950, and $1,109 for the years ended December 31, 2008, 2007 and 2006, respectively. The plan also includes a profit-sharing component. Contributions under the profit-sharing component are determined by the board of directors of the Company’s general partner and are discretionary. The Company’s profit sharing contribution was $1,123, $689, and $870 for the years ended December 31, 2008, 2007 and 2006, respectively.
 
The Company has a noncontributory defined benefit plan (“Pension Plan”) for both those salaried employees as well as those employees represented by either the United Steelworkers (“USW”) or the International Union of Operating Engineers (“IUOE”) who were formerly employees of Penreco and who became employees of the Company as a result of the Penreco acquisition on January 3, 2008. The Company also has a contributory defined benefit postretirement medical plan for both those salaried employees as well as those employees represented by either the International Brotherhood of Teamsters (“IBT”), USW or IUOE who were formerly employees of Penreco and who became employees of the Company as a result of the Penreco acquisition, as well as a non-contributory disability plan for those salaried employees who were formerly employees of Penreco (collectively, “Other Plans”). The pension benefits are based primarily on years of service for USW and IUOE represented employees and both years of service and the employee’s final 60 months’ average compensation for salaried employees. The funding policy is consistent with funding requirements of applicable laws and regulations. The assets of these plans consist of corporate equity securities, municipal and government bonds, and cash equivalents. Effective January 31, 2009, the Company has amended the Pension Plan. The amendment removes the salaried employee from accumulating additional benefits subsequent to January 31, 2009. All information presented below has been adjusted for this curtailment, which resulted in a reduction in the Company’s benefit obligation of $2,311.
 
The components of net periodic pension and other post retirement benefits cost for the year ended December 31, 2008 were as follows:
 
                 
    Year Ended December 31, 2008  
          Other Post
 
    Pension
    Retirement
 
    Benefits     Employee Benefits  
 
Service cost
  $ 945     $ 9  
Interest cost
    1,298       51  
Expected return on assets
    (1,341 )      
                 
Net periodic pension cost
  $ 902     $ 60  
                 
 
During the year ended December 31, 2008, the Company made contributions of $193 and $63 to its Pension Plan and Other Plans, respectively, and expects to make no contributions in 2009.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
The benefit obligations, plan assets, funded status, and amounts recognized in the consolidated balance sheets were as follows:
 
                 
          Other Post
 
    Pension
    Retirement
 
    Benefits     Employee Benefits  
 
Change in projected benefit obligation (“PBO”):
               
Benefit obligation at January 3, 2008
  $ 20,097     $ 872  
Service cost
    945       9  
Interest cost
    1,298       51  
Curtailment
    (2,311 )      
Benefits paid
    (630 )     (141 )
Actuarial (gain) loss
    1,613       (30 )
Administrative expense
    (116 )      
Employee contributions
          78  
                 
Benefit obligation at December 31, 2008
  $ 20,896     $ 839  
                 
Change in plan assets:
               
Fair value of plan assets at January 3, 2008
  $ 18,183     $  
Benefit payments
    (630 )     (141 )
Actual return on assets
    (5,612 )      
Administrative expense
    (116 )      
Employee contributions
          78  
Employer contribution
    193       63  
                 
Fair value of plan assets at December 31, 2008
  $ 12,018     $  
                 
Funded status — benefit obligation in excess of plan assets
  $ (8,878 )   $ (839 )
Curtailment
    (2,311 )      
Unrecognized net actuarial loss
    1,613       (30 )
Unexpected loss on plan assets
    6,952        
                 
Net amount recognized at December 31, 2008
  $ (2,624 )   $ (869 )
                 
Amounts recognized in the consolidated balance sheets consisted of:
               
Accrued benefit obligation
  $ (8,878 )   $ (839 )
Accumulated other comprehensive loss
    6,254       (30 )
                 
Net amount recognized at December 31, 2008
  $ (2,624 )   $ (869 )
                 
 
The accumulated benefit obligation for the Pension Plan was $20,896 as of December 31, 2008. The accumulated benefit obligation is equal to the projected benefit obligation due to the curtailment that occurred in 2008. The accumulated benefit obligation for the Pension Plan was less than plan assets by $8,878 as of December 31, 2008. As of December 31, 2008, the Company had no prior service costs or transition gains (losses) but recorded actuarial losses of $6,224 in accumulated other comprehensive income (loss) in the consolidated balance sheets.
 
The effective portion of the minimum pension liability classified in accumulated other comprehensive loss is $6,224 as of December 31, 2008. In 2009, the Company expects to recognize $419 and $0, respectively, of losses


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
from accumulated other comprehensive loss for the Company’s Pension Plan and Other Postretirement Benefits Plan.
 
The significant weighted average assumptions used for the year ended December 31, 2008 were as follows:
 
                 
    Pension
    Other Post Retirement
 
    Benefits     Employee Benefits  
 
Discount rate for benefit obligations
    6.18 %     6.20 %
Discount rate for net periodic benefit costs
    6.58 %     6.20 %
Expected return on plan assets for net periodic benefit costs
    7.50 %     0.00 %
Rate of compensation increase for benefit obligations
    4.50 %     0.00 %
Rate of compensation increase for net periodic benefit costs
    4.50 %     0.00 %
 
For measurement purposes, a 8.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2009. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.5% for 2029 and remain at that level thereafter. An increase or decrease by one percentage point in the assumed healthcare cost trend rates would not have a material effect on the benefit obligation and service and interest cost components of benefit costs for the Other Plans as of January 3, 2008. The Company considered the historical returns and the future expectation for returns for each asset class, as well as the target asset allocation of the Pension Plan portfolio, to develop the expected long-term rate of return on plan assets.
 
The Company’s Pension Plan and Other Plans asset allocations, as of December 31, 2008 by asset category, are as follows:
 
                 
          Other Post
 
          Retirement
 
    Pension
    Employee
 
    Benefits     Benefits  
 
Cash
    2 %     0 %
U.S. equities
    77 %     0 %
Foreign equities
    4 %     0 %
Fixed income
    17 %     0 %
                 
      100 %     0 %
                 
 
Investment Policy
 
The investment objective of the Penreco Pension Plan Trust (the “Trust”) is to generate a long-term rate of return which will fund the related pension liabilities and minimize the Company’s contributions to the Trust. Trust assets are to be invested with an emphasis on providing a high level of current income through fixed income investments and longer-term capital appreciation through equity investments. Trust assets are targeted to achieve an investment return of 7.50% or more compounded annually over any 5-year period. Due to the long-term nature of pension liabilities, the Trust will assume moderate risk only to the extent necessary to achieve its return objective.
 
The Trust pursues its investment objectives by investing in a customized profile of asset allocation which corresponds to the investment return target. Full discretion in portfolio investment decisions is given to Wells Fargo & Company or its affiliates (“the Manager”), subject to the investment policy guidelines. The Manager is required to utilize fiduciary care in all investment decisions and is expected to minimize all costs and expenses involved with the managing of these assets.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
With consideration given to the long-term goals of the Trust, the following ranges reflect the long-term strategy for achieving the stated objectives:
 
                 
    Range of
       
Asset Class
  Asset Allocations     Target Allocation  
 
Cash
    0 — 5 %     Minimal  
Fixed income
    20 — 50 %     35 %
Equities
    50 — 80 %     65 %
 
Trust assets will be invested in accordance with the prudent expert standard as mandated by ERISA. In the event market environments create asset exposures outside of the policy guidelines, reallocations will be made in an orderly manner.
 
Fixed Income Guidelines
 
U.S. Treasury, agency securities, and corporate bond issues rated “investment grade” or higher are considered appropriate for this portfolio. Written approval will be obtained to hold securities downgraded below “investment grade” by either Moody’s or Standard & Poor’s. Money market and fixed-income funds that are consistent with the stated investment objective of the Trust are also considered acceptable.
 
Excluding U.S. Treasury and agency obligations, money market or fixed-income mutual funds, no single issuer shall exceed more than 10% of the total portfolio market value. The average maturity range shall be consistent with the objective of providing a high level of current income and long-term growth within the acceptable risk level established for the Trust.
 
Equity Guidelines
 
Any equity security that is on the Manager’s working list is considered appropriate for this portfolio. Equity mutual funds that are consistent with the stated investment objective of the Trust are also considered acceptable. No individual equity position, with the exception of equity mutual funds, should exceed 10% of the total market value of the Trust’s assets.
 
Performance of investment results will be reviewed, at least semiannually, by the Calumet Retirement Savings Committee (“CRSC”) and annually at a joint meeting between the CRSC and the Manager. Written communication regarding investment performance occurs quarterly. Any major changes in the Manager’s investment strategy will be communicated to the Chairman of the CRSC on an ongoing basis and as frequently as necessary. The Manager shall be informed of special situations affecting Trust investments including substantial withdrawal or funding pattern changes and changes in investment policy guidelines and objectives.
 
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2008:
 
                 
    Pension
    Other Post Retirement
 
    Benefits     Employee Benefits  
 
2009
  $ 773     $ 98  
2010
    820       75  
2011
    870       82  
2012
    949       101  
2013
    1,041       79  
2014 to 2018
    6,527       342  
                 
Total
  $ 10,980     $ 777  
                 


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
15.   Transactions with Related Parties
 
During the years ended December 31, 2008, 2007 and 2006, the Company had sales to related parties owned by a limited partner of $7,973, $4,726 and $904, respectively. Trade accounts and other receivables from related parties at December 31, 2008 and 2007 were $1,828 and $497, respectively. The Company also had purchases from related parties owned by a limited partner, excluding crude purchases related to the Legacy agreement discussed below, during the years ended December 31, 2008, 2007 and 2006 of $615, $1,730 and $1,228, respectively. Accounts payable to related parties, excluding accounts payable related to Legacy agreement discussed below, at December 31, 2008 and 2007 were $774 and $907, respectively.
 
In May 2008, the Company began purchasing all of its crude oil requirements for its Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources Co., L.P. (“Legacy”). Legacy is owned in part by one of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and president, F. William Grube, and Jennifer G. Straumins, the Company’s senior vice president. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company is approximately 6,000 barrels per day. During the year ended December 31, 2008, the Company had crude oil purchases of $140,180 from Legacy. Accounts payable to Legacy at December 31, 2008 related to this agreement were $6,395.
 
A limited partner has provided certain administrative and accounting services to the Company for an annual fee. Such services included, but were not necessarily limited to, advice and assistance concerning aspects of the operation, planning, and human resources of the Company. Payments for the years ended December 31, 2008, 2007 and 2006 were $0, $227 and $549, respectively. The Company terminated these services during the year ended December 31, 2007.
 
The Company previously participated in a self-insurance program for medical benefits with a limited partner and several other related companies. In connection with this program, contributions were made to a voluntary employees’ benefit association (VEBA) trust. Contributions made by the Company to the VEBA for the years ended December 31, 2008, 2007 and 2006 totaled $0, $876 and $3,093, respectively. The Company terminated participation in this related party VEBA during the year ended December 31, 2007 and established a new VEBA of which it is the sole participant and administered by its general partner.
 
During 2006 and prior, the Company had placed a portion of its insurance underwriting requirements, including general liability, automobile liability, excess liability, workers’ compensation as well as directors’ and officers’ liability with a commercial insurance brokerage business. A member of the board of directors of our general partner serves as an executive of this commercial insurance brokerage company. The total premiums paid to this company by Calumet for the years ended December 31, 2008, 2007 and 2006 were $634, $889 and $1,647 respectively. With the exception of its directors’ and officers’ liability insurance which were placed with this commercial insurance brokerage company, the Company placed its insurance requirements with third parties during the years ended December 31, 2008 and 2007.
 
The Company previously participated in a self-insurance program for workers’ compensation with a limited partner and several other related companies. In connection with this program, contributions were made to the limited partner. Contributions made by the Company to the limited partner for the years ended December 31, 2008, 2007 and 2006 totaled $0, $254 and $213, respectively. The Company terminated participation in this plan during the year ended December 31, 2007 and established a self-insurance program on a standalone basis.
 
The Company previously participated in a self-insurance program for general liability with a limited partner and several related companies. In connection with this program, contributions were made to the limited partner. Contributions made by the Company to the limited partner for the years ended December 31, 2008, 2007 and 2006 totaled $0, $998 and $563, respectively. The Company terminated participation in this plan during the year ended December 31, 2007 and established a self-insurance program on a standalone basis.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
16.   Segments and Related Information
 
a.   Segment Reporting
 
Under the provisions of SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, the Company has two reportable segments: Specialty Products and Fuel Products. The Specialty Products segment, which includes Penreco from its date of acquisition, produces a variety of lubricating oils, solvents and waxes. 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 from operations. The Company accounts for intersegment sales and transfers at cost plus a specified mark-up. Reportable segment information is as follows:
 
                                         
    Specialty
    Fuel
    Combined
          Consolidated
 
Year Ended December 31, 2008
  Products     Products     Segments     Eliminations     Total  
 
Sales:
                                       
External customers
  $ 1,578,035     $ 910,959     $ 2,488,994     $     $ 2,488,994  
Intersegment sales
    1,113,342       27,925       1,141,267       (1,141,267 )      
                                         
Total sales
  $ 2,691,377     $ 938,884     $ 3,630,261     $ (1,141,267 )   $ 2,488,994  
                                         
Depreciation and amortization
    61,729               61,729               61,729  
Income from operations
    72,709       56,031       128,740               128,740  
Reconciling items to net income:
                                       
Interest expense
                                    (33,938 )
Interest income
                                    388  
Debt extinguishment costs
                                    (898 )
Loss on derivative instruments
                                    (55,379 )
Gain on sale of mineral rights
                                    5,770  
Other
                                    11  
Income tax expense
                                    (257 )
Net income
                                    44,437  
Capital expenditures
  $ 167,702     $     $ 167,702     $     $ 167,702  
 


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
                                         
    Specialty
    Fuel
    Combined
          Consolidated
 
Year Ended December 31, 2007
  Products     Products     Segments     Eliminations     Total  
 
Sales:
                                       
External customers
  $ 866,716     $ 771,132     $ 1,637,848     $     $ 1,637,848  
Intersegment sales
    691,592       32,651       724,243       (724,243 )      
                                         
Total sales
  $ 1,558,308     $ 803,783     $ 2,362,091     $ (724,243 )   $ 1,637,848  
                                         
Depreciation and amortization
    17,775             17,775             17,775  
Income from operations
    42,282       58,918       101,200             101,200  
Reconciling items to net income:
                                       
Interest expense
                                    (4,717 )
Interest income
                                    1,944  
Debt extinguishment costs
                                    (352 )
Gain (loss) on derivative instruments
                                    (13,781 )
Other
                                    (919 )
Income tax expense
                                    (501 )
                                         
Net income
                                    82,874  
                                         
Capital expenditures
  $ 261,015     $     $ 261,015     $     $ 261,015  
 
                                         
    Specialty
    Fuel
    Combined
          Consolidated
 
Year Ended December 31, 2006
  Products     Products     Segments     Eliminations     Total  
 
Sales:
                                       
External customers
  $ 913,143     $ 727,905     $ 1,641,048     $     $ 1,641,048  
Intersegment sales
    653,842       34,135       687,977       (687,977 )      
                                         
Total sales
  $ 1,566,985     $ 762,040     $ 2,329,025     $ (687,977 )   $ 1,641,048  
                                         
Depreciation and amortization
    15,027             15,027             15,027  
Income from operations
    83,526       39,607       123,133             123,133  
Reconciling items to net income:
                                       
Interest expense
                                    (9,030 )
Interest income
                                    2,951  
Debt extinguishment costs
                                    (2,967 )
Gain (loss) on derivative instruments
                                    (18,045 )
Other
                                    (274 )
Income tax expense
                                    (190 )
                                         
Net income
                                    95,578  
                                         
Capital expenditures
  $ 76,064     $     $ 76,064     $     $ 76,064  
 

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
                 
    December 31,  
    2008     2007  
 
Segment assets:
               
Specialty products
  $ 2,208,741     $ 1,462,996  
Fuel products
    1,483,457       1,019,149  
                 
Combined segments
    3,692,198       2,482,145  
Eliminations
    (2,611,136 )     (1,803,288 )
                 
Total assets
  $ 1,081,062     $ 678,857  
                 
 
b.   Geographic Information
 
International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2008, 2007 and 2006. 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 and jet fuel. The following table sets forth the major product category sales:
 
                         
    Year Ended December 31,  
    2008     2007     2006  
 
Specialty products:
                       
Lubricating oils
  $ 841,225     $ 478,132     $ 509,933  
Solvents
    419,831       199,843       201,931  
Waxes
    142,525       61,621       61,192  
Fuels
    30,389       52,449       41,268  
Asphalt and other by-products
    144,065       74,671       98,819  
                         
Total
    1,578,035       866,716       913,143  
                         
Fuel products:
                       
Gasoline
    332,669       307,144       336,681  
Diesel
    379,739       203,659       207,148  
Jet fuel
    186,675       225,868       176,372  
By-products
    11,876       34,461       7,704  
                         
Total
    910,959       771,132       727,905  
                         
Consolidated sales
  $ 2,488,994     $ 1,637,848     $ 1,641,048  
                         
 
d.   Major Customers
 
During the year ended December 31, 2008, the Company had one customer, Murphy Oil U.S.A., which represented approximately 10.5% of consolidated sales. No other customer represented 10% or greater of consolidated sales in each of the three years ended December 31, 2008, 2007 and 2006.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
17.   Quarterly Financial Data (Unaudited)
 
                                         
    First
    Second
    Third
    Fourth
       
    Quarter     Quarter     Quarter     Quarter     Total (1)  
 
2008
                                       
Sales
  $ 594,723     $ 671,220     $ 724,371     $ 498,680     $ 2,488,994  
Gross profit
    34,834       60,882       76,974       81,193       253,883  
Net income
    (3,392 )     41,808       (12,515 )     18,536       44,437  
Basic and diluted net income per limited partner unit:
                                       
Common
  $ 0.45     $ 0.96     $ 0.45     $ 0.55     $ 2.41  
Subordinated
  $ (0.91 )   $ 0.96     $ (1.60 )   $ 0.55     $ (1.00 )
Weighted average limited partner common units outstanding — basic
    19,166,000       19,166,000       19,166,000       19,166,000          
Weighted average limited partner common units outstanding — diluted
    19,166,000       19,166,000       19,166,000       19,166,000          
Weighted average limited partner subordinated units outstanding — basic and diluted
    13,066,000       13,066,000       13,066,000       13,066,000          
 
                                         
    First
    Second
    Third
    Fourth
       
    Quarter     Quarter     Quarter     Quarter     Total(1)  
 
2007
                                       
Sales
  $ 351,113     $ 421,726     $ 428,084     $ 436,925     $ 1,637,848  
Gross profit
    55,034       60,471       37,875       27,976       181,356  
Net income
    28,210       37,418       9,456       7,790       82,874  
Basic and diluted net income per limited partner unit:
                                       
Common
  $ 0.79     $ 0.94     $ 0.45     $ 0.45     $ 2.63  
Subordinated
  $ 0.79     $ 0.94     $ 0.15     $ (0.02 )   $ 1.86  
Weighted average limited partner common units outstanding — basic
    16,366,000       16,366,000       16,366,000       17,613,826          
Weighted average limited partner common units outstanding — diluted
    16,367,000       16,368,000       16,369,000       17,615,246          
Weighted average limited partner subordinated units outstanding — basic and diluted
    13,066,000       13,066,000       13,066,000       13,066,000          
 
 
(1) The sum of the four quarters may not equal the total year due to rounding.
 
18.   Subsequent Events
 
On January 22, 2009, the Company declared a quarterly cash distribution of $0.45 per unit on all outstanding units, or $14,800, for the quarter ended December 31, 2008. The distribution was paid on February 13, 2009 to unitholders of record as of the close of business on February 3, 2009. This quarterly distribution of $0.45 per unit equates to $1.80 per unit, or $59,202 on an annualized basis.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(in thousands, except operating, unit and per unit data)
 
On January 26, 2009, the Company entered into a crude oil supply agreement with Legacy Resources Co., L.P. (“Legacy”) an affiliate of the Company’s general partner. Under the agreement, it is contemplated that Legacy will supply the Company’s Shreveport refinery with a portion of its crude oil requirements that are received via common carrier pipeline. Pricing for the crude oil purchased under each confirmation will be mutually agreed to by the parties and set forth in such confirmation and will include a market-based premium as determined and agreed to by the parties. The agreement is effective as of January 26, 2009 and will continue to be in effect until terminated by either party by written notice. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company under this Agreement is up to 15,000 barrels per day. Legacy is owned in part by The Heritage Group, an affiliate of the Company’s general partner, in part by the Company’s general partner’s chief executive officer and president, F. William Grube, and in part by the Company’s general partner’s senior vice president, Jennifer G. Straumins.


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Report of Independent Registered Public Accounting Firm
 
To the Members of
Calumet GP, LLC
 
We have audited the accompanying balance sheet of Calumet GP, LLC as of December 31, 2008. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.
 
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Calumet GP, LLC’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Calumet GP, LLC’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.
 
In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Calumet GP, LLC at December 31, 2008, in conformity with U.S. generally accepted accounting principles.
 
/s/  Ernst & Young LLP
 
Indianapolis, Indiana
February 27, 2009


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CALUMET GP, LLC
 
CONSOLIDATED BALANCE SHEET
 
         
    December 31,
 
    2008  
    (In thousands)  
 
ASSETS
Current assets:
       
Cash and cash equivalents
  $ 313  
Accounts receivable:
       
Trade, less allowance for doubtful accounts of $2,121
    103,993  
Other
    5,594  
         
      109,587  
         
Inventories
    118,524  
Derivative assets
    71,199  
Prepaid expenses and other current assets
    1,803  
Deposits
    4,021  
         
Total current assets
    305,447  
Property, plant and equipment, net
    659,684  
Goodwill
    48,335  
Other intangible assets, net
    49,502  
Other noncurrent assets, net
    18,390  
         
Total assets
  $ 1,081,358  
         
 
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
       
Accounts payable
  $ 87,460  
Accounts payable — related party
    6,395  
Accrued salaries, wages and benefits
    6,865  
Taxes payable
    6,833  
Other current liabilities
    9,662  
Current portion of long-term debt
    4,811  
Derivative liabilities
    15,827  
         
Total current liabilities
    137,853  
Pension and post-retirement benefit obligations
    9,717  
Long-term debt, less current portion
    460,280  
         
Total liabilities
    607,850  
Commitments and contingencies
       
Minority interest
    242,632  
Members’ capital
    175,310  
Accumulated other comprehensive income
    55,566  
         
Total members’ capital
    230,876  
         
Total liabilities and members’ capital
  $ 1,081,358  
         
 
See accompanying notes to the consolidated balance sheet.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET
(in thousands, except operating, unit and per unit data)
 
1.   Nature of Operations
 
Calumet GP, LLC (the GP) is a Delaware limited liability company formed on September 27, 2005 and is the general partner of Calumet Specialty Products Partners, L.P. (the Partnership). Its sole purpose is to operate the Partnership. The GP is owned by The Heritage Group as well as Fred M. Fehsenfeld, Jr. family trusts and an F. William Grube family trust. The GP owns a two percent general partner interest in the Partnership and manages and operates all of the assets of the Partnership. However, due to the substantive control granted to the GP by the partnership agreement we consolidate our interest in the Partnership (collectively Calumet or the Company).
 
Calumet is engaged in the production and marketing of crude oil-based specialty lubricating oils, fuels, solvents and waxes. Calumet owns refineries located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport, Louisiana, Karns City, Pennsylvania, Dickenson, Texas and a terminal located in Burnham, Illinois.
 
On January 3, 2008, Calumet closed on its acquisition of Penreco, a Texas general partnership. See Note 4.
 
2.   Members’ Capital
 
During the year ended December 31, 2008, the GP received cash distributions of $1,018 from the Partnership and distributed $1,018 to the GP’s members.
 
3.   Summary of Significant Accounting Policies
 
Consolidation
 
The consolidated financial statements of the GP include the accounts of the GP, the Partnership and its wholly-owned operating subsidiaries, Calumet Lubricants Co., Limited Partnership, Calumet Sales Company Incorporated, Calumet Penreco, LLC and Calumet Shreveport, LLC. Calumet Shreveport, LLC’s wholly-owned operating subsidiaries are Calumet Shreveport Fuels, LLC and Calumet Shreveport Lubricants & Waxes, LLC. All intercompany transactions and accounts have been eliminated. Hereafter, the consolidated companies are referred to as the Company.
 
Use of Estimates
 
The Company’s financial statements are prepared in conformity with U.S. generally accepted accounting principles which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Cash and Cash Equivalents
 
Cash and cash equivalents includes all highly liquid investments with a maturity of three months or less at the time of purchase.
 
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.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
Inventories consist of the following:
 
         
    December 31,
 
    2008  
 
Raw materials
  $ 24,955  
Work in process
    43,735  
Finished goods
    49,834  
         
    $ 118,524  
         
 
The replacement cost of these inventories, based on current market values, would have been $27,517 higher as of December 31, 2008.
 
Accounts Receivable
 
The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivables are generally due within 30 days for the specialty products segment and 10 days for the fuel products segment. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical credit experience and expected future trends. The activity in the allowance for doubtful accounts was as follows:
 
         
    December 31,
 
    2008  
 
Beginning balance
  $ 786  
Provision
    1,448  
Write-offs, net
    (113 )
         
Ending balance
    2,121  
         
 
Property, Plant and Equipment
 
Property, plant and equipment are stated on the basis of cost. Depreciation is calculated generally on composite groups, using the straight-line method over the estimated useful lives of the respective groups.
 
Property, plant and equipment, including depreciable lives, consists of the following:
 
         
    December 31,
 
    2008  
 
Land
  $ 3,249  
Buildings and improvements (10 to 40 years)
    6,626  
Machinery and equipment (10 to 20 years)
    711,122  
Furniture and fixtures (5 to 10 years)
    2,682  
Assets under capital leases (4 years)
    4,015  
Construction-in-progress
    25,065  
         
      752,759  
Less accumulated depreciation
    (93,075 )
         
    $ 659,684  
         


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related accumulated depreciation are retired, and any gain or loss is reflected in earnings.
 
During the year ended December 31, 2008, the Company incurred $41,159 of interest expense of which $7,221 was capitalized as a component of property, plant and equipment.
 
The Company has not recorded an asset retirement obligation as of December 31, 2008 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.
 
Accumulated depreciation above includes $669 of depreciation expense related to the Company’s capitalized lease assets.
 
Goodwill
 
Goodwill represents the excess of purchase price over fair value of the net assets acquired in the Penreco acquisition. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, goodwill and other intangible assets are not amortized, but are tested for impairment at least annually and when indicators dictate, such as adverse changes in business climate, market value of long-lived assets or a change in the structure of the Company. The Company performs its annual impairment review in the fourth quarter of each fiscal year, unless circumstances dictate more frequent assessments. The 2008 annual impairment review resulted in no impairment charge. For more information, refer to Note 6.
 
Other Intangible Assets
 
Other intangible assets primarily consist of supply agreements, customer relationships, non-compete agreements and patents acquired in the Penreco acquisition. These assets are being amortized using the discounted estimated future cash flows method over the term of the related agreements. Intangible assets associated with customer relationships of Penreco are being amortized using the discounted estimated future cash flows method based upon an assumed rate of annual customer attrition. For more information, refer to Note 6.
 
Impairment of Long-Lived Assets
 
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In such an event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair market value of the long-lived asset. Fair market value is determined primarily using anticipated cash flows discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.
 
Revenue Recognition
 
The Company recognizes revenue on orders received from its customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under the Company’s normal billing and credit terms, all of the Company’s obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
Concentrations of Credit Risk
 
The Company performs periodic credit evaluations of its customers’ financial condition and generally does not require collateral. The Company maintains allowances for doubtful customer accounts for estimated losses resulting from the inability of its customers to make required payments. The allowance for doubtful accounts is developed based on several factors including customers’ credit quality, historical write-off experience, age of accounts receivable, default percentages provided by a third party and any known specific issues or disputes which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, the Company has significant derivative assets with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s SFAS No. 157, Fair Value Measurements, valuations to determine the impact of counterparty credit risk on the valuation of its derivative instruments.
 
Income Taxes
 
The Company, as a limited liability company, is not liable for income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries Calumet Lubricants Co., Limited Partnership, Calumet Penreco, LLC and Calumet Shreveport, LLC. However, Calumet Sales Company Incorporated (“Calumet Sales Company”), a wholly-owned subsidiary of the Company, is a corporation and as a result, is liable for income taxes on its earnings. Income taxes on the earnings of the Company, with the exception of Calumet Sales Company, are the responsibility of the members, with earnings of the Company included in members’ earnings.
 
In the event that the Partnership’s taxable income did not meet certain qualification requirements, it would be taxed as a corporation. Related to these qualifications, the Partnership requested a ruling from the Internal Revenue Service (“IRS”) with respect to the qualifying nature of income generated from the Penreco assets and business operations. In the fourth quarter of 2008, the IRS provided a favorable ruling. Interest and penalties related to income taxes, if any, would be recorded in income tax expense. The Company had no unrecognized tax benefits as of December 31, 2008. The Company’s income taxes generally remain subject to examination by major tax jurisdictions for a period of three years.
 
Effective January 1, 2007, the Company adopted the provisions of Financial Interpretation No. 48,Accounting for Uncertainty in Income Taxes (the “Interpretation”), an interpretation of SFAS Statement No. 109, Accounting for Income Taxes. The Interpretation clarifies the accounting for uncertainty in income taxes by prescribing a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position to be taken or expected to be taken in a tax return. The implementation of the Interpretation did not have a material effect on the Company’s financial position, results of operations or cash flows.
 
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. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133, and in May 2003 by SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, (collectively referred to as “SFAS 133”), the Company recognizes all derivative instruments as either assets or liabilities at fair value on the balance sheets. The Company utilizes third party valuations and published market data to determine the fair value of these derivative instruments. To the extent a derivative instrument is designated 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 instrument is deferred in accumulated other comprehensive income (loss), a component of partners’ capital. The Company accounts for certain derivatives hedging purchases of crude oil and natural gas, the sale of gasoline, diesel and jet fuel, and the payment of interest as


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
cash flow hedges. The derivative instruments designated as hedging purchases and sales are recorded to cost of sales and sales in the consolidated statements of operations, respectively, upon recording the related hedged transaction in sales or cost of sales. The derivative instruments designated as hedging payments of interest are recorded in interest expense in the consolidated statements of operations. For the year ended December 31, 2008, the Company has recorded derivative losses of $297,319 to sales and derivative gains of $306,079 to cost of sales in the consolidated statements of operations. During the year ended December 31, 2008, the Company recorded a loss of $49,746 on crude oil collar, interest rate swap and natural gas swap derivative settlements in realized gain (loss) on derivative instruments in the consolidated statements of operations due to the derivative transactions not being designated as cash flow hedges. An interest rate swap loss of $554 for the year ended December 31, 2008, was recorded to interest expense in the consolidated statements of operations. 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 or loss on derivative instruments in the 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 loss on derivative instruments in the consolidated statements of operations.
 
The Company assesses, both at inception of the hedge and on an ongoing basis, whether the derivative instruments that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company’s estimate of the ineffective portion of the hedges for the year ended December 31, 2008 was a gain of $3,730 which was recorded to unrealized gain (loss) on derivative instruments and realized loss on derivative instruments in the consolidated statements of operations.
 
The effective portion of the hedges classified in accumulated other comprehensive income (loss) is $61,790 as of December 31, 2008 and, absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2011 with balances being recognized as follows:
 
         
    Accumulated Other
 
    Comprehensive
 
Year
  Income (Loss)  
 
2009
  $ 24,878  
2010
    27,102  
2011
    9,810  
2012
     
         
Total
  $ 61,790  
 
The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative instruments. The Company executes all its derivative instruments with a small number of counterparties, the majority of which are large financial institutions with ratings of at least A1 and A+ by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on a derivative instrument’s 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. The Company’s contracts with these counterparties allow for netting of derivative instrument positions executed under each contract. The Company does not expect nonperformance on any derivative instrument.
 
Other Noncurrent Assets
 
Other noncurrent assets consist of deferred debt issuance costs and turnaround costs. Deferred debt issuance costs were $8,899 as of December 31, 2008 and are being amortized on a straight-line basis over the lives of the related debt instruments. These amounts are net of accumulated amortization of $2,160 at December 31, 2008.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $9,491 as of December 31, 2008. The Company capitalizes these costs and amortizes the cost on a straight-line basis over the lives of the turnaround assets. These amounts are net of accumulated amortization of $2,586 at December 31, 2008.
 
New Accounting Pronouncements
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (the “Statement”). The Statement applies to assets and liabilities required or permitted to be measured at fair value under other accounting pronouncements. The Statement defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements about fair value, but does not provide guidance whether assets and liabilities are required or permitted to be measured at fair value. The Statement is effective for fiscal years beginning after November 15, 2007. The Company adopted the Statement on January 1, 2008 and applied the various disclosures as required by the Statement. The adoption of this Statement did not have a material affect on the Company’s financial position or results of operations. In February 2008, the FASB agreed to defer for one year the effective date of the Statement for certain nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.
 
In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (the “Position”), which amends certain aspects of FASB Interpretation Number 39, Offsetting of Amounts Related to Certain Contracts. The Position permits companies to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The Position is effective for fiscal years beginning after November 15, 2007. The Company’s accounting policy is to not offset fair value amounts recognized for the right at reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangements. As of December 31, 2008, the Company has provided cash margin of $4.0 million in credit support to certain of its hedging counterparties.
 
In December 2007, the FASB issued FASB Statement No. 141(R), Business Combinations (the “Statement”). The Statement applies to the financial accounting and reporting of business combinations. The Statement is effective for business combination transactions for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company anticipates that the Statement will not have a material effect on its financial position, results of operations, or cash flows.
 
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS 133 have been applied, and the impact that hedges have on an entity’s financial position, results of operations, and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company currently provides an abundance of information about its hedging activities and use of derivatives in its quarterly and annual filings with the SEC, including many of the disclosures contained within SFAS 161. Thus, the Company currently does not anticipate the adoption of SFAS 161 will have a material impact on the disclosures already provided.
 
In March 2008, the FASB issued EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“EITF 07-4”). EITF 07-4 requires master limited partnerships to treat incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to pay IDRs. EITF 07-4 requires that


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
undistributed earnings be allocated to the partnership interests based on the allocation of earnings to capital accounts as specified in the respective partnership agreement. When distributions exceed earnings, EITF 07-4 requires that net income be reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the respective partnership agreement. EITF 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Company is evaluating the potential impacts of EITF 07-4.
 
In April 2008, the FASB issued FASB Staff Position No. 142-3, Determination of the Useful Life of Intangible Assets, (“FSP No. 142-3”) that amends the factors considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). FSP No. 142-3 requires a consistent approach between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of an asset under SFAS No. 141(R), Business Combinations. FSP No. 142-3 also requires enhanced disclosures when an intangible asset’s expected future cash flows are affected by an entity’s intent and/or ability to renew or extend the arrangement. FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and is applied prospectively. Early adoption is prohibited. The Company does not expect the adoption of FSP No. 142-3 will have a material impact on its consolidated results of operations or financial condition.
 
4.   Acquisition of Penreco
 
On January 3, 2008 the Company acquired Penreco, a Texas general partnership, for $269,118, net of the cash acquired. Penreco was owned by ConocoPhillips Company and M.E. Zukerman Specialty Oil Corporation. Penreco manufactures and markets highly-refined products and specialty solvents, including white mineral oils, petrolatums, natural petroleum sulfonates, cable-filling compounds, refrigeration oils, food-grade compressor lubricants and gelled products. The acquisition included facilities in Karns City, Pennsylvania and Dickinson, Texas, as well as several long-term supply agreements with ConocoPhillips Company.
 
The Company believes that this acquisition provides several key strategic benefits, including market synergies within its solvents and lubricating oil product lines, additional operational and logistics flexibility and overhead cost reductions resulting from the acquisition. The acquisition also broadens the Company’s customer base and gives the Company access to new markets.
 
As a result of the acquisition, the assets and liabilities previously held by Penreco and results of the operations of these assets have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition.
 
The Company recorded $48,335 of goodwill as a result of this acquisition, all of which was recorded within the Company’s specialty products segment. The allocation of the aggregate purchase price is as follows:
 
         
Accounts receivable
  $ 42,049  
Inventories
    66,392  
Prepaid expenses and other current assets
    70  
Property, plant and equipment
    91,790  
Other noncurrent assets
    288  
Intangibles
    59,325  
Goodwill
    48,335  
Accounts payable
    (29,014 )
Other current liabilities
    (7,331 )
Other noncurrent liabilities
    (2,786 )
         
Total purchase price, net of cash acquired
  $ 269,118  
         


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
The components of intangible assets listed in the table above as of January 3, 2008, based upon a third party appraisal, were as follows:
 
                 
    Amount     Life  
 
Customer relationships
  $ 28,482       20  
Supplier agreements
    21,519       4  
Patents
    1,573       12  
Non-competition agreements
    5,732       5  
Distributor agreements
    2,019       3  
                 
Total
  $ 59,325          
                 
Weighted average amortization period
            12  
 
The Company formulated its plan associated with the involuntary termination of certain non-union Penreco employees and accrued $1,829 for such costs, which are included in the acquisition liabilities. All affected employees have been terminated and substantially all liabilities have been paid as of December 31, 2008.
 
5.   Shreveport Refinery Expansion
 
During the year ended December 31, 2008, the Company invested an additional $119,630 for a total investment of $374,044 in its Shreveport refinery expansion project. The project was completed and operational in May 2008. Additionally, for the years ended December 31, 2008, the Company had invested $40,753 in the Shreveport refinery for other capital expenditures including projects to improve efficiency, de-bottleneck certain operating units and for new product development.
 
6.   Goodwill and Other Intangible Assets
 
The Company has recorded $48,335 of goodwill as a result of the Penreco acquisition, all of which is recorded within the Company’s specialty products segment.
 
Other intangible assets consist of the following:
 
                         
          December 31, 2008  
    Weighted
    Gross
    Accumulated
 
    Average Life     Amount     Amortization  
 
Customer relationships
    20     $ 28,482     $ (4,071 )
Supplier agreements
    4       21,519       (7,539 )
Patents
    12       1,573       (313 )
Non-competition agreements
    5       5,732       (768 )
Distributor agreements
    3       2,019       (758 )
Royalty agreements
    19       4,116       (490 )
                         
      12     $ 63,441     $ (13,939 )
                         
 
Intangible assets associated with supplier agreements, non-competition agreements, patents and distributor agreements are being amortized on an accelerated basis in order to properly match expense with the estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships of Penreco are being amortized using the discounted estimated future cash flows based upon an assumed rate of annual customer attrition.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
7.   Commitments and Contingencies
 
Operating Leases
 
The Company has various operating leases for the use of land, storage tanks, compressor stations, railcars, equipment, precious metals, operating unit catalyst and office facilities that extend through August 2015. Renewal options are available on certain of these leases in which the Company is the lessee.
 
As of December 31, 2008, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows:
 
         
    Operating
 
Year
  Leases  
 
2009
  $ 12,665  
2010
    10,154  
2011
    8,133  
2012
    6,223  
2013
    4,438  
Thereafter
    4,075  
         
Total
  $ 45,688  
         
 
Historically, the Company has purchased a portion of its crude oil under a contract that contained minimum purchase requirements. This contract expired during 2008 and the Company has fulfilled all commitments under the contract. Total purchases under this contract were $690,359 for the year ended December 31, 2008. The Company is currently purchasing all of its crude oil under evergreen contracts or on a spot basis. As of December 31, 2008, the estimated minimum purchase requirements under our crude oil contracts were as follows:
 
         
Year
  Commitment  
 
2009
  $ 149,613  
2010
     
2011
     
2012
     
2013
     
Thereafter
     
         
Total
  $ 149,613  
         
 
In connection with the closing of the Penreco acquisition on January 3, 2008, the Company 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, the Company is obligated to purchase $37,365  of feedstock for the LVT unit in each of the next four years based on pricing estimates as of December 31, 2008. 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 the Company as liquidated damages.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
Labor Matters
 
The Company has approximately 360 employees out of a total of approximately 630 covered by various collective bargaining agreements. These agreements have expiration dates of March 31, 2010, April 30, 2010, October 31, 2011 and January 31, 2012.
 
Contingencies
 
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxing and regulatory authorities, such as the Louisiana Department of Environmental Quality (“LDEQ”), Environmental Protection Agency (“EPA”), IRS and Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position, results of operations or cash flow.
 
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 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. In particular, the LDEQ has proposed penalties totaling approximately $400 and supplemental projects 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. The Company anticipates that any penalties that may be assessed due to the alleged violations will be consolidated in a settlement agreement that the Company anticipates executing with the LDEQ in connection with the agency’s “Small Refinery and Single Site Refinery Initiative” described below. The Company has recorded a liability for the proposed penalty within other current liabilities on the consolidated balance sheets. Environmental expenses are recorded within other expenses in the consolidated statements of operations.
 
The Company is party to ongoing discussions on a voluntary basis with the LDEQ regarding the Company’s participation in that agency’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


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. The Company expects that the LDEQ’s primary focus under the state initiative will be on four compliance and enforcement concerns: (i) Prevention of Significant Deterioration/New Source Review; (ii) New Source Performance Standards for fuel gas combustion devices, including flares, heaters and boilers; (iii) Leak Detection and Repair requirements; and (iv) Benzene Waste Operations National Emission Standards for Hazardous Air Pollutants. The Company is in discussions with the LDEQ regarding its participation in this regulatory initiative and the Company anticipates that it will be entering into a settlement agreement with the LDEQ pursuant to which the Company will be required to make emissions reductions requiring capital investments between approximately $1,000 and $3,000 in total over a three to five year period at its three Louisiana refineries. Because the settlement agreement is also expected to resolve the alleged air emissions issues at the Company’s Cotton Valley and Princeton refineries and consolidate any penalties associated with such issues, the Company further anticipates that a penalty of approximately $400 will be assessed in connection with this settlement agreement.
 
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. During 2008, the Company determined that it will incur approximately $700 of costs during 2009 at its Cotton Valley refinery in connection with continued remediation of groundwater impacts at that site.
 
The Company also is in separate discussions with the EPA to resolve alleged deficiencies in risk management planning in connection with a fire-related incident arising out of tank cleaning and vacuum truck operations at its Shreveport refinery on October 30, 2008. The incident involved a third-party contractor and resulted in damage to an on-site aboveground storage tank. Following an investigation of the matter, EPA issued five violations against the Company, alleging, among other things, inadequate contractor training and oversight, and has proposed a penalty of $230. The Company is currently evaluating its response to the EPA with respect to the matter.
 
The Company is indemnified by Shell Oil Company (“Shell”), 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.
 
The Company is indemnified on a limited basis by ConocoPhillips Company and M.E. Zuckerman Specialty Oil Corporation, former owners of Penreco, for pending, threatened, contemplated or contingent environmental claims against Penreco, if any, that were not known and identified as of the Penreco acquisition date. A significant portion of these indemnifications will expire two years from January 1, 2008 if there are no claims asserted by the Company and are generally subject to a $2,000 limit.
 
Health and Safety
 
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, state and local government authorities and citizens. 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 commissioned studies to assess the adequacy of its process safety management practices at its Shreveport refinery. Depending on the findings made in these studies, the


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
Company may incur capital expenditures over the next several years to enhance these practices so that it may maintain its compliance with applicable OSHA regulations at the refinery. While the Company does not expect these expenditures to be material at this time, it has not yet received the reports from the engineering firms conducting the studies to reach final resolution. The Company believes that its operations are in substantial compliance with OSHA and similar state laws.
 
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 December 31, 2008, the Company had outstanding standby letters of credit of $21,355 under its senior secured revolving credit facility. The maximum amount of letters of credit the Company can issue is limited to its borrowing capacity under its revolving credit facility or $300,000, whichever is lower. As of December 31, 2008, the Company had availability to issue letters of credit of $51,865 under its revolving credit facility. As discussed in Note 8, as of December 31, 2008 the Company also had a $50,000 letter of credit outstanding under its senior secured first lien letter of credit facility for its fuels hedging program, which bears interest at 4.0%.
 
8.   Long-Term Debt
 
Long-term debt consisted of the following:
 
         
    December 31,
 
    2008  
 
Borrowings under new senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 4.00% (6.15% at December 31, 2008), interest and principal payments quarterly with borrowings due January 2015, effective interest rate of 7.84%
  $ 375,085  
Borrowings under senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 3.50% (8.74% at December 31, 2007), interest and principal payments quarterly with borrowings due December 2012
     
Borrowings under senior secured revolving credit agreement with third-party lenders, interest at prime plus 0.50% (3.75% and 7.25% at December 31, 2008 and 2007, respectively), interest payments monthly, borrowings due January 2013
    102,539  
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly with borrowings due January 2012
    2,640  
Less unamortized discount on new senior secured first lien term loan with third-party lenders
    (15,173 )
         
Total long-term debt
    465,091  
Less current portion of long-term debt
    4,811  
         
    $ 460,280  
         
 
The borrowing capacity at December 31, 2008 under the revolving credit facility was $175,759, with $51,865 available for additional borrowings based on collateral and specified availability limitations. The revolving credit facility has a first priority lien on the Company’s cash, accounts receivable and inventory and a second priority lien on the Company’s fixed assets.
 
On January 3, 2008, the Partnership closed a new $435,000 senior secured first lien term loan facility which includes a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. The proceeds of the term loan were used to (i) finance a portion of the acquisition of Penreco, (ii) fund the anticipated growth in working capital and remaining capital expenditures associated with the Shreveport refinery expansion project, (iii) refinance the existing term loan and (iv) to the extent available, for general partnership purposes. The new term loan bears interest at a rate equal (i) with respect to a Eurodollar Loan, the Eurodollar Rate plus 400 basis


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
points and (ii) with respect to a Base Rate Loan, the Base Rate plus 300 basis points (as defined in the term loan credit agreement). The letter of credit facility to support crack spread hedging bears interest at 4.0%.
 
Lenders under the term loan facility have a first priority lien on the Company’s fixed assets and a second priority lien on its cash, accounts receivable, inventory and other personal property. The term loan facility matures in January 2015. The term loan facility requires quarterly principal payments of $963 until maturity on September 30, 2014, with the remaining balance due at maturity on January 3, 2015.
 
On January 3, 2008, the Partnership amended its existing senior secured revolving credit facility dated as of December 9, 2005, Pursuant to this amendment, the revolving credit facility lenders agreed to, among other things, (i) increase the total availability under the revolving credit facility up to $375,000 and (ii) conformed certain of the financial covenants and other terms in the revolving credit facility to those contained in the term loan credit agreement. The existing senior secured revolving credit facility matures on January 3, 2013.
 
During 2008, the Company has experienced adverse financial conditions primarily attributable with historically high crude oil costs and the impact of the Shreveport refinery expansion project cost overruns and the delay in the startup of the expansion project. Compliance with the financial covenants pursuant to the Company’s credit agreements is tested quarterly based upon performance over the most recent four fiscal quarters, and as of December 31, 2008, it was in compliance with all financial covenants under its credit agreements. The Company’s ability to maintain compliance with these financial covenants in the quarter ended December 31, 2008 was substantially enhanced by the significant increase in specialty products segment gross profit during the third and fourth quarters resulting from increased selling prices for specialty products in the third quarter and reductions in the cost of crude oil throughout the third and fourth quarters. The Company is continuing to take steps to ensure that it meets the requirements of its credit agreements and currently forecasts that it will be in compliance on future measurement dates. These steps have included increasing specialty products sales prices, increasing crude oil price hedging for the specialty products segment and reducing working capital.
 
While assurances cannot be made regarding its future compliance with the financial covenants in its credit agreements and being cognizant of the general uncertain economic environment, the Company anticipates that its strategic initiatives listed above will allow it to maintain compliance with such financial covenants and to continue to improve its Adjusted EBITDA, liquidity and distributable cash flow.
 
Failure to achieve the Company’s anticipated results may result in a breach of certain of the financial covenants contained in its credit agreements. If this occurs, the Company will enter into discussions with its lenders to either modify the terms of the existing credit facilities or obtain waivers of non-compliance with such covenants. There can be no assurances of the timing of the receipt of any such modification or waiver, the term or costs associated therewith or our ultimate ability to obtain the relief sought. The Company’s failure to obtain a waiver of non-compliance with certain of the financial covenants or otherwise amend the credit facilities would constitute an event of default under its credit facilities and would permit the lenders to pursue remedies. These remedies could include acceleration of maturity under the credit facilities and limitations or the elimination of the Company’s ability to make distributions to its unitholders. If the Company’s lenders accelerate maturity under its credit facilities, a significant portion of its indebtedness may become due and payable immediately. The Company might not have, or be able to obtain, sufficient funds to make these accelerated payments. If the Company is unable to make these accelerated payments, its lenders could seek to foreclose on its assets.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
As of December 31, 2008, maturities of the Company’s long-term debt is as follows:
 
         
Year
  Maturity  
 
2009
  $ 4,811  
2010
    4,594  
2011
    4,460  
2012
    4,175  
2013
    106,389  
Thereafter
    355,835  
         
Total
  $ 480,264  
         
 
In 2007, the Company entered into a capital lease for catalyst which will expire in 2012. Assets recorded under this capital lease obligation are included in property, plant and equipment consists of $3,736 as of December 31, 2008. As of December 31, 2008, the Company had recorded $669 in amortization for capital lease assets. The assets were placed in service in 2008.
 
As of December 31, 2008, the Company had estimated minimum commitments for the payment of rentals under capital leases as follows:
 
         
    Capital
 
Year
  Leases  
 
2009
  $ 1,133  
2010
    845  
2011
    660  
2012
    330  
2013
     
         
Total minimum lease payments
    2,968  
Less amount representing interest
    328  
         
Capital lease obligation
    2,640  
Less obligations due within one year
    961  
         
Long-term capital lease obligation
  $ 1,679  
         
 
9.   Derivatives
 
The Company had the following derivative instruments outstanding as of December 31, 2008.
 
Crude Oil Collar and Swap Contracts — Specialty Products Segment
 
The Company utilizes combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty products segment. The Company’s policy is generally to enter into crude oil derivative contracts that match its expected future cash out flows for up to 70% of its anticipated crude oil purchases related to its specialty products production. At December 31, 2008, the Company had approximately 7,700 barrels per day of crude oil hedges expiring in January 2009 through March 2009 and the Company is at the lower end of its targeted volume range of hedges for the specialty products segment. These positions generally will be short term in nature and expire within three to nine months from execution; however, the Company may execute derivative contracts for up to two years forward if its expected future cash flows support lengthening its position.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
At December 31, 2008, the Company had the following four-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $2,067 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.
 
                                                 
                Average
    Average
    Average
    Average
 
Crude Oil Put/Call Spread
              Lower Put
    Upper Put
    Lower Call
    Upper Call
 
Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)     ($/Bbl)     ($/Bbl)     ($/Bbl)  
 
January 2009
    217,000       7,000     $ 50.32     $ 60.32     $ 70.32     $ 80.32  
February 2009
    84,000       3,000       38.33       48.33       58.33       68.33  
                                                 
Totals
    301,000                                          
Average price
                  $ 46.98     $ 56.98     $ 66.98     $ 76.98  
 
At December 31, 2008, the Company had the following two-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $10,277 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.
 
                                 
                Average
    Average
 
                Sold Put
    Bought Call
 
Crude Oil Put/Call Spread Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)     ($/Bbl)  
 
January 2009
    186,000       6,000     $ 68.57     $ 90.83  
February 2009
    112,000       4,000       74.85       96.25  
March 2009
    93,000       3,000       79.37       101.67  
                                 
Totals
    391,000                          
Average price
                  $ 72.94     $ 94.96  
 
Crude Oil Swap Contracts— Fuel Products Segment
 
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 purchases used in fuels production. At December 31, 2008, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as hedges
 
                         
    Barrels
             
Crude Oil Swap Contracts by Expiration Dates
  Purchased     BPD     ($/Bbl)  
 
First Quarter 2009
    2,025,000       22,500     $ 66.26  
Second Quarter 2009
    2,047,500       22,500       66.26  
Third Quarter 2009
    2,070,000       22,500       66.26  
Fourth Quarter 2009
    2,070,000       22,500       66.26  
Calendar Year 2010
    7,300,000       20,000       67.29  
Calendar Year 2011
    3,009,000       8,244       76.98  
                         
Totals
    18,521,500                  
Average price
                  $ 68.41  


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
At December 31, 2008, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $14,278 of unrealized gains in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.
 
                         
Crude Oil Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    450,000       5,000     $ 62.66  
Second Quarter 2009
    455,000       5,000       62.66  
Third Quarter 2009
    460,000       5,000       62.66  
Fourth Quarter 2009
    460,000       5,000       62.66  
                         
Totals
    1,825,000                  
Average price
                  $ 62.66  
 
Fuels Product Swap Contracts
 
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 and gasoline swap contracts for a period no greater than five years forward and for no more than 75% of forecasted fuels sales.
 
Diesel Swap Contracts
 
At December 31, 2008, 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.
 
                         
Diesel Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    1,170,000       13,000     $ 80.51  
Second Quarter 2009
    1,183,000       13,000       80.51  
Third Quarter 2009
    1,196,000       13,000       80.51  
Fourth Quarter 2009
    1,196,000       13,000       80.51  
Calendar Year 2010
    4,745,000       13,000       80.41  
Calendar Year 2011
    2,371,000       6,496       90.58  
                         
Totals
    11,861,000                  
Average price
                  $ 82.48  
 
Gasoline Swap Contracts
 
At December 31, 2008, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as hedges.
 
                         
Gasoline Swap Contracts by Expiration Dates
  Barrels Sold     BPD     ($/Bbl)  
 
First Quarter 2009
    855,000       9,500     $ 73.83  
Second Quarter 2009
    864,500       9,500       73.83  
Third Quarter 2009
    874,000       9,500       73.83  
Fourth Quarter 2009
    874,000       9,500       73.83  
Calendar Year 2010
    2,555,000       7,000       75.28  
Calendar Year 2011
    638,000       1,748       83.42  
                         
Totals
    6,660,500                  
Average price
                  $ 75.30  


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
At December 31, 2008, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $15,851 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.
 
                         
    Barrels
             
Gasoline Swap Contracts by Expiration Dates
  Purchased     BPD     ($/Bbl)  
 
First Quarter 2009
    450,000       5,000     $ 60.53  
Second Quarter 2009
    455,000       5,000       60.53  
Third Quarter 2009
    460,000       5,000       60.53  
Fourth Quarter 2009
    460,000       5,000       60.53  
                         
Totals
    1,825,000                  
Average price
                  $ 60.53  
 
Natural Gas Swap Contracts
 
The Company utilizes swap contracts to manage natural gas price risk and volatility of cash flows. Certain of these swap contracts are designated as cash flow hedges of the future purchase of natural gas. The Company’s policy is generally to enter into natural gas derivative contracts to hedge approximately 50% or more of its upcoming fall and winter months’ anticipated natural gas requirement for a period no greater than three years forward. At December 31, 2008, the Company had the following derivatives related to natural gas purchases, of which 90,000 MMBtus are designated as hedges. As a result of a portion of these derivative instruments not being designated as hedges, the Company recognized $1,223 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.
 
                 
Natural Gas Swap Contracts by Expiration Dates
  MMBtus     $/MMBtu  
 
First Quarter 2009
    330,000     $ 10.38  
                 
Totals
    330,000          
Average price
          $ 10.38  
 
Interest Rate Swap Contracts
 
In 2008, the Company entered into a forward swap contract to manage interest rate risk related to its current variable rate senior secured first lien term loan which closed January 3, 2008. The Company has hedged the future interest payments related to $150,000 and $50,000 of the total outstanding term loan indebtedness in 2009 and 2010, respectively, pursuant to this forward swap contract.
 
This swap contract is designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at 3.09% and 3.66% per annum in 2009 and 2010, respectively.
 
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 the 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 gain (loss) on derivative instruments in the consolidated statements of operations as of December 31, 2008. For the year ended December 31, 2008, the Company recorded $2,188 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008. 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 which is not designated as a cash flow hedge.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
10.   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 value 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 consolidated financial statements at fair value in accordance with SFAS No. 157, Fair Value Measurements. The fair value of our long-term debt was $305,084 at December 31, 2008. The fair value of long-term debt materially approximated the carrying value at December 31, 2007. In addition, based upon fees charged for similar agreements, the face values of outstanding standby letters of credit approximated their fair value at December 31, 2008 and 2007.
 
11.   Fair Value Measurements
 
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. The Company has adopted the provisions of SFAS 157 as of January 1 2008, for financial instruments. In February 2008, the FASB agreed to defer for one year the effective date of SFAS 157 for certain nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.
 
SFAS 157 establishes 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, as required by SFAS No. 157, 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 December 31, 2008, the Company held certain assets 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, natural gas 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 single A or better. The fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, natural gas 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 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


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
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 December 31, 2008, the Company’s asset was reduced by approximately $6,186 and its liability was reduced by $564. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for gasoline 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 consist of mutual funds that are publicly traded and for which market prices are readily available, thus these investments are categorized as Level 1.
 
The Company’s assets measured at fair value on a recurring basis subject to the disclosure requirements of SFAS 157 at December 31, 2008 were as follows:
 
                                 
    Fair Value Measurements  
    Level 1     Level 2     Level 3     Total  
 
Assets:
                               
Crude oil swaps
  $     $      —     $     $  
Gasoline swaps
                103,780       103,780  
Diesel swaps
                90,337       90,337  
Natural gas swaps
                       
Crude oil options
                       
Pension plan investments
    12,018                   12,018  
                                 
Total assets at fair value
  $ 12,018     $     $ 194,117     $ 206,135  
                                 
Liabilities:
                               
Crude oil swaps
  $     $     $ (119,202 )   $ (119,202 )
Gasoline swaps
                       
Diesel swaps
                       
Natural gas swaps
                (1,429 )     (1,429 )
Crude oil options
                (12,345 )     (12,345 )
Interest rate swaps
                (5,769 )     (5,769 )
Pension plan investments
                       
                                 
Total liabilities at fair value
  $     $     $ (138,745 )   $ (138,745 )
                                 


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
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 year ended December 31, 2008:
 
         
    Derivative
 
    Instruments, Net  
 
Fair value at January 1, 2008
  $ (600,051 )
Realized losses
    58,833  
Unrealized gains (losses)
    17,141  
Comprehensive income (loss)
    58,610  
Purchases, issuances and settlements
    (21,709 )
Transfers in (out) of Level 3
    542,548  
         
Fair value at December 31, 2008
  $ 55,372  
         
Total gains or losses included in net income attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of December 31, 2008
  $ 3,454  
         
 
All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges as defined in SFAS 133, are included in sales for gasoline and diesel derivatives, cost of sales for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in the consolidated financial statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments, as defined in SFAS 133, are recorded in earnings immediately in unrealized gain (loss) on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments. See Note 9 for further information on SFAS 133 and hedging.
 
12.   Unit-Based Compensation
 
The Company’s general partner adopted a Long-Term Incentive Plan (the “Plan”) on January 24, 2006, amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by the compensation committee of the Company’s general partner’s board of directors.
 
On December 28, 2007 and December 30, 2008, non-employee directors of our general partner were granted phantom units under the terms of the Plan as part of their director compensation package related to fiscal years 2007 and 2008, respectively. These phantom units have a four year service period, beginning on January 1, with one quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant. The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and selling, general and administrative expense in the consolidated statements of operations using the straight-line method over the four year vesting period, as it expects these units to fully vest.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
A summary of the Company’s nonvested units as of December 31, 2008, and the changes during the year ended December 31, 2008 is presented below:
 
                 
          Weighted-Average
 
          Grant Date
 
Nonvested Phantom Units
  Grant     Fair Value  
 
Nonvested at January 1, 2008
    8,508     $ 35.56  
Granted
    30,192       7.79  
Vested
    (10,992 )     16.38  
Forfeited
           
                 
Nonvested at December 31, 2008
    27,708     $ 12.91  
                 
 
For the year ended December 31, 2008, compensation expense of $179 was recognized in the consolidated statements of operations related to vested unit grants. As of December 31, 2008, there was a total of $358 of unrecognized compensation costs related to nonvested unit grants. These costs are expected to be recognized over a weighted-average period of three years. The total fair value of phantom units vested during the year ended December 31, 2008 was $86.
 
13.   Employee Benefit Plan
 
The Company has a defined contribution plan administered by its general partner. All full-time employees who have completed at least one hour of service are eligible to participate in the plan. Participants are allowed to contribute 0% to 100% of their pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% contribution by the participant up to 4% and 50% of each additional 1% contribution up to 6% for a maximum contribution by the Company of 5% per participant. The Company’s matching contribution was $1,782 for the year ended December 31, 2008. The plan also includes a profit-sharing component. Contributions under the profit-sharing component are determined by the board of directors of the Company’s general partner and are discretionary. The Company’s profit sharing contribution was $1,123 for the year ended December 31, 2008.
 
The Company has a noncontributory defined benefit plan (“Pension Plan”) for both those salaried employees as well as those employees represented by either the United Steelworkers (“USW”) or the International Union of Operating Engineers (“IUOE”) who were formerly employees of Penreco and who became employees of the Company as a result of the Penreco acquisition on January 3, 2008. The Company also has a contributory defined benefit postretirement medical plan for both those salaried employees as well as those employees represented by either the International Brotherhood of Teamsters (“IBT”), USW or IUOE who were formerly employees of Penreco and who became employees of the Company as a result of the Penreco acquisition, as well as a non-contributory disability plan for those salaried employees who were formerly employees of Penreco (collectively, “Other Plans”). The pension benefits are based primarily on years of service for USW and IUOE represented employees and both years of service and the employee’s final 60 months’ average compensation for salaried employees. The funding policy is consistent with funding requirements of applicable laws and regulations. The assets of these plans consist of corporate equity securities, municipal and government bonds, and cash equivalents. Effective January 31, 2009, the Company has amended the Pension Plan. The amendment removes the salaried employee from accumulating additional benefits subsequent to January 31, 2009. All information presented below has been adjusted for this curtailment, which resulted in a reduction in the Company’s benefit obligation of $2,311.


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
The components of net periodic pension and other post retirement benefits cost for the year ended December 31, 2008 were as follows:
 
                 
    Year Ended
 
    December 31, 2008  
          Other Post
 
    Pension
    Retirement
 
    Benefits     Employee Benefits  
 
Service cost
  $ 945     $ 9  
Interest cost
    1,298       51  
Expected return on assets
    (1,341 )      
                 
Net periodic pension cost
  $ 902     $ 60  
                 
 
During the year ended December 31, 2008, the Company made contributions of $193 and $63 to its Pension Plan and Other Plans, respectively and expects to make no contributions in 2009.
 
The benefit obligations, plan assets, funded status, and amounts recognized in the consolidated balance sheets were as follows:
 
                 
          Other Post
 
    Pension
    Retirement
 
    Benefits     Employee Benefits  
 
Change in projected benefit obligation (“PBO”):
               
Benefit obligation at January 3, 2008
  $ 20,097     $ 872  
Service cost
    945       9  
Interest cost
    1,298       51  
Curtailment
    (2,311 )      
Benefits paid
    (630 )     (141 )
Actuarial (gain) loss
    1,613       (30 )
Administrative expense
    (116 )      
Employee contributions
          78  
                 
Benefit obligation at December 31, 2008
  $ 20,896     $ 839  
                 
Change in plan assets:
               
Fair value of plan assets at January 3, 2008
  $ 18,183     $  
Benefit payments
    (630 )     (141 )
Actual return on assets
    (5,612 )      
Administrative expense
    (116 )      
Employee contributions
          78  
Employer contribution
    193       63  
                 
Fair value of plan assets at December 31, 2008
  $ 12,018     $  
                 
Funded status — benefit obligation in excess of plan assets
  $ (8,878 )   $ (839 )
Curtailment
    (2,311 )      
Unrecognized net actuarial loss
    1,613       (30 )
Unexpected loss on plan assets
    6,952        
                 
Net amount recognized at December 31, 2008
  $ (2,624 )   $ (869 )
                 
Amounts recognized in the consolidated balance sheets consisted of:
               
Accrued benefit obligation
  $ (8,878 )   $ (839 )
Accumulated other comprehensive loss
    6,254       (30 )
                 
Net amount recognized at December 31, 2008
  $ (2,624 )   $ (869 )
                 


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
The accumulated benefit obligation for the Pension Plan was $20,896 as of December 31, 2008. The accumulated benefit obligation is equal to the projected benefit obligation due to the curtailment that occurred in 2008. The accumulated benefit obligation for the Pension Plan was less than plan assets by $8,878 as of December 31, 2008. As of December 31, 2008, the Company had no prior service costs or transition gains (losses) but recorded actuarial losses of $6,224 in accumulated other comprehensive income (loss) in the consolidated balance sheets.
 
The effective portion of the minimum pension liability classified in accumulated other comprehensive loss is $6,224 as of December 31, 2008. In 2009, the Company expects to recognize $419 and $0, respectively, of loss from accumulated other comprehensive loss for the Company’s Pension Plan and Other Postretirement Benefits Plan.
 
The significant weighted average assumptions used for the year ended December 31, 2008 were as follows:
 
                 
    Pension
    Other Post Retirement
 
    Benefits     Employee Benefits  
 
Discount rate for benefit obligations
    6.18 %     6.20 %
Discount rate for net periodic benefit costs
    6.58 %     6.20 %
Expected return on plan assets for net periodic benefit costs
    7.50 %     0.00 %
Rate of compensation increase for benefit obligations
    4.50 %     0.00 %
Rate of compensation increase for net periodic benefit costs
    4.50 %     0.00 %
 
For measurement purposes, a 8.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2009. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.5% for 2029 and remain at that level thereafter. An increase or decrease by one percentage point in the assumed healthcare cost trend rates would not have a material effect on the benefit obligation and service and interest cost components of benefit costs for the Other Plans as of January 3, 2008. The Company considered the historical returns and the future expectation for returns for each asset class, as well as the target asset allocation of the Pension Plan portfolio, to develop the expected long-term rate of return on plan assets.
 
The Company’s Pension Plan and Other Plans asset allocations, as of December 31, 2008 by asset category, are as follows:
 
                 
          Other Post
 
          Retirement
 
    Pension
    Employee
 
    Benefits     Benefits  
 
Cash
    2 %     0 %
U.S. equities
    77 %     0 %
Foreign equities
    4 %     0 %
Fixed income
    17 %     0 %
                 
      100 %     0 %
                 
 
Investment Policy
 
The investment objective of the Penreco Pension Plan Trust (the “Trust”) is to generate a long-term rate of return which will fund the related pension liabilities and minimize the Company’s contributions to the Trust. Trust assets are to be invested with an emphasis on providing a high level of current income through fixed income investments and longer-term capital appreciation through equity investments. Trust assets are targeted to achieve an investment return of 7.50% or more compounded annually over any 5-year period. Due to the long-term nature of pension liabilities, the Trust will assume moderate risk only to the extent necessary to achieve its return objective.
 
The Trust pursues its investment objectives by investing in a customized profile of asset allocation which corresponds to the investment return target. Full discretion in portfolio investment decisions is given to Wells Fargo & Company or its affiliates (“the Manager”), subject to the investment policy guidelines. The Manager is


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
required to utilize fiduciary care in all investment decisions and is expected to minimize all costs and expenses involved with the managing of these assets.
 
With consideration given to the long-term goals of the Trust, the following ranges reflect the long-term strategy for achieving the stated objectives:
 
                 
    Range of
       
Asset Class
  Asset Allocations     Target Allocation  
 
Cash
    0 — 5 %     Minimal  
Fixed income
    20 — 50 %     35 %
Equities
    50 — 80 %     65 %
 
Trust assets will be invested in accordance with the prudent expert standard as mandated by ERISA. In the event market environments create asset exposures outside of the policy guidelines, reallocations will be made in an orderly manner.
 
Fixed Income Guidelines
 
U.S. Treasury, agency securities, and corporate bond issues rated “investment grade” or higher are considered appropriate for this portfolio. Written approval will be obtained to hold securities downgraded below “investment grade” by either Moody’s or Standard & Poor’s. Money market and fixed-income funds that are consistent with the stated investment objective of the Trust are also considered acceptable.
 
Excluding U.S. Treasury and agency obligations, money market or fixed-income mutual funds, no single issuer shall exceed more than 10% of the total portfolio market value. The average maturity range shall be consistent with the objective of providing a high level of current income and long-term growth within the acceptable risk level established for the Trust.
 
Equity Guidelines
 
Any equity security that is on the Manager’s working list is considered appropriate for this portfolio. Equity mutual funds that are consistent with the stated investment objective of the Trust are also considered acceptable. No individual equity position, with the exception of equity mutual funds, should exceed 10% of the total market value of the Trust’s assets.
 
Performance of investment results will be reviewed, at least semiannually, by the Calumet Retirement Savings Committee (“CRSC”) and annually at a joint meeting between the CRSC and the Manager. Written communication regarding investment performance occurs quarterly. Any major changes in the Manager’s investment strategy will be communicated to the Chairman of the CRSC on an ongoing basis and as frequently as necessary. The Manager shall be informed of special situations affecting Trust investments including substantial withdrawal or funding pattern changes and changes in investment policy guidelines and objectives.
 
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2008:
                 
    Pension
    Other Post Retirement
 
    Benefits     Employee Benefits  
 
2009
  $ 773     $ 98  
2010
    820       75  
2011
    870       82  
2012
    949       101  
2013
    1,041       79  
2014 to 2018
    6,527       342  
                 
Total
  $ 10,980     $ 777  
                 


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CALUMET GP, LLC
 
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
(in thousands, except operating, unit and per unit data)
 
14.   Transactions with Related Parties
 
During the year ended December 31, 2008 the Company had sales to related parties owned by a limited partner of $7,973. Trade accounts and other receivables from related parties at December 31, 2008 were $1,828. The Company also had purchases from related parties owned by a limited partner, excluding crude purchases related to the Legacy agreement discussed below, during the year ended December 31, 2008, of $615. Accounts payable to related parties, excluding accounts payable related to Legacy agreement discussed below, at December 31, 2008 were $774.
 
In May 2008, the Company began purchasing all of its crude oil requirements for its Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources Co., L.P. (“Legacy”). Legacy is owned in part by one of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and president, F. William Grube, and Jennifer G. Straumins, the Company’s senior vice president. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company is approximately 6,000 barrels per day. During the year ended December 31, 2008, the Company had crude oil purchases of $140,180 from Legacy. Accounts payable to Legacy at December 31, 2008 related to this agreement were $6,395.
 
During 2006 and prior, the Company had placed a portion of its insurance underwriting requirements, including general liability, automobile liability, excess liability, workers’ compensation as well as directors’ and officers’ liability with a commercial insurance brokerage business. A member of the board of directors of our general partner serves as an executive of this commercial insurance brokerage company. The total premiums paid to this company by Calumet for the years ended December 31, 2008, were $634. With the exception of its directors’ and officers’ liability insurance which were placed with this commercial insurance brokerage company, the Company placed its insurance requirements with third parties during the years ended December 31, 2008.
 
15.   Subsequent Events
 
On January 22, 2009, the Company declared a quarterly cash distribution of $0.45 per unit on all outstanding units, or $14,800, for the quarter ended December 31, 2008. The distribution was paid on February 13, 2009 to unitholders of record as of the close of business on February 3, 2009. This quarterly distribution of $0.45 per unit equates to $1.80 per unit, or $59,202 on an annualized basis.
 
On January 26, 2009, the Company entered into a crude oil supply agreement with Legacy Resources Co., L.P. (“Legacy”) an affiliate of the Company’s general partner. Under the agreement, it is contemplated that Legacy will supply the Company’s Shreveport refinery with a portion of its crude oil requirements that are received via common carrier pipeline. Pricing for the crude oil purchased under each confirmation will be mutually agreed to by the parties and set forth in such confirmation and will include a market-based premium as determined and agreed to by the parties. The agreement is effective as of January 26, 2009 and will continue to be in effect until terminated by either party by written notice. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company under this Agreement is up to 15,000 barrels per day. Legacy is owned in part by The Heritage Group, an affiliate of the Company’s general partner, in part by the Company’s general partner’s chief executive officer and president, F. William Grube, and in part by the Company’s general partner’s senior vice president, Jennifer G. Straumins.


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Item 9.   Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
 
None.
 
Item 9A.   Controls and Procedures
 
Management’s Report on Internal Control Over Financial Reporting
 
The management of Calumet Specialty Products Partners, L.P. (the Company) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with US generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with US generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
 
Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Calumet Penreco, LLC, which is included in its 2008 consolidated financial statements and constituted $266,270,000 of total assets as of December 31, 2008 and $460,778,000 of revenues for the year then ended. Management also did not perform an evaluation of the internal control over financial reporting of Calumet Penreco, LLC.
 
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, based on criteria for effective internal control over financial reporting described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, we have concluded that internal control over financial reporting is effective as of December 31, 2008.
 
Ernst & Young LLP, an independent registered public accounting firm, has audited the Company’s consolidated financial statements and has issued an attestation report on the effectiveness of internal control over financial reporting which appears on the following page.
 
/s/  F. William Grube
F. William Grube
President, Chief Executive Officer and Director of
Calumet GP, LLC
 
February 27, 2009
 
/s/  R. Patrick Murray, II
R. Patrick Murray, II
Vice President, Chief Financial Officer and
Secretary of Calumet GP, LLC
 
February 27, 2009


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors of Calumet GP, LLC
General Partner of Calumet Specialty Products Partners, L.P.
 
We have audited Calumet Specialty Product Partners L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Calumet Specialty Product Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
 
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Calumet Penreco, LLC, which is included in the 2008 consolidated financial statements of Calumet Specialty Products Partners, L.P. and constituted $266,270,000 of total assets as of December 31, 2008 and $460,778,000 of revenues for the year then ended. Our audit of internal control over financial reporting of Calumet Specialty Products Partners, L.P. also did not include an evaluation of the internal control over financial reporting of Calumet Penreco, LLC.
 
In our opinion, Calumet Specialty Products Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Calumet Specialty Products Partners, L.P. as of December 31, 2008 and 2007 and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2008 of Calumet Specialty Products Partners, L.P. and our report dated February 27, 2009 expressed an unqualified opinion thereon.
 
/s/  Ernst & Young LLP
 
Indianapolis, Indiana
February 27, 2009
 
Item 9B.   Other Information
 
None.


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PART III
 
Item 10.   Directors, Executive Officers of Our General Partner and Corporate Governance
 
Management of Calumet Specialty Products Partners, L.P. and Director Independence
 
Our general partner, Calumet GP, LLC, manages our operations and activities. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to our unitholders, as limited by the various provisions of our partnership agreement modifying and restricting the fiduciary duties that might otherwise be owed by our general partner to our unitholders.
 
The directors of our general partner oversee our operations. The owners of our general partner have appointed seven members to our general partner’s board of directors. The directors of our general partner are generally elected by a majority vote of the owners of our general partner on an annual basis. However, as long as our chief executive officer and president, F. William Grube, or trusts established for the benefit of his family members, continue to own at least 30% of the membership interests in our general partner, Mr. Grube (or in certain specified instances, his designee or transferee) has the right to serve as a director of our general partner. The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified.
 
Pursuant to Section 4360 of the NASDAQ Stock Market (“NASDAQ”) Marketplace Rules, NASDAQ does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. However, three of our general partner’s seven directors are “independent” as that term is defined in the applicable NASDAQ rules and Rule 10A-3 of the Exchange Act. In determining the independence of each director, our general partner has adopted standards that incorporate the NASDAQ and Exchange Act standards. Our general partner’s independent directors as determined in accordance with those standards are: James S. Carter, Robert E. Funk and Michael L. Smith.
 
The officers of our general partner manage the day-to-day affairs of our business. Officers serve at the discretion of the board of directors.
 
Directors and Executive Officers
 
The following table shows information regarding the directors and executive officers of Calumet GP, LLC as of February 26, 2009. Directors are elected for one-year terms.
 
             
Name
 
Age
 
Position with Calumet GP, LLC
 
Fred M. Fehsenfeld, Jr. 
    58     Chairman of the Board
F. William Grube
    61     Chief Executive Officer, President and Director
Allan A. Moyes, III
    62     Executive Vice President
Jennifer G. Straumins
    35     Senior Vice President
R. Patrick Murray, II
    37     Vice President, Chief Financial Officer and Secretary
Robert M. Mills
    55     Vice President — Crude Oil Supply
Jeffrey D. Smith
    46     Vice President — Planning and Economics
William A. Anderson
    40     Vice President — Sales and Marketing
James S. Carter
    60     Director
William S. Fehsenfeld
    58     Director
Robert E. Funk
    63     Director
Nicholas J. Rutigliano
    61     Director
Michael L. Smith
    60     Director
 
Fred M. Fehsenfeld, Jr. has served as the chairman of the board of directors of our general partner since September 2005. Mr. Fehsenfeld also served as the vice chairman of the board of directors of Calumet Lubricants


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Co., L.P. since 1990. Mr. Fehsenfeld has worked for The Heritage Group in various capacities since 1977 and has served as its managing trustee since 1980. Mr. Fehsenfeld received his B.S. in Mechanical Engineering from Duke University and his M.S. in Management from the Massachusetts Institute of Technology Sloan School.
 
F. William Grube has served as the chief executive officer, president and director of our general partner since September 2005. Mr. Grube has also served as president and chief executive officer of Calumet Lubricants Co., L.P. since 1990. From 1973 to 1989, Mr. Grube served as executive vice president of the Rock Island Refinery. Mr. Grube received his B.S. in Chemical Engineering from Rose-Hulman Institute of Technology and his M.B.A. from Harvard University. Mr. Grube is the father of Jennifer G. Straumins, Senior Vice President of our general partner.
 
Allan A. Moyes, III has served as executive vice president of our general partner since September 2005. Mr. Moyes has also served as executive vice president of Calumet Lubricants Co., L.P. since 1997. From 1994 to 1997, Mr. Moyes served as manager of planning and economics for Calumet Lubricants Co., L.P. From 1989 to 1994, Mr. Moyes worked for Marathon Oil Company as the technical service manager at its Indianapolis refinery. From 1978 to 1989, Mr. Moyes worked in various capacities at the Rock Island Refinery. Mr. Moyes received his Computer Science degree at Memphis State Technical University.
 
Jennifer G. Straumins has served as senior vice president of our general partner since February 2007. From January 2006 through February 2007, Ms. Straumins served as vice president — investor relations. Ms. Straumins served in various capacities in financial planning and economics for Calumet Lubricants Co., L.P. from 2002 through 2006. Prior to joining Calumet Lubricants Co., L.P., Ms. Straumins held financial planning positions with Great Lakes Chemical Company and Exxon Chemical Company. Ms. Straumins received a B.E. in Chemical Engineering from Vanderbilt University and her M.B.A. from the University of Kansas. Ms. Straumins is the daughter of F. William Grube, the chief executive officer and president of our general partner.
 
R. Patrick Murray, II has served as vice president, chief financial officer and secretary of our general partner since September 2005. Mr. Murray has also served as the vice president and chief financial officer of Calumet Lubricants Co., L.P. since 1999 and from 1998 to 1999 served as its controller. From 1993 to 1998, Mr. Murray was a senior auditor with Arthur Andersen LLP. Mr. Murray received his B.B.A. in Accountancy from the University of Notre Dame.
 
Robert M. Mills has served as vice president — crude oil supply of our general partner since September 2005. Mr. Mills has also served as the vice president — crude oil supply of Calumet Lubricants Co., L.P. since 1995 and from 1993 to 1995 served as manager of supply and distribution. Mr. Mills received his B.S. in Business Administration from Louisiana State University.
 
Jeffrey D. Smith has served as vice president — planning and economics of our general partner since September 2005. He has also served as the vice president — planning and economics of Calumet Lubricants Co., L.P. since 2002. Mr. Smith joined Calumet Lubricants Co., L.P. in 1994 and served in various capacities prior to becoming vice president. Mr. Smith received his B.S. in Geology from Louisiana Tech University.
 
William A. Anderson has served as vice president — sales and marketing of our general partner since September 2005. Mr. Anderson has also served as the vice president — sales and marketing of Calumet Lubricants Co., L.P. since 2000 and served in various other capacities for Calumet Lubricants Co., L.P. from 1993 to 2000. Mr. Anderson received his B.A. in Communications from DePauw University.
 
James S. Carter has served as a member of the board of directors of our general partner since January 2006. Mr. Carter served as U.S. regional director of Exxon Mobil Fuels Company, the fuels subsidiary of Exxon Mobil Corporation, from 1999 until his retirement in 2003. Mr. Carter received his M.B.A. in Finance and Accounting from Tulane University.
 
William S. Fehsenfeld has served as a member of the board of directors of our general partner since January 2006. Mr. Fehsenfeld is chairman of the board and has served as an officer of Schuler Books, Inc., the independent bookstore company he founded with his wife, since 1982. He has also served as a trustee of The Heritage Group from 2003 to the present. Mr. Fehsenfeld received his B.G.S. from the University of Michigan and


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his M.B.A. from Grand Valley State University. He is also a first cousin of the chairman of the board of directors of our general partner, Mr. Fred M. Fehsenfeld, Jr.
 
Robert E. Funk has served as a member of the board of directors of our general partner since January 2006. Mr. Funk previously served as vice president-corporate planning and economics of Citgo Petroleum Corporation, a refiner and marketer of transportation fuels, lubricants, petrochemicals, refined waxes, asphalt and other industrial products, from 1997 until his retirement in December 2004. Mr. Funk previously served Citgo or its predecessor, Cities Services Company, as general manager-facilities planning from 1988 to 1997, general manager-lubricants operations from 1983 to 1988 and manager-refinery east, Lake Charles refinery from 1982 to 1983. Mr. Funk received his B.S. in Chemical Engineering from the University of Kansas.
 
Nicholas J. Rutigliano has served as a member of the board of directors of our general partner since January 2006. Mr. Rutigliano has served as president of Tobias Insurance Group, Inc., a commercial insurance brokerage business he founded, since 1973. He has also served as a trustee of The Heritage Group from 1980 to the present and as a trustee of the University of Evansville. Mr. Rutigliano received his B.S. in Business from the University of Evansville. He is also the brother-in-law of the chairman of the board of directors of our general partner, Mr. Fred M. Fehsenfeld, Jr.
 
Michael L. Smith has served as a member of the board of directors of our general partner since January 2006. Mr. Smith is the chairman of the audit committee of our board of directors and previously served as executive vice president and chief financial officer of Wellpoint Inc. (f/k/a Anthem Inc.), a publicly traded health benefits company, from 1999 until his retirement in January 2005. Mr. Smith previously served as senior vice president of Anthem and chief financial officer of Anthem Blue Cross and Blue Shield’s Midwest and Connecticut operations from 1998 to 1999. From 1996 to 1998, he was chief operating officer and chief financial officer of American Health Network, a former Anthem subsidiary. Mr. Smith is a member of the board of directors of Kite Realty Group Trust, Vectren Corporation, hhgregg, Inc. and Emergency Medical Services Corporation. He also serves on the Board of Trustees of DePauw University, the board of directors of the Lumina Foundation for Education and is a member of the Indiana Commission for Higher Education. Mr. Smith received his B.A. in Economics from DePauw University.
 
Board of Directors Committees
 
Conflicts Committee
 
Two members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by NASDAQ and the Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The two independent board members who serve on the conflicts committee are Messrs. James S. Carter and Robert E. Funk. Mr. Carter serves as the chairman of the conflicts committee.
 
Compensation Committee
 
The board of directors of our general partner also has a compensation committee which, among other responsibilities, oversees the compensation plans awarded to directors and officers described in Item 11 “Executive and Director Compensation.” NASDAQ does not require a limited partnership like us to have a compensation committee comprised entirely of independent directors. Accordingly, Messrs. Fred M. Fehsenfeld, Jr. and F. William Grube serve as members of our compensation committee. Mr. Fehsenfeld serves as the chairman of the compensation committee.
 
The board of directors has adopted a written charter for the compensation committee which defines the scope of the committee’s authority. The committee may form and delegate some or all of its authority to subcommittees comprised of committee members when it deems appropriate. The committee is responsible for reviewing and recommending to the board of directors for its approval the annual salary and other compensation components for the chief executive officer. The committee reviews and makes recommendations to the board of directors for its


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approval any of the Partnership’s equity compensation-based plans, including the Long-Term Incentive Plan, or any cash bonus or incentive compensation plans or programs. Also, the committee reviews and approves all annual salary and other compensation arrangements and components for the senior executives of the Partnership. Further, the compensation committee periodically reviews and makes a recommendation to the board of directors for changes in the compensation of all directors. The committee has the authority to retain and terminate any compensation consultant to assist it in the evaluation of director and senior executive compensation and to obtain independent advice and assistance from internal and external legal, accounting and other advisors.
 
See Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Peer Group and Compensation Targets” for additional discussion regarding the results of this executive compensation review.
 
Audit Committee
 
The board of directors of our general partner has an audit committee comprised of three directors, Messrs. James S. Carter, Robert E. Funk and Michael L. Smith, each of whom the board of directors of our general partner has determined meets the independence and experience standards established by NASDAQ and the SEC. In addition, the board of directors of our general partner has determined that a Mr. Smith is an “audit committee financial expert” (as defined by the SEC). Mr. Smith serves as the chairman of the audit committee.
 
The board of directors has adopted a written charter for the audit committee. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof and pre-approves any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee.
 
Code of Ethics
 
We have adopted a Code of Business Conduct and Ethics that applies to all officers, directors and employees.
 
Available on our website at www.calumetspecialty.com are copies of our committee charters and Code of Business Conduct and Ethics, all of which also will be provided to unitholders without charge upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, IN 46214.
 
Section 16(a) Beneficial Ownership Reporting Compliance
 
Section 16(a) of the Securities and Exchange Act of 1934 (the “Exchange Act”) requires directors and officers of our general partner and persons who beneficially own more than ten percent of our common units to file with the SEC and NASDAQ initial reports of ownership and reports of changes in ownership of such securities. SEC regulations require officers and directors of our general partner and greater than ten percent beneficial owners to furnish us with copies of all Section 16(a) forms they file.
 
Based solely on a review of the copies of those forms furnished to the Partnership and written representations from the applicable officers and directors, the Partnership believes its officers and directors complied with all applicable Section 16(a) filing requirements during the fiscal year ended December 31, 2008.
 
Item 11.   Executive and Director Compensation
 
Compensation Discussion and Analysis
 
Overview
 
The compensation committee of the board of directors of our general partner oversees our compensation programs. Our general partner maintains compensation and benefits programs designed to allow us to attract, motivate and retain the best possible employees to manage the Partnership, including executive compensation


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programs designed to reward the achievement of both short-term and long-term goals necessary to promote growth and generate positive unitholder returns. Our general partner’s executive compensation programs are based on a pay-for-performance philosophy, including measurement of the Partnership’s performance against a specified financial target, namely distributable cash flow. The Partnership’s executive compensation programs include both long-term and short-term compensation elements which, together with base salary and employee benefits, constitute a total compensation package intended to be competitive with similar companies. Although short-term compensation elements represent the majority of total compensation that can be earned and paid to our executives, the long-term elements as described in “Elements of Executive Compensation — Long-Term, Unit-Based Awards” for which the compensation committee and board of directors approved for implementation beginning with the 2007 fiscal year will represent a significant portion of total compensation on a prospective basis to provide a meaningful incentive for the executives to achieve goals and objectives focused on long-term unitholder returns.
 
Under their collective authority, the compensation committee and the board of directors maintain the right to develop and modify compensation programs and policies as they deem appropriate. Factors they may consider in making decisions to materially increase or decrease compensation include overall Partnership financial performance, growth of the Partnership over time, changes in complexity of the Partnership as well as individual executive job scope complexity, individual executive job performance, and changes in competitive compensation practices in our defined labor markets. In determining any forms of compensation other than the base salary for the senior executives, or in the case of the chief executive officer the recommendation to the board of directors of the forms of compensation for the chief executive officer, the compensation committee considers the Partnership’s financial performance and relative unitholder return, the value of similar incentive awards to senior executives at comparable companies and the awards given to senior executives in past years.
 
Financial Performance Metric Used in Compensation Programs
 
Our primary business objective is to generate cash flows to make distributions to our unitholders. The Partnership’s distributable cash flow is the primary measurement of performance taken into account in setting policies and making compensation decisions, as we believe this represents the most comprehensive measurement of our ability to generate cash flows. Both short-term and long-term forms of executive compensation are specifically structured on the Partnership’s achievement relative to annual distributable cash flow goals and, as such, determination of related awards, as well as their grant or payment, occurs subsequent to the end of each fiscal year upon final determination of distributable cash flow. We believe that including this financial objective as the primary performance measurement to determine compensation awards for all of our executive officers recognizes the integrated and collaborative effort required by the full executive team to maximize performance. Distributable cash flow is a non-GAAP measure that we define, consistent with our credit agreements, as our Adjusted EBITDA less maintenance capital expenditures, cash interest expense and income tax expense. Please refer to Item 6 “Selected Financial Data — Non-GAAP Financial Measures” for our definition of Adjusted EBITDA.
 
Peer Group and Compensation Targets
 
To evaluate all areas of executive compensation, the compensation committee seeks the additional input of outside compensation consultants and available comparative information to validate that the compensation programs established for our executives are consistent with the philosophy of compensating our executives at ranges that approximate within 10% of the median of market for companies of similar size to us. In 2008, the compensation committee retained Mercer Inc. (“Mercer”) as a consultant to review our general partner’s executive compensation programs. Mercer reported directly to the compensation committee and did not provide any additional services to our general partner. The scope of this engagement included the following:
 
  •  review of Calumet’s existing peer group of publicly-traded master limited partnerships for executive compensation benchmarking;
 
  •  analysis of market pay levels and trends for our named executive officers, other officers and key employees from peer companies including base salary, annual incentives and long-term incentives; and
 
  •  assessment of Calumet’s executive pay levels relative to overall market levels.


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The following master limited partnerships were included by Mercer in the peer group for the compensation review: Atlas Pipeline Partners, L.P., Buckeye Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, L.P., DCP Midstream Partners, L.P., Genesis Energy, L.P., Inergy, L.P., MarkWest Energy Partners, L.P., Penn Virginia Resource Partners, L.P., Regency Energy Partners, L.P. and Suburban Propane Partners, L.P. Peer group companies were validated and selected based on their comparability of EBITDA (a non-GAAP measurement), sales and total assets to those of Calumet. Market data compiled from public disclosures of the peer group companies were used in the review to benchmark our compensation of the key executive group against the market. Mercer provided a presentation of its findings to the compensation committee in October 2008.
 
The compensation committee used the findings of the Mercer executive compensation review to validate that total compensation for Calumet’s key executives, including each named executive officer, is competitive with the middle range of total compensation among a peer group of companies and the broader market in which Calumet competes for executive talent when making its compensation decisions. The Mercer review indicated that Calumet’s aggregate target total direct compensation of its key executives, which includes all the major elements of its executive compensation program, including base salary, short-term incentives and long-term compensation, was below the median of market by less than 5%. While the Mercer review indicated that aggregate base salaries for key executives fall near the 25th percentile of the peer group, short-term incentives for each of the key executives, assuming the target levels of such incentives are achieved, are near the 75th percentile of the market. As a result of higher short-term incentives, total cash compensation of our key executives, in aggregate, falls approximately 10% above the median of the peer group. Long-term incentives as a percentage of base salaries for the key executives generally falls below the 25th percentile of the peer group. In addition, Mercer’s findings indicated that upon review of cash compensation among Calumet’s executives, relative parity was generally consistent with market practices.
 
Review of Named Executive Officer Performance
 
The compensation committee reviews, on an annual basis, each compensation element of a named executive officer. In each case, the compensation committee takes into account the scope of responsibilities and experience and balances these against competitive salary levels. The compensation committee has the opportunity to meet with the named executive officers at various times during the year, which allows the compensation committee to form its own assessment of each individual’s performance.
 
Objectives of Compensation Programs
 
The Partnership’s executive compensation programs are designed with the following primary objectives:
 
  •  reward strong individual performance that drives positive Partnership financial results;
 
  •  make incentive compensation a significant portion of an executive’s total compensation, designed to balance short-term and long-term performance;
 
  •  align the interests of our executives with those of our unitholders; and
 
  •  attract, develop and retain executives with a compensation structure that is competitive with other publicly-traded partnerships of similar size.
 
Elements of Executive Compensation
 
The compensation committee believes the total compensation and benefits program for the Partnership’s named executive officers should consist of the following:
 
  •  base salary;
 
  •  annual incentive plan which includes short-term cash awards and also includes an optional deferred compensation element;
 
  •  long-term incentive compensation, including unit-based awards;
 
  •  retirement, health and welfare benefits; and
 
  •  perquisites.


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These elements are designed to constitute an integrated executive compensation structure meant to incentivize a high level of individual executive officer performance in line with the Partnership’s financial and operating goals.
 
Base Salary
 
Salaries provide executives with a base level of monthly income as consideration for fulfillment of certain roles and responsibilities. The salary program assists us in achieving our objective of attracting and retaining the services of quality individuals who are essential for the growth and profitability of Calumet. Generally, changes in the base salary levels for our named executive officers are determined on an annual basis by the compensation committee of the board of directors and are effective at the beginning of the following fiscal year. This determination is based on the following criteria to determine incremental adjustments to base salary:
 
  •  an assessment of the individual executive’s sustained performance against his or her individual job responsibilities and overall job complexity;
 
  •  general cost of living increases;
 
  •  current salary relative to that of other Calumet executives; and
 
  •  a review by the compensation committee of the range of executive salaries for our peer group of publicly traded partnerships of similar size in the energy industry to ensure that base salaries, when combined with other compensation components, fall within 10% of the market median of our peer group.
 
Increases to annual salary reflect a reward and recognition for successfully fulfilling the position’s roles and responsibilities. The compensation committee reviews annual inflation indexes to determine a general level of cost of living increase that is used consistently in determining annual cost of living increases for all of our employees. The compensation committee, in its discretion, may make base salary adjustments at an interim date during the fiscal year for executives deemed warranted due to changes in job complexity or after a comparison of executive compensation levels of publicly-traded partnerships similar in size to us.
 
Mr. Grube’s initial base salary was established under his employment agreement, which provides that the amount of his annual salary increase must be at least equal to the average of the percentage increases of all salaried employee’s of Calumet’s general partner. Mr. Grube’s salary increases for 2008 and 2009 were each 4.0%, which was equivalent to the average of the percentage increases of all salaried employees for each of those fiscal years. Please read “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Employment Agreement with F. William Grube” for additional terms of Mr. Grube’s employment agreement.
 
For fiscal year 2008, the compensation committee approved more significant increases in the base salaries for Mr. Murray and Ms. Straumins based on increased job complexity due to the growth of our business.
 
The compensation committee approved increased salaries for all of the named executive officers for 2009 as part of its annual salary review process in consideration of the above factors. Effective January 1, 2009, the base salaries for Mr. Moyes, Mr. Murray, Mr. Anderson and Ms. Straumins are $296,400, $242,000, $220,000 and $214,500, respectively. The more significant increase in Mr. Anderson’s base salary for 2009 is based on increased job complexity due to the growth of our business.
 
Short-Term Cash Awards
 
Under the Cash Incentive Compensation Plan (the “Cash Incentive Plan”), short-term cash awards are designed to aid Calumet in retaining and motivating executives to assist the Partnership in meeting its financial performance objectives on an annual basis. Short-term cash awards are granted to named executive officers and certain other management employees based on Calumet’s achievement of performance targets on its distributable cash flow, thereby establishing a direct link between executive compensation and the Partnership’s financial performance.
 
The compensation committee establishes minimum, target and stretch incentive opportunities for each executive officer expressed as a percentage of base salary. The amount that is paid out is based on Calumet’s


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achievement of a minimum, target or stretch level of distributable cash flow for the fiscal year. Generally, no awards are paid under the Cash Incentive Plan unless the Partnership achieves at least the minimum distributable cash flow goal. The compensation committee can recommend to the full Board, however, that cash awards be given notwithstanding the fact that the Partnership failed to achieve at least the minimum distributable cash flow goal. Since the inception of the Cash Incentive Plan the compensation committee has not used this discretion, as no awards have been paid under the plan unless the Partnership achieved at least the minimum distributable cash flow goal. If the minimum, target or stretch level distributable cash flow amount is achieved, participants in the plan will receive their minimum, target or stretch cash award opportunity, respectively. If the Partnership’s distributable cash flow is between specified goal levels, participants are eligible to receive a prorated percentage of their cash award opportunity based on where the actual distributable cash flow amount falls between the levels. For fiscal year 2008, the minimum distributable cash flow goal was $90.0 million, the target goal was $110.0 million and the stretch goal was $125.0 million.
 
The following table summarizes the levels of cash award opportunity for each named executive officer and the actual percentage earned by them in 2008:
 
                                 
    Cash Incentive Award Opportunity as a
 
    Percentage of Base Salary  
    Minimum     Target     Stretch     Actual Payout  
 
F. William Grube
    50 %     100 %     200 %     73 % (1)
Allan A. Moyes, III
    50 %     100 %     200 %     61 %
R. Patrick Murray, II, William A. Anderson, and Jennifer G. Straumins
    50 %     100 %     150 %     61 %
 
 
(1) Mr. Grube’s employment agreement guarantees him a potential award that is at least 150% of the amount of the next highest potential award by any other executive officer of our general partner, which would be the maximum potential award for Mr. Moyes of $548,000.
 
The compensation committee determined these percentages of base salary at levels, when combined with both base salary and potential long-term, unit-based awards, to develop a total direct compensation structure for the named executive officers which is intended to be within 10% of the median of our peer group, while placing significant emphasis on the achievement of the Partnership’s distributable cash flow goals.
 
At the recommendation of the compensation committee, the board of directors approves distributable cash flow targets for each fiscal year based on budgets prepared by management. The 2008 target distributable cash flow goal was established at a level that the board of directors believed reflected the reasonable expectations management had for the financial performance of the Partnership during the fiscal year and likely to be achieved given actual distributable cash flow achieved for the 2007 fiscal year. The board of directors set the stretch cash flow goal at a level which they believed would be attained only with higher levels of performance relative to the reasonable expectations management had for the financial performance of the Partnership and therefore not likely to be achieved. For the 2008 fiscal year, the Partnership’s distributable cash flow was above the minimum goal but below its target distributable cash flow goal. The primary drivers of the Partnership not meeting its target distributable cash flow goal were the dramatic increase in the price of crude oil during the first half of 2008, which negatively impacted the Partnership’s gross profit relative to expected performance, and realized hedging losses on the Partnership’s derivative instruments which were caused primarily by the rapid decline in crude oil prices during the second half of 2008, which negatively impacted the Partnership’s Adjusted EBITDA relative to expected performance.
 
Upon the recommendation of the compensation committee, the board of directors has approved new distributable cash flow targets for the 2009 fiscal year based on budgets prepared by management. Each of the three distributable cash flow goal levels for the 2009 fiscal year exceeds its corresponding distributable cash flow goal level for the 2008 fiscal year in line with the same expected likelihood of achieving such goal levels used to set the distributable cash flow goals for 2008.
 
For further description of this compensation program, please see “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Cash Incentive Plan.”


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Executive Deferred Compensation Plan
 
On December 18, 2008, the board of directors approved the Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan (the “Deferred Compensation Plan”), effective January 1, 2009. The compensation committee will act as plan administrator of the Deferred Compensation Plan. The compensation committee allows for the participation of the executive officers in this plan to encourage the officers to save for retirement and to assist the Partnership in retaining the officers. The Deferred Compensation Plan is intended to promote retention by giving employees an opportunity to save in a tax-efficient manner. The terms governing the retirement benefit under this plan for the executive officers are the same as those available for other eligible employees in the U.S. Pursuant to the Deferred Compensation Plan, a select group of management, including the named executive officers, and all of the non-employee directors of the Partnership will be eligible to participate by making an annual irrevocable election to defer, in the case of management, all or a portion of their annual cash incentive award under the Cash Incentive Plan, and, in the case of non-management directors, all or none of their annual cash retainer. The deferred amounts will be credited to participant’s accounts in the form of phantom units, with each such phantom unit representing a notional unit that entitles the holder to receive either an actual common unit of the Partnership or the cash value of a common unit (determined by using the fair market value of a common unit at the time a determination is needed). The phantom units credited to each Plan participant’s account will receive distribution equivalent rights, which will be credited to the participant’s account in the form of additional phantom units. In its sole discretion, the Partnership may make matching contributions of phantom units or purely discretionary contributions of phantom units, in amounts and at times as it determines.
 
Plan distributions are payable on the earlier of the date specified by each participant and the participant’s termination of employment. Participants will at all times be 100% vested in amounts they have deferred pursuant to their annual cash incentive award or annual cash retainer. Partnership contributions, however, may be subject to a vesting schedule, as determined by the plan administrator. Certain events such as death, disability, normal retirement or a change of control of the Partnership require automatic distribution of the Deferred Compensation Plan benefits, and will also accelerate any portion of a participant’s account that has not already become vested at that time. Plan benefits will be distributed to participants in the form of common units, cash or a combination of common units and cash at the election of the plan administrator.
 
Long-Term, Unit-Based Awards
 
Long-term unit-based awards may consist of phantom units, restricted units, unit options, substitution awards, and distribution equivalent rights. These awards are granted to employees, consultants and directors of our general partner under the provisions of our Long-Term Incentive Plan, as amended, (the “Plan”) originally adopted on January 24, 2006 and administered by the compensation committee. These awards aid Calumet in retaining and motivating executives to assist the Partnership in meeting its financial performance objectives.
 
In fiscal 2008, the annual unit awards to named executive officers consisted of the contingent right to receive a phantom units. A phantom unit is the right to receive, upon the satisfaction of time-based vesting criteria specified in the grant, a common unit (or cash equivalent). Under the program, phantom units are granted only upon the Partnership’s achievement of specified levels of distributable cash flow. Accordingly, these awards established a direct link between executive compensation and the Partnership’s financial performance. This component of executive compensation, when coupled with an extended ratable vesting period as compared to cash awards, further aligns the interests of executives with the Partnership’s unitholders in the longer-term and reinforces unit ownership levels among executives.


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The following table provides the annual unit award opportunity for each named executive officer. The objective in determining the size of the phantom unit awards is to provide our named executive officers with long-term incentive opportunities targeted at the between the 25th percentile and the 50th percentile of peer practices for long-term equity based awards for similarly situated executive officers. The distributable cash flow target and stretch levels were the same ones used in determining payouts for the cash incentive awards.
 
                         
    2008 Phantom Unit Award Opportunity     Phantom Units
 
    Target     Stretch     Granted  
 
F. William Grube
    6,000       9,000       0  
Allan A. Moyes, III
    4,000       6,000       0  
R. Patrick Murray, II, William A. Anderson, and Jennifer G. Straumins
    3,000       4,500       0  
 
No phantom units were granted under the program related to fiscal year 2008 because the Partnership did not achieve at least its target distributable cash flow goal.
 
Phantom units that are granted are subject to a time-vesting requirement, whereby 25% of the units vest immediately at grant and the remainder vest ratably over three years.
 
Upon the recommendation of the compensation committee, the board of directors has approved new distributable cash flow targets for the 2009 fiscal year based on budgets prepared by management with the same estimated likelihoods of distributable cash flow performance levels as described above in “Short-Term Cash Awards.” The board of directors also approved increases in the two potential levels of phantom unit grants for all participants to be awarded based on whether the Partnership achieves its specified distributable cash flow goals, namely the target and stretch distributable cash flow goals, and such phantom unit grants would include the same time vesting requirement as potential phantom unit awards offered under the program in prior fiscal years.
 
For 2009, as a result of the significant decrease in the trading price of our common units and our desire to maintain our target long-term incentive opportunity in line with our peer group, the number of phantom units that may be awarded upon achievement of the specified levels of distributable cash flow has been increased. In addition, Ms. Straumins and Messrs. Murray and Anderson are eligible to receive the same number of phantom units as Mr. Moyes based on a goal of achieving internal parity in potential awards among our named executive officers. The following table provides the annual unit award opportunity for each named executive officer.
 
                 
    2009 Phantom Unit Award Opportunity  
    Target     Stretch  
 
F. William Grube
    10,800       16,200  
R. Patrick Murray, II, Allan A. Moyes, III, William A. Anderson, and Jennifer G. Straumins
    7,200       10,800  
 
For further description of this compensation program, please see “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Phantom Unit Program.”
 
Health and Welfare Benefits
 
We offer a variety of health and welfare benefits to all eligible employees of our general partner. These benefits are consistent with the types of benefits provided by our peer group and provided so as to assure that we are able to maintain a competitive position in terms of attracting and retaining executive officers and other employees. In addition, the health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. The named executive officers generally are eligible for the same benefit programs on the same basis as the rest of our employees. Our health and welfare programs include medical, pharmacy, dental, life insurance and accidental death and dismemberment. In addition, certain employees are eligible for long-term disability coverage. Coverage under long-term disability offers benefits specific to the named executive officers. We provide the named executive officers with a compensation allowance, which is grossed up for the payment of taxes to allow them to purchase long-term disability coverage on an after-tax basis at no net cost to them. As


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structured, these long-term disability benefits will pay 60% of monthly earnings, as defined by the policy, up to a maximum of $6,000 per month during a period of continuing disability up to normal retirement age, as defined by the policy. Executive officers and other key employees are also eligible to obtain executive physical examinations which are paid for by the Partnership. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.
 
Retirement Benefits
 
We provide the Calumet GP, LLC Retirement Savings Plan (the “401(k) Plan”) to assist our eligible officers and employees in providing for their retirement. Named executive officers participate in the same retirement savings plan as other eligible employees subject to ERISA limits. The Partnership matches 100% of each 1% of eligible compensation contribution by the participant up to 4% and 50% of each additional 1% of eligible compensation contribution up to 6%, for a maximum contribution by the Partnership of 5% of eligible compensation contributions per participant. These contributions are provided as a reward for prior contributions and future efforts toward our success and growth.
 
The retirement savings plan also includes a discretionary profit-sharing component. Determination of annual contributions are made by the compensation committee based on overall profitability of the Partnership. The board of directors approved a discretionary profit sharing contribution to the 401(k) plan for all eligible participants equivalent to 2.5% of their eligible compensation for the 2008 fiscal year. The value of Partnership contributions to the retirement savings plan for named executive officers is included in the Summary Compensation Table. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.
 
Perquisites
 
We provide certain executive officers with perquisites and other personal benefits that we believe are reasonable and consistent with our overall compensation programs and philosophy. These benefits are provided in order to enable us to attract and retain these executives. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.
 
All named executive officers are provided with all, or certain of, the following benefits as a supplement to their other compensation:
 
  •  Use of Company Vehicle:  In order to assist them in conducting the daily affairs of the Partnership, we provide each named executive officer with a company vehicle that may be used for personal use as well as business use. Personal use of a company vehicle is treated as taxable compensation to the named executive officer.
 
  •  Executive Physical Program:  Generally on an annual basis, we pay for a complete and professional personal physical exam for each named executive officer appropriate for his or her age to improve their health and productivity.
 
  •  Club Memberships:  We pay club membership fees for certain named executive officers. Although such club memberships may be used for personal purposes in addition to business entertainment purposes, each named executive officer having such a membership is responsible for the reimbursement of the Partnership or direct payment for any incremental costs above the base membership fees associated with his or her personal use of such membership.
 
  •  Spousal Travel:  On an occasional basis, we pay expenses related to travel of the spouses of our named executive officers in order to accompany the named executive officer to business-related events.
 
  •  Long-Term Disability Insurance:  We provide compensation to allow each named executive officer to purchase long-term disability insurance on an after-tax basis at no net cost to them.
 
The compensation committee periodically reviews the perquisite program to determine if adjustments are appropriate.


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Other Compensation Related Matters
 
Tax Implications of Executive Compensation
 
Because Calumet is not an entity taxable as a corporation, many of the tax issues associated with executive compensation that face publicly traded corporations do not directly affect the Partnership. Internal Revenue Code Section 409A (“Section 409A”) provides that amounts deferred under nonqualified deferred compensation plans are includible in a participant’s income when vested, unless certain requirements are met. If these requirements are not met, participants are also subject to an additional income tax and interest. All of our awards under our Long-Term Incentive Plan, severance arrangements and other nonqualified deferred compensation plans presently meet these requirements. As a result, employees will be taxed when the deferred compensation is actually paid to them. We will be entitled to a tax deduction at that time.
 
Executive Ownership of Units
 
While we have not adopted any security ownership requirements or policies for our executives, our executive compensation programs foster the enhancement of executives’ equity ownership through long-term, unit-based awards under Calumet’s Long-Term Incentive Plan. Further, in 2006 several executives purchased a significant number of our common units as participants in our directed unit program in conjunction with our initial public offering. For a listing of security ownership by our named executive officers, refer to Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”
 
The board of directors has adopted the Insider Trading Policy of Calumet GP, LLC and Calumet Specialty Products Partners, L.P. (the “Insider Trading Policy”), which provides guidelines to employees, officers and directors with respect to transactions in the Partnership’s securities. Pursuant to Calumet’s Insider Trading Policy, all executive officers and directors must confer with the Chief Financial Officer before effecting any put or call options for the Partnership’s securities. Further, the Insider Trading Policy states that the Partnership strongly discourages all such transactions by officers, directors and all other employees and consultants. The Insider Trading Policy is available on our website at www.calumetspecialty.com or a copy will be provided at no cost to unitholders upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, IN 46214.
 
Employment Agreement
 
We have entered into an employment agreement with our chief executive officer and president, F .William Grube, to ensure he will perform his role for an extended period of time given his position and value to the Partnership. For a discussion of the major terms of Mr. Grube’s employment agreement, please refer to “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Employment Agreement with F. William Grube.”
 
Under his employment agreement, Mr. Grube is entitled to receive severance compensation if his employment is terminated under certain conditions, such as termination by Mr. Grube for “good reason” or by us without “cause,” each as defined in the agreement and further described in “Potential Payments Upon Termination — Employment Agreement with F. William Grube.”
 
Our employment agreement with Mr. Grube and the related severance provisions are designed to meet the following objectives:
 
  •  Change in Control:  In certain scenarios, the potential for merger or being acquired may be in the best interests of our unitholders. We provide the potential for severance compensation to Mr. Grube in the event of a change in control transaction to promote his ability to act in the best interests of our unitholders even though his employment could be terminated as a result of the transaction.
 
  •  Termination without Cause:  We believe severance compensation in such a scenario is appropriate because Mr. Grube is bound by confidentiality, nonsolicitation and noncompetition provisions covering one year after termination and because we and Mr. Grube have a mutually agreed to severance package that is in place


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  prior to any termination event. This provides us with more flexibility to make a change in this executive position if such a change is in our and our unitholders’ best interests.
 
The salary multiple of the change of control benefits, use of the single trigger change of control benefits and the amount of the severance payout were determined through negotiation with Mr. Grube at the time that we entered into his employment agreement. Relative to the overall value of the Partnership, the compensation committee believes these potential benefits are reasonable.
 
Summary Compensation Table
 
The following table sets forth certain compensation information of our named executive officers for the years ended December 31, 2008, 2007 and 2006:
 
                                         
    Summary Compensation Table for 2008  
                Non-Equity Incentive
    All Other
       
Name and Principal Position
  Year     Salary     Plan Compensation (2)     Compensation (3)     Total  
 
F. William Grube
    2008     $ 357,000     $ 261,844     $ 25,712     $ 644,556  
Chief Executive Officer and President
    2007       342,800             7,858       350,658  
      2006       332,800       654,263       31,138       1,018,201  
R. Patrick Murray, II
    2008       220,000       134,750       24,682       379,432  
Vice President and Chief Financial Officer
    2007       188,333             7,023       195,356  
      2006       152,500       224,379       30,464       407,343  
Allan A. Moyes, III
    2008       285,000       174,563       26,919       486,482  
Executive Vice President
    2007       274,000             44,455       318,455  
      2006       251,592       436,175       32,184       719,951  
William A. Anderson
    2008       190,000       116,375       36,336       342,711  
Vice President — Sales and Marketing
    2007       182,000             18,079       200,079  
      2006       163,917       230,979       35,106       430,002  
Jennifer G. Straumins (1)
    2008       195,000       119,438       21,940       336,378  
Senior Vice President
    2007       166,000             6,913       172,913  
 
 
(1) Ms. Straumins became an executive officer in February 2007.
 
(2) Represents amounts earned under the Partnership’s Cash Incentive Compensation Plan. Please read “Compensation Discussion and Analysis — Elements of Executive Compensation — Short-Term Cash Awards.”
 
(3) The following table provides the aggregate “All Other Compensation” information for each of the named executive officers, except that it excludes perquisites or other personal benefits received by Mr. Grube, Mr. Murray, Mr. Moyes and Ms. Straumins in 2008, as such amounts for these named executive officers were each less than $10,000 in the aggregate.
 
                                                                 
    401(k) Plan
                            Long-Term
             
    Matching
    Annual
          Spousal
    Club
    Disability
    Term Life
       
    Contributions     Physical     Vehicle     Travel     Membership     Insurance     Insurance     Total  
 
F. William Grube
  $ 24,534     $     $     $     $     $     $ 1,178     $ 25,712  
R. Patrick Murray, II
    23,956                                     726       24,682  
Allan A. Moyes, III
    25,978                                     941       26,919  
William A. Anderson
    20,642             6,707       965       6,545       850       627       36,336  
Jennifer G. Straumins
    21,296                                     644       21,940  


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Grants of Plan-Based Awards
 
The following table sets forth grants of plan-based awards to our named executive officers for the year ended December 31, 2008:
 
                         
    Estimated Future Payouts Under
 
    Non-Equity Incentive Plan Awards  
Name
  Minimum     Target     Maximum  
 
F. William Grube
  $ 213,750     $ 427,500     $ 855,000  
R. Patrick Murray, II
  $ 110,000     $ 220,000     $ 330,000  
Allan A. Moyes III
  $ 142,500     $ 285,000     $ 570,000  
William A. Anderson
  $ 95,000     $ 190,000     $ 285,000  
Jennifer G. Straumins
  $ 97,500     $ 195,000     $ 292,500  
 
The above table shows the ranges of potential cash incentive awards granted to executives under Calumet’s Cash Incentive Compensation Plan related to fiscal year 2008. For a description of this plan and available awards, please read “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Cash Incentive Plan.”
 
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table
 
Description of Cash Incentive Plan
 
Annual distributable cash flow goals are recommended by the compensation committee to the board of directors and are based upon the annual Partnership forecast of financial performance for the coming fiscal year, and such goals are reviewed and approved by the board of directors. Three increasing distributable cash flow goals are established to calculate awards under the Cash Incentive Plan: minimum, target and stretch. Under the Cash Incentive Plan, if the Partnership’s actual performance meets at least the minimum distributable cash flow goal for the fiscal year, executives and certain other management employees may receive incentive awards ranging from 15% to 50% of base salary, depending on the employee’s position with the general partner. If financial performance exceeds the minimum distributable cash flow goal, the cash incentive award paid as a percentage of base salary may be larger, ultimately reaching an upper range of 60% to 200% of base salary, if distributable cash flow for the fiscal year reaches the stretch goal. Cash incentive awards are prorated if actual performance falls between the defined minimum and stretch cash flow goals. If distributable cash flow falls below the minimum goal, no cash incentive awards are paid under the Cash Incentive Plan. Awards earned, if any, under this plan are generally paid in the first quarter of the following fiscal year after finalizing the calculation of the Partnership’s performance relative to the distributable cash flow targets. The following table summarizes the levels of awards available to participants in the Cash Incentive Plan:
 
                         
    Cash Incentive Award Calculated as a
 
    Percentage of Base Salary  
Incentive Level (1)
  Minimum     Target     Stretch  
 
1
    50 %     100 %     200 %
2
    50 %     100 %     150 %
3
    20 %     40 %     80 %
4
    15 %     30 %     60 %
 
 
(1) Mr. Grube, our chief executive officer and president, and Mr. Moyes, our executive vice president, are the only employees who participate in the Cash Incentive Plan at Incentive Level 1. The other named executive officers (Mr. Murray, Mr. Anderson and Ms. Straumins), along with certain other officers, participate in the Cash Incentive Plan at Incentive Level 2.
 
As recommended by the compensation committee and approved by the board of directors, for the 2009 fiscal year, Mr. Murray, Mr. Anderson and Ms. Straumins will participate in the Cash Incentive Plan at Incentive Level 1.


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Beginning with the 2009 fiscal year, participants in the Cash Incentive Plan will be eligible to defer all or a portion of all of their award, if any, under the Cash Incentive Plan into the Calumet Executive Deferred Compensation Plan, which was adopted by the board of Directors on December 18, 2008 and effective as of January 1, 2009. See “Compensation Discussion and Analysis — Elements of Executive Compensation — Executive Deferred Compensation Plan” for additional discussion of this plan.
 
Description of Long-Term Incentive Plan
 
Following is a summary of the major terms and provisions of the Partnership’s Long-Term Incentive Plan:
 
General.  The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan, an aggregate of 43,968 of which have already been awarded to the non-employee directors of our general partner. Units withheld to satisfy our general partner’s tax withholding obligations are available for delivery pursuant to other awards.
 
Restricted Units and Phantom Units.  A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or our general partner, subject to any contrary provisions in the award agreement.
 
If a grantee’s employment, consulting or membership on the board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the grant agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner is entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase. Any outstanding restricted unit or phantom unit awards fully vest upon the occurrence of certain events including, but not limited to, change of control of the Partnership, death, disability and normal retirement.
 
Distributions made by us on restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units. Previously granted contingent phantom unit awards have contemplated the award of tandem distribution equivalent rights, or DERS, in the event the phantom units were awarded. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit. The compensation committee, in its discretion, may grant tandem DERs on such terms as it deems appropriate.
 
Participants do not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.
 
2008 Phantom Unit Program.  In addition to the features described above, potential awards under our 2008 Phantom Unit Program range from 1,000 to 6,000 phantom units for achievement of the target distributable cash flow goal and from 1,500 to 9,000 phantom units for achievement of the stretch distributable cash flow goal. Awards are not prorated for actual distributable cash flow that is achieved between the target and stretch levels. Phantom units that are granted are subject to a time-vesting requirement, whereby 25% of


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the units vest immediately at grant and the remainder vest ratably over three years on each December 31st. At the election of the general partner, phantom unit awards may be settled in either cash or common units.
 
The following table summarizes the levels of phantom unit awards available to participants in the 2008 program:
 
                 
    Phantom Unit Award Opportunity  
Incentive Level (a)
  Target     Stretch  
 
1
    6,000       9,000  
2
    4,000       6,000  
3
    3,000       4,500  
4
    2,000       3,000  
5
    1,000       1,500  
 
 
(a) Mr. Grube is the only employee and named executive officer who is eligible for a long-term unit-based award under Incentive Level 1. Mr. Moyes is the only employee and named executive officer who is eligible for a long-term unit-based award under Incentive Level 2. The other named executive officers (Mr. Murray, Mr. Anderson and Ms. Straumins), along with certain other officers, participate in the program at Incentive Level 3.
 
Unit Options.  The Plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant.
 
Upon exercise of a unit option, our general partner will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring the common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.
 
Substitution Awards.  The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, our general partner or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.
 
Termination of Plan.  Our general partner’s board of directors, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by the board of directors of our general partner or when common units are no longer available for delivery pursuant to awards under the Plan. Our general partner’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the board of directors of our general partner may increase the number of common units that may be delivered with respect to awards under the Plan.
 
Description of Employment Agreement with F. William Grube
 
We have an employment agreement with F. William Grube, our chief executive officer and president, dated as of January 31, 2006 (the “Effective Date”). The term of the employment agreement is five years and expires on


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January 31, 2011 (the “Employment Period”), with automatic extensions of an additional twelve months added to the Employment Period beginning on the third anniversary of the Effective Date, and on every anniversary of the Effective Date thereafter, unless either party notifies the other of non-extension at least ninety days prior to any such anniversary date.
 
The agreement provides for an initial annual base salary of approximately $333,000, subject to annual adjustment by the compensation committee of the board of directors of our general partner, as well as the right to participate in our Long-Term Incentive Plan and other bonus plans. Mr. Grube will generally be entitled to receive a payout or distribution of at least 150% of the amount of any cash, equity or other payout or distribution that may be made to any other executive officer under the terms of these plans. Mr. Grube’s employment agreement may be terminated at any time by either party with proper notice. For the term of the employment agreement and for the one-year period following the termination of employment, Mr. Grube is prohibited from engaging in competition (as defined in the employment agreement) with us and soliciting our customers and employees.
 
Outstanding Equity Awards at Fiscal Year-End
 
Our named executive officers had no outstanding equity awards at December 31, 2008.
 
Options Exercises and Stock Vested
 
Our named executive officers exercised no options and had no unit awards vest during the year ended December 31, 2008.
 
Pension Benefits
 
The Partnership has no pension plans that provide for payments or other benefits for our named executive officers.
 
Nonqualified Deferred Compensation
 
On December 18, 2008, the board of directors approved the Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan (the “Deferred Compensation Plan”), to be effective as of January 1, 2009. The Deferred Compensation Plan is an unfunded arrangement intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of the Employee Retirement Income Security Act of 1974, as amended, and to comply with Section 409A. See “Compensation Discussion and Analysis - Elements of Executive Compensation — Executive Deferred Compensation Plan” for additional discussion of this plan.
 
Potential Payments Upon Termination
 
Employment Agreement with F. William Grube
 
Following is a description of our obligations, including potential payments to Mr. Grube, upon termination of Mr. Grube’s employment under various termination scenarios. We have assumed for purposes of quantifying Mr. Grube’s potential payments that his termination occurred on December 31, 2008, and amounts are our best estimates as to the potential payout he would have received upon that date. The amounts Mr. Grube would receive upon an actual termination of employment could only be calculated with certainty upon a true termination of employment.
 
In consideration for any potential severance Mr. Grube may receive pursuant to his employment agreement, he will not compete or solicit our employees for a period of one year following a termination of employment. Prior to receipt of any potential severance payments or the acceleration of any outstanding equity awards, Mr. Grube will be required to sign, and not revoke, a full waiver and release in our favor. Following such release and waiver’s period of revocability, Mr. Grube will be eligible to receive payments as soon as administratively possible, though if Section 409A would subject Mr. Grube to additional taxes upon receipt of the payments, we will delay the payment of these amounts for a period of six months and provide for interest to accrue on such delayed amounts at the maximum nonusurious rate from the date of the originally scheduled payment date.


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Termination of Employment Due to Death or Disability
 
Upon the termination of Mr. Grube’s employment due to his disability or death:
 
a. We will pay him or his beneficiary a lump sum equal to his earned annual base salary through the date of termination to the extent not theretofore paid;
 
b. We will pay him or his beneficiary a lump sum equal to any compensation incentive awards payable in cash with respect to fiscal years ended prior to the year that includes the date of termination to the extent not theretofore paid;
 
c. We will pay him or his beneficiary a lump sum cash payment with respect to his participation in any plans, programs, contracts or other arrangements that may result in a cash payment for the fiscal year that includes the date of termination on a prorated basis considering the date of termination relative to the full fiscal year; and
 
d. Any equity awards held by Mr. Grube shall immediately vest and become fully exercisable or payable, as the case may be.
 
For this purpose, Mr. Grube will be deemed to have a “disability” if he is unable to perform his duties under the employment agreement by reason of mental or physical incapacity for 90 consecutive calendar days during the Employment Period, provided that we will not have the right to terminate his employment for disability if in the written opinion of a qualified physician reasonably acceptable to us is delivered to the us within 30 days of our delivery to Mr. Grube of a notice of termination (as defined in the employment agreement) that it is reasonably likely that Mr. Grube will be able to resume his duties on a regular basis within 90 days of the notice of termination and Mr. Grube does resume such duties within such time.
 
If Mr. Grube’s employment were to have been terminated on December 31, 2008, due to death or disability (as defined in the employment agreement), we estimate that the value of the payments and benefits described in clauses (a), (b), (c) and (d) above he would have been eligible to receive is as follows: (a) $0; (b) $0; (c) $261,844; and (d) $0, with an aggregate value of $261,844.
 
Termination of Employment by Mr. Grube for Good Reason or by Us Without Cause
 
Upon the termination of Mr. Grube’s employment by him for good reason or by us without cause:
 
a. We will pay him a lump sum cash payment in an amount equal to three times his annual base salary then in effect;
 
b. We will pay him a lump sum equal to his earned annual base salary through the date of termination to the extent not theretofore paid;
 
c. We will pay him a lump sum equal to any compensation incentive awards payable in cash with respect to fiscal years ended prior to the year that includes the date of termination to the extent not theretofore paid;
 
d. We will pay him a lump sum cash payment with respect to his participation in any plans, programs, contracts or other arrangements that may result in a cash payment for the fiscal year that includes the date of termination on a prorated basis considering the date of termination relative to the full fiscal year;
 
e. All equity-based awards (including phantom unit awards) held by Mr. Grube shall immediately vest in full (at their target levels, if applicable) and become fully exercisable or payable, as the case may be.
 
“Good reason” as defined in the employment agreement includes: (i) any material breach by us of the employment agreement; (ii) any requirement by us that Mr. Grube relocate outside of the metropolitan Indianapolis, Indiana area; (iii) failure of any successor to us to assume the employment agreement not later than the date as of which it acquires substantially all of the equity, assets or business of us; (iv) any material reduction in Mr. Grube’s title, authority, responsibilities, or duties (including a change that causes him to cease being a member of the board of directors or reporting directly and solely to the board of directors); or (v) the assignment of Mr. Grube any duties materially inconsistent with his duties as the chief executive officer of the Partnership.


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“Cause” as defined in the employment agreement includes: (i) Mr. Grube’s willful and continuing failure (excluding as a result of his mental or physical incapacity) to perform his duties and responsibilities with us; (ii) Mr. Grube’s having committed any act of material dishonesty against us or any of its affiliates as defined in the employment agreement; (iii) Mr. Grube’s willful and continuing breach of the employment agreement; (iv) Mr. Grube’s having been convicted of, or having entered a plea of nolo contendre to any felony; or (v) Mr. Grube’s having been the subject of any final and non-appealable order, judicial or administrative, obtained or issued by the Securities and Exchange Commission, for any securities violation involving fraud.
 
If Mr. Grube’s employment were to have been terminated by him for good reason or by us without cause on December 31, 2008, we estimate that the value of the payments and benefits described in clauses (a), (b), (c), (d) and (e) above he would have been eligible to receive is as follows: (a) $1,071,000 (or three times $357,000); (b) $0; (c) $0; (d) $261,844; and (e) $0, with an aggregate value of $1,332,844.
 
Termination of Employment by Mr. Grube Without Good Reason or by Us for Cause
 
Upon the termination of employment by Mr. Grube without good reason or by us with cause:
 
a. We will pay him a lump sum equal to his earned annual base salary through the date of termination to the extent not theretofore paid;
 
b. We will pay him a lump sum equal to any compensation incentive awards payable in cash with respect to fiscal years ended prior to the year that includes the date of termination to the extent not theretofore paid; and
 
c. We will pay him a lump sum cash payment with respect to his participation in any plans, programs, contracts or other arrangements that may result in a cash payment for the fiscal year that includes the date of termination on a prorated basis considering the date of termination relative to the full fiscal year.
 
If Mr. Grube’s employment were to have terminated by him without good reason or by us for cause on December 31, 2008, we estimate that the value of the payments and benefits described in clauses (a), (b) and (c) above he would have been eligible to receive is as follows: (a) $0; (b) $0; (c) $261,844, with an aggregate value of $261,844.
 
Compensation of Directors
 
Officers or employees of our general partner who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner receives an annual fee as well as compensation for attending meetings of the board of directors and committee meetings. Non-employee director compensation consists of the following:
 
  •  an annual fee of $30,000, payable in quarterly installments;
 
  •  an annual award of restricted or phantom units with a market value of approximately $40,000;
 
  •  an audit committee chair annual fee of $8,000, payable in quarterly installments;
 
  •  a non-chair audit committee member annual fee of $4,000, payable in quarterly installments;
 
  •  all other committee chair annual fee of $5,000; and
 
  •  all other committee member annual fee of $2,500, payable in quarterly installments.
 
In addition, we reimburse each non-employee director for his out-of-pocket expenses incurred in connection with attending meetings of the board of directors or committees. Under certain circumstances, we will also indemnify each director for his actions associated with being a director to the fullest extent permitted under Delaware law.
 
Effective April 1, 2009, the board of directors approved, upon the recommendation of the compensation committee, an increase in the annual fee paid to non-employee directors from $30,000 to $50,000, primarily as a result of the increased complexity of the Partnership’s operations since its initial public offering in January 2006. Fees related to participation on board of director committees were not revised. Beginning with the 2009 fiscal year,


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non-employee directors have the option to defer all or none of their annual cash fees into the Deferred Compensation Plan which was approved by the board of directors on December 18, 2008. See “Compensation Discussion and Analysis — Elements of Executive Compensation — Executive Deferred Compensation Plan” for additional discussion of this plan.
 
The following table sets forth certain compensation information of our non-employee directors for the year ended December 31, 2008:
 
                         
    Director Compensation Table for 2008  
    Fees Earned or
    Unit
       
Name
  Paid in Cash     Awards (1)     Total  
 
Fred M. Fehsenfeld, Jr. 
  $ 37,500     $ 29,819     $ 67,319  
James S. Carter
    39,000       29,819       68,819  
William S. Fehsenfeld
    30,000       29,819       59,819  
Robert E. Funk
    36,500       29,819       66,319  
Nicholas J. Rutigliano
    30,000       29,819       59,819  
Michael L. Smith
    38,000       29,819       67,819  
 
 
(1) On December 30, 2008, each non-employee director was granted 5,032 phantom units with a grant date fair value of $40,004. With respect to this award, 25% of the phantom units vested on December 31, 2008, entitling the director to common units, with an additional 25% vesting on December 31 of each of the three successive years. Pursuant to Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, $29,819 of compensation cost for each non-employee director was recognized by the Partnership in 2008 related to the vesting of 25% of the 2008 granted phantom units, 25% of the 2007 granted phantom units and 25% of the 2006 granted phantom units, or 1,832 common units, on December 31, 2008. Assumptions used in the calculation of these amounts are included in Note 13 to our audited consolidated financial statements included in this Annual Report on Form 10-K. As of December 31, 2008, each non-employee director had 4,618 unvested phantom units outstanding with a market value of $40,454. An aggregate of 27,708 phantom units with a market value of $242,722 were outstanding as of December 31, 2008.
 
Compensation Committee Interlocks and Insider Participation
 
The members of our compensation committee are F. William Grube and Fred M. Fehsenfeld, Jr. Mr. Grube is our chief executive officer and president. Mr. F. Fehsenfeld, Jr. is the chairman of the board of directors of our general partner. Please read Item 13 “Certain Relationships, Related Party Transactions and Director Independence — Crude Oil Purchases and — Specialty Product Sales” for descriptions of our transactions in fiscal year 2008 with certain entities related to Messrs. Grube and Fehsenfeld, Jr. No executive officer of our general partner served as a member of the compensation committee of another entity that had an executive officer serving as a member of our board of directors or compensation committee.
 
Report of the Compensation Committee for the Year Ended December 31, 2008
 
The compensation committee of our general partner has reviewed and discussed our Compensation Discussion and Analysis with management. Based upon such review, the related discussion with management and such other matters deemed relevant and appropriate by the compensation committee, the compensation committee has recommended to the board of directors that our Compensation Discussion and Analysis be included in the Partnership’s Annual Report on Form 10-K.
 
 
Members of the Compensation Committee:
Fred M. Fehsenfeld, Jr., Chairman
F. William Grube


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Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
 
The following table sets forth the beneficial ownership of our units as of February 26, 2009 held by:
 
  •  each person who beneficially owns 5% or more of our outstanding units;
 
  •  each director of our general partner;
 
  •  each named executive officer of our general partner; and
 
  •  all directors, and executive officers of our general partner as a group.
 
The amounts and percentages of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.
 
Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The address for the beneficial owners listed below, other than The Heritage Group and Kayne Anderson Capital Advisors, L.P., is 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, Indiana 46214.
 
                                         
                      Percentage of
       
    Common
    Percentage of
    Subordinated
    Subordinated
    Percentage of
 
    Units
    Common Units
    Units
    Units
    Total Units
 
    Beneficially
    Beneficially
    Beneficially
    Beneficially
    Beneficially
 
Name of Beneficial Owner
  Owned     Owned     Owned     Owned     Owned  
 
The Heritage Group (1)
    3,838,940       20.03 %     8,028,593       61.45 %     36.82 %
Calumet, Incorporated (2)
    591,886       3.09 %     1,342,401       10.27 %     6.00 %
Kayne Anderson Capital Advisors, L.P. (3)
    1,199,528       6.26 %           %     3.72 %
Janet K. Grube (4)
    1,179,969       6.16 %     2,676,173       20.48 %     11.96 %
F. William Grube
    50,000       *           %     *
Fred M. Fehsenfeld, Jr. (1)(2)(7)(8)
    189,786       *     403,592       3.09 %     1.84 %
Allan A. Moyes, III
    14,124       *           %     *
Jennifer G. Straumins (9)
    7,000       *           %     *
R. Patrick Murray, II
    8,000       *           %     *
Robert M. Mills
    10,450       *           %     *
William A. Anderson (10)
    10,680       *           %     *
Jeffrey D. Smith
    4,000       *           %     *
James S. Carter
    25,835       *           %     *
William S. Fehsenfeld (1)(5)(8)
    65,716       *           %     *
Robert E. Funk
    21,710       *           %     *
Nicholas J. Rutigliano (1)(6)(8)
    38,310       *           %     *
Michael L. Smith
    7,710       *           %     *
All directors and executive officers as a group (12 persons)
    443,321       2.31 %     403,592       3.09 %     2.63 %
 
 
= less than 1 percent.
 
(1) Thirty grantor trusts indirectly own all of the outstanding general partner interests in The Heritage Group, an Indiana general partnership. The direct or indirect beneficiaries of the grantor trusts are members of the Fehsenfeld family. Each of the grantor trusts has five trustees, Fred M. Fehsenfeld, Jr., James C. Fehsenfeld, Nicholas J. Rutigliano, William S. Fehsenfeld and Nancy A. Smith, each of whom exercises equivalent voting


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rights with respect to each such trust. Each of Fred M. Fehsenfeld, Jr., Nicholas J. Rutigliano and William S. Fehsenfeld, who are directors of our general partner, disclaims beneficial ownership of all of the common and subordinated units owned by The Heritage Group, and none of these units are shown as being beneficially owned by such directors in the table above. The address for The Heritage Group is 5400 W. 86th St., Indianapolis, Indiana 46268-0123.
 
(2) The common units of Calumet, Incorporated are indirectly owned 45.8% by The Heritage Group and 5.1% by Fred M. Fehsenfeld, Jr. personally. Fred M. Fehsenfeld, Jr. is also a director of Calumet, Incorporated. Accordingly, 270,877 of the common units and 614,417 of the subordinated units owned by Calumet, Incorporated are also shown as being beneficially owned by The Heritage Group in the table above, and 29,979 of the common units and 67,992 of the subordinated units owned by Calumet, Incorporated are also shown as being beneficially owned by Fred M. Fehsenfeld, Jr. in the table above. The Heritage Group and Fred M. Fehsenfeld, Jr. disclaims beneficial ownership of all of the common and subordinated units owned by Calumet, Incorporated in excess of their respective pecuniary interests in such units.
 
(3) As noted in the Schedule 13G/A filed with the SEC on February 9, 2009. The filing person has indicated that it shares voting and dispositive power of certain of such units. The address for Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.
 
(4) Janet K. Grube’s holdings include common and subordinated units that are owned by two grantor retained annuity trusts for which Janet K. Grube, the spouse of F. William Grube, serves as sole trustee. Janet K. Grube and her two children are the beneficiaries of such trusts. Janet K. Grube’s holdings also include common and subordinated units owned by Janet K. Grube personally. F. William Grube has no voting or investment power over these units and disclaims beneficial ownership of all such units, and none of these units are shown as being beneficially owned by F. William Grube in the table above.
 
(5) Includes common units that are owned by the spouse and children of William S. Fehsenfeld for which he disclaims beneficial ownership.
 
(6) Includes common units that are owned by the spouse of Nicholas J. Rutigliano for which he disclaims beneficial ownership.
 
(7) Includes common units that are owned by the spouse and certain children of Fred M. Fehsenfeld, Jr., for which he disclaims beneficial ownership.
 
(8) Does not include a total of 682,154 common units and 1,297,650 subordinated units owned by two trusts, the direct or indirect beneficiaries of which are members of the Fred M. Fehsenfeld, Jr. family. Each of the trusts has five trustees, Fred M. Fehsenfeld, Jr., James C. Fehsenfeld, Nicholas J. Rutigliano, William S. Fehsenfeld and Nancy A. Smith, each of whom exercises equivalent voting rights with respect to each such trust. Each of Fred M. Fehsenfeld, Jr., Nicholas J. Rutigliano and William S. Fehsenfeld, who are directors of our general partner, disclaims beneficial ownership of all of the common and subordinated units owned by the trusts, and none of these units are shown as being beneficially owned by such directors in the table above.
 
(9) Includes common units that are owned by certain children of Jennifer G. Straumins, for which she disclaims beneficial ownership.
 
(10) Includes common units that are owned by certain children of William A. Anderson, for which he disclaims beneficial ownership.


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Equity Compensation Plan Information
 
The following table summarizes information about our equity compensation plans as of December 31, 2008:
 
                         
                Number of Securities
 
                Remaining Available for
 
    Number of Securities
    Weighted-Average
    Future Issuance Under
 
    to be Issued Upon
    Exercise Price
    Equity Compensation
 
    Exercise of Outstanding
    of Outstanding
    Plans (Excluding
 
    Options, Warrants
    Options, Warrants
    Securities Reflected
 
    and Rights(1)
    and Rights
    in Column (a))
 
    (a)     (b)     (c)  
 
Equity compensation plans approved by unitholders
        $        
Equity compensation plans not approved by unitholders
    27,708             729,992  
                         
Total
    27,708     $       729,992  
                         
 
 
(1) The Long-Term Incentive Plan contemplates the issuance or delivery of up to 783,960 common units to satisfy awards under the plan. The number of units presented in column (a) assumes that all outstanding grants will be satisfied by the issuance of new units or the purchase of existing units on the open market upon vesting. In fact, some portion of the phantom units may be settled in cash and some portion may be withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c). For more information on our Long-Term Incentive Plan, which did not require approval by our limited partners, refer to Item 11 “Executive and Director Compensation — Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Long-Term Incentive Plan.”
 
Item 13.   Certain Relationships, Related Party Transactions and Director Independence
 
Distributions and Payments to Our General Partner and its Affiliates
 
Owners of our general partner and their affiliates own 6,110,015 common units and 13,066,000 subordinated units representing an aggregate 58.3% limited partner interest in us. In addition, our general partner owns a 2% general partner interest in us and the incentive distribution rights. We will generally make cash distributions of 98% to the unitholders pro rata, including the affiliates of our general partner, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level. Please refer to Item 5 “Market Information” for a summary of cash distribution levels of the Partnership during the year ended December 31, 2008.
 
Our general partner does not receive any management fee or other compensation for its management of our partnership, however, our general partner and its affiliates are reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.
 
Omnibus Agreement
 
We entered into an omnibus agreement, dated January 31, 2006, with The Heritage Group and certain of its affiliates pursuant to which The Heritage Group and its controlled affiliates agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental United States (“restricted business”) for so long as The Heritage Group controls us. This restriction does not apply to:
 
  •  any business owned or operated by The Heritage Group or any of its affiliates as of January 31, 2006;
 
  •  the refining and marketing of asphalt and asphalt-related products and related product development activities;


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  •  the refining and marketing of other products that do not produce “qualifying income” as defined in the Internal Revenue Code;
 
  •  the purchase and ownership of up to 9.9% of any class of securities of any entity engaged in any restricted business;
 
  •  any restricted business acquired or constructed that The Heritage Group or any of its affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of less than $5.0 million;
 
  •  any restricted business acquired or constructed that has a fair market value or construction cost, as applicable, of $5.0 million or more if we have been offered the opportunity to purchase it for fair market value or construction cost and we decline to do so with the concurrence of the conflicts committee of the board of directors of our general partner; and
 
  •  any business conducted by The Heritage Group with the approval of the conflicts committee of the board of directors of our general partner.
 
Indemnification of Directors and Officers
 
Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.
 
Insurance Brokerage
 
Nicholas J. Rutigliano, a member of the board of directors of our general partner, founded and is the president of Tobias Insurance Group, Inc., a commercial insurance brokerage business, that has historically placed a portion of our insurance underwriting requirements, including our general liability, automobile liability, excess liability, workers’ compensation as well as directors’ and officers’ liability. The total premiums paid by us through Mr. Rutigliano’s firm for 2008 were approximately $0.6 million. We believe these premiums are comparable to the premiums we would pay for such insurance from a non-affiliated third party and we have assessed our other insurance brokerage options to confirm this belief. We have transitioned the majority of the aforementioned insurance underwriting requirements to a non-affiliated third party commercial insurance broker.
 
Crude Oil Purchases
 
We purchase a portion of our crude oil supplies from Legacy Resources Co., L.P. (“Legacy”), an exploration and production company owned in part by The Heritage Group, our chief executive officer and president, F. William Grube, and Jennifer G. Straumins, our senior vice president. The total purchases made by us from Legacy Resources in 2008 were approximately $140.2 million, which represented purchases based upon standard index-based, market rates.
 
In May 2008, the Company began purchasing all of its crude oil requirements for its Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy. Because Legacy is owned in part by one of the Company’s limited partners, an affiliate of our general partner, and our chief executive officer and president, F. William Grube, the terms of the agreement were reviewed by the conflicts committee of the board of directors of the Company’s general partner, which consists entirely of independent directors. The conflicts committee approved the agreement after determining that the terms of the agreement are fair and reasonable to the Company. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company is approximately 7,000 barrels per day.
 
On January 26, 2009, the Company entered into an additional crude oil supply agreement with Legacy. Under the agreement, it is contemplated that Legacy will supply the Company’s Shreveport refinery with a portion of its


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crude oil requirements that are received via common carrier pipeline. Pricing for the crude oil purchased under each confirmation will be mutually agreed to by the parties and set forth in such confirmation and will include a market-based premium as determined and agreed to by the parties. The agreement is effective as of January 26, 2009 and will continue to be in effect until terminated by either party by written notice. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company under this Agreement is up to 15,000 barrels per day.
 
Specialty Product Sales and Related Purchases
 
During 2008, we made ordinary course sales of certain specialty products to TruSouth Oil, LLC (“TruSouth”), a specialty petroleum packaging and distribution company owned in part by The Heritage Group, Calumet, Incorporated, Fred M. Fehsenfeld, Jr. (our chairman) as an individual, certain Fehsenfeld family trusts established where Mr. Fehsenfeld or his family members are the beneficiary, Janet K. Grube (the spouse of F. William Grube, our chief executive officer and president) individually, and certain Grube family trusts for which Janet K. Grube is sole trustee. The total sales made by us to TruSouth in 2008 were approximately $7.0 million. As of December 31, 2008 the balance due us from TruSouth related to these products sales was approximately $0.03 million. The total purchases made by us from TruSouth in 2008 for blending and packaging services were approximately $0.6 million. As of December 31, 2008 the balance due from us to TruSouth related to these purchases was approximately $0.02 million. We believe that the product sales prices and credit terms offered to TruSouth are comparable to prices and terms offered to non-affiliated third party customers.
 
During 2008, we made ordinary course sales of certain specialty products to Johann Haltermann, Ltd. (“Haltermann”), a specialty chemical company owned in part by The Heritage Group and certain Grube family trusts for which Janet K. Grube is sole trustee. The total sales made by us to Haltermann in 2008 were approximately $0.9 million. As of December 31, 2008 the balance due us from Haltermann related to these products sales was approximately $0.02 million. We anticipate that we will continue to sell products to Haltermann in the future. We believe that the product sales prices and credit terms offered to Haltermann are comparable to prices and terms offered to non-affiliated third party customers.
 
Procedures for Review and Approval of Related Person Transactions
 
Effective February 9, 2007, to further formalize the process by which related person transactions are analyzed and approved or disproved, the board of directors of our general partner has adopted the Calumet Specialty Products Partners, L.P. Related Person Transaction Policy (the “Policy”) to be followed in connection with all related person transactions (as defined by the Policy) involving the Partnership and its subsidiaries. The Policy was adopted to provide guidelines and procedures for the application of the partnership agreement to related person transactions and to further supplement the conflicts resolutions policies already set forth therein.
 
The Policy defines a “related person transaction” to mean any transaction since the beginning of the Partnership’s last fiscal year (or any currently proposed transaction) in which: (i) the Partnership or any of its subsidiaries was or is to be a participant; (ii) the amount involved exceeds $120,000 (including any series of similar transactions exceeding such amount on an annual basis); and (iii) any related person (as defined in the Policy) has or will have a direct or indirect material interest. Under the terms of the policy, our general partner’s chief executive officer (“CEO”) has the authority to approve a related person transaction (considering any and all factors as the CEO determines in his sole discretion to be relevant, reasonable or appropriate under the circumstances) so long as it is:
 
(a) in the normal course of the Partnership’s business;
 
(b) not one in which the CEO or any of his immediate family members has a direct or indirect material interest; and
 
(c) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or fair to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership).


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The CEO does not have the authority to approve the issuances of equity or grants of awards under the Partnership’s Long-Term Incentive Plan, except as provided in that plan. Pursuant to the Policy, any other related person transaction must be approved by the conflicts committee acting in accordance with the terms and provisions of its charter.
 
A copy of the Policy is available on our website at www.calumetspecialty.com and will be provided to unitholders without charge upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, IN 46214.
 
Please see Item 10 “Directors, and Executive Officers of Our General Partner and Corporate Governance” for a discussion of director independence matters.
 
Item 14.   Principal Accountant Fees and Services
 
The following table details the aggregate fees billed for professional services rendered by our independent auditor during 2008 and 2007.
 
                 
    Year Ended December 31,  
    2008     2007  
 
Audit fees
  $ 1,651,500     $ 1,803,000  
Audit related fees
    6,000       575,000  
Tax fees
           
All other fees
          1,500  
                 
Total
  $ 1,657,500     $ 2,379,500  
                 
 
Expenditures classified as “Audit fees” above include those related to our annual audit, audits of our general partner, quarterly review procedures and, in 2007, work performed in connection with our follow-on equity offering.
 
The audit committee of our general partner’s board of directors has adopted an audit committee charter, which is available on our website at www.calumetspecialty.com. The charter requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee. Services for the audit, tax and all other fee categories above were pre-approved by the audit committee.


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PART IV
 
Item 15.   Exhibits
 
(a)(2) Financial Statement Schedules
 
All schedules are omitted because they are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
 
(a)(3) Exhibits
 
The following documents are filed as exhibits to this Form 10-K:
 
             
Exhibit
       
Number
     
Description
 
  2 .1       Agreement with Respect to the Sale of Partnership Interests in Penreco, a Texas General Partnership, dated October 19, 2007, by and among ConocoPhillips Company and M.E. Zuckerman Specialty Oil Corporation, as Sellers, and Calumet Specialty Products Partners, L.P., as Purchaser (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed with the Commission on October 22, 2007 (File No 000-51734)).
  3 .1     Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 of 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)).
  10 .1     Credit Agreement dated as of January 3, 2008, by and among Calumet Lubricants Co., Limited Partnership, as Borrower, Calumet Specialty Products Partners, L.P., Calumet GP, LLC, Calumet Operating, LLC, and the Subsidiaries and Affiliates of the Borrower as Guarantors, the Lenders and Bank of America, N.A., as Administrative Agent and Credit-Linked L/C Issuer and Banc of America Securities LLC, as Sole Lead Arranger and Sole Book Manager (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
  10 .2     Amended and Restated ISDA Master Agreement and related Schedule and Credit Support Annex, dated as of January 3, 2008, between Calumet Lubricants Co., Limited Partnership and J. Aron & Company (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
  10 .3     Noncompetition Agreement, dated January 3, 2008, between ConocoPhillips Company and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
  10 .4     Noncompetition Agreement, dated January 3, 2008, between M.E. Zukerman Specialty Oil Corporation and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).


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Exhibit
       
Number
     
Description
 
  10 .5     Sixth Amendment, dated as of January 3, 2008, to Credit Agreement dated as of December 9, 2005 among Calumet Lubricants Co., Limited Partnership and certain of its affiliates, including Calumet Specialty Products Partners, L.P., as Borrowers, Bank of America, N.A. as agent for the Lenders, and the Lenders party thereto (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K/A filed with the Commission on January 10, 2008 (File No 000-51734)).
  10 .6     LVT Unit Agreement, effective January 1, 2008, between ConocoPhillips Company and Calumet Penreco, LLC (incorporated by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
  10 .7     LVT Feedstock Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
  10 .8     HDW Diesel Sale and Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
  10 .9     Amended Crude Oil Sale Contract, effective April 1, 2008, between Plains Marketing, L.P. and Calumet Shreveport Fuels, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on March 20, 2008 (File No 000-51734)).
  10 .10     Crude Oil Supply Agreement, dated as of April 30, 2008 and effective May 1, 2008, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on May 6, 2008 (File No 000-51734)).
  10 .11     Amendment No. 1 to Crude Oil Supply Agreement, dated as of November 25, 2008 and effective October 1, 2008, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on December 1, 2008 (File No 000-51734)).
  10 .12*     Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan, dated December 18, 2008 and effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K) filed with the Commission on December 22, 2008 (File No 000-51734).
  10 .13*     Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No 000-51734)).
  10 .14     Master Crude Oil Purchase and Sale Agreement, effective as of January 26, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on January 30, 2009 (File No 000-51734)).
  10 .15*     F. William Grube Employment Contract (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
  10 .16     Omnibus Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Registration Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
  10 .17*     Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement on Form S-1 (File No. 333-128880)).
  10 .18*     Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009.
  21 .1     List of Subsidiaries of Calumet Specialty Products Partners, L.P.
  23 .01     Consent of Ernst & Young, LLP, independent registered public accounting firm.
  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.
 
 
Identifies management contract and compensatory plan arrangements.

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SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) 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/  F. William Grube
F. William Grube,
President, Chief Executive
Officer and Director of Calumet GP, LLC
(Principal Executive Officer)
 
Date: March 3, 2009
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
Name
 
Title
 
Date
 
         
/s/  F. William Grube

F. William Grube
  President, Chief Executive Officer and Director of Calumet GP, LLC (Principal Executive Officer)   Date: March 3, 2009
         
/s/  Allan A. Moyes, III

Allan A. Moyes, III
  Executive Vice President of
Calumet GP, LLC
  Date: March 3, 2009
         
/s/  R. Patrick Murray, II

R. Patrick Murray, II
  Vice President, Chief Financial Officer and Secretary of Calumet GP, LLC (Principal Accounting and Financial Officer)   Date: March 3, 2009
         
/s/  Fred M. Fehsenfeld, Jr.

Fred M. Fehsenfeld, Jr.
  Director and Chairman of the Board of Calumet GP, LLC   Date: March 3, 2009
         
/s/  James S. Carter

James S. Carter
  Director of Calumet GP, LLC   Date: March 3, 2009
         
/s/  William S. Fehsenfeld

William S. Fehsenfeld
  Director of Calumet GP, LLC   Date: March 3, 2009
         
/s/  Robert E. Funk

Robert E. Funk
  Director of Calumet GP, LLC   Date: March 3, 2009
         
/s/  Nicholas J. Rutigliano

Nicholas J. Rutigliano
  Director of Calumet GP, LLC   Date: March 3, 2009
         
/s/  Michael L. Smith

Michael L. Smith
  Director of Calumet GP, LLC   Date: March 3, 2009


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Index to Exhibits
 
             
Exhibit
       
Number
     
Description
 
  2 .1       Agreement with Respect to the Sale of Partnership Interests in Penreco, a Texas General Partnership, dated October 19, 2007, by and among ConocoPhillips Company and M.E. Zuckerman Specialty Oil Corporation, as Sellers, and Calumet Specialty Products Partners, L.P., as Purchaser (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed with the Commission on October 22, 2007 (File No 000-51734)).
  3 .1     Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 of 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)).
  10 .1     Credit Agreement dated as of January 3, 2008, by and among Calumet Lubricants Co., Limited Partnership, as Borrower, Calumet Specialty Products Partners, L.P., Calumet GP, LLC, Calumet Operating, LLC, and the Subsidiaries and Affiliates of the Borrower as Guarantors, the Lenders and Bank of America, N.A., as Administrative Agent and Credit-Linked L/C Issuer and Banc of America Securities LLC, as Sole Lead Arranger and Sole Book Manager (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
  10 .2     Amended and Restated ISDA Master Agreement and related Schedule and Credit Support Annex, dated as of January 3, 2008, between Calumet Lubricants Co., Limited Partnership and J. Aron & Company (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
  10 .3     Noncompetition Agreement, dated January 3, 2008, between ConocoPhillips Company and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
  10 .4     Noncompetition Agreement, dated January 3, 2008, between M.E. Zukerman Specialty Oil Corporation and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
  10 .5     Sixth Amendment, dated as of January 3, 2008, to Credit Agreement dated as of December 9, 2005 among Calumet Lubricants Co., Limited Partnership and certain of its affiliates, including Calumet Specialty Products Partners, L.P., as Borrowers, Bank of America, N.A. as agent for the Lenders, and the Lenders party thereto (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K/A filed with the Commission on January 10, 2008 (File No 000-51734)).
  10 .6     LVT Unit Agreement, effective January 1, 2008, between ConocoPhillips Company and Calumet Penreco, LLC (incorporated by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.


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Exhibit
       
Number
     
Description
 
  10 .7     LVT Feedstock Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
  10 .8     HDW Diesel Sale and Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
  10 .9     Amended Crude Oil Sale Contract, effective April 1, 2008, between Plains Marketing, L.P. and Calumet Shreveport Fuels, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on March 20, 2008 (File No 000-51734)).
  10 .10     Crude Oil Supply Agreement, dated as of April 30, 2008 and effective May 1, 2008, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on May 6, 2008 (File No 000-51734)).
  10 .11     Amendment No. 1 to Crude Oil Supply Agreement, dated as of November 25, 2008 and effective October 1, 2008, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on December 1, 2008 (File No 000-51734)).
  10 .12*     Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan, dated December 18, 2008 and effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K) filed with the Commission on December 22, 2008 (File No 000-51734).
  10 .13*     Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No 000-51734)).
  10 .14     Master Crude Oil Purchase and Sale Agreement, effective as of January 26, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on January 30, 2009 (File No 000-51734)).
  10 .15*     F. William Grube Employment Contract (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
  10 .16     Omnibus Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Registration Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
  10 .17*     Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement on Form S-1 (File No. 333-128880)).
  10 .18*     Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009.
  21 .1     List of Subsidiaries of Calumet Specialty Products Partners, L.P.
  23 .01     Consent of Ernst & Young, LLP, independent registered public accounting firm.
  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.
 
 
Identifies management contract and compensatory plan arrangements.

178