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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, 2006
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   2911   37-1516132
 
(State or Other Jurisdiction of   (Primary Standard Industrial   (I.R.S. Employer
Incorporation or Organization)   Classification Code Number)   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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o     Accelerated filer o     Non-accelerated filer þ
 
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 $231.8 million on June 30, 2006, based on $31.73 per unit, the closing price of the common units as reported on the NASDAQ Global Market on such date.
 
At February 9, 2007, there were 16,366,000 common units and 13,066,000 subordinated units outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
NONE.
 


 

 
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-K — 2006 ANNUAL REPORT
 
Table of Contents
 
                 
        Page
 
  Business and Properties   4
  Risk Factors Related to Our Business   18
  Unresolved Staff Comments   34
  Legal Proceedings   34
  Submission of Matters to a Vote of Security Holders   34
 
  Market for the Registrant’s Common Equity, and Related Unitholder Matters and Issuer Purchases of Equity Securities   34
  Selected Financial and Operating Data   41
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   45
  Quantitative and Qualitative Disclosures About Market Risk   62
  Financial Statements   66
  Changes In and Disagreements With Accountants on Accounting and Financial Disclosure   110
  Controls and Procedures   110
  Other Information   110
 
  Directors, Executive Officers of Our General Partner and Corporate Governance   110
  Executive and Director Compensation   114
  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters   128
  Certain Relationships, Related Party Transactions and Director Independence   131
  Principal Accountant Fees and Services   134
 
  Exhibits   134
 Consent of Ernst & Young LLP
 Certification of F. William Grube Pursuant to Section 302
 Certification of R. Patrick Murray, II Pursuant to Section 302
 Certifications Pursuant to Section 1350


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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 expected completion date, the estimated cost, and the resulting increases in production levels, (ii) expected settlements with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental liabilities, and (iii) the probability of the achievement of a certain financial performance target related to executive compensation programs, 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. The risk factors and other factors noted throughout this 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 results of our hedging activities;
 
  •  the availability of, and our ability to consummate, acquisition or combination opportunities;
 
  •  our access to capital to fund expansions or acquisitions 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 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 crude oil price fluctuations;
 
  •  the impact of current and future laws, rulings and governmental regulations;
 
  •  shortages or cost increases of power supplies, natural gas, materials or labor;
 
  •  weather interference with business operations or project construction;
 
  •  fluctuations in the debt and equity markets; and
 
  •  general economic, market or business conditions.
 
Other factors described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read Item 1A “Risk Factors Related to Our Business” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk.” Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
 
References in this Form 10-K to “Calumet Specialty Products Partners,” “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


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and liabilities were contributed to Calumet Specialty Products Partners, L.P. and its subsidiaries. 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 Form 10-K to “our general partner” refer to Calumet GP, LLC.
 
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 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. For the year ended December 31, 2006, approximately 74.9% of our gross profit was generated from our specialty products segment and approximately 25.1% of our gross profit was generated from our fuel products segment.
 
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 7,574 bpd for the year ended December 31, 2006.
 
  •  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 7,130 bpd for the year ended December 31, 2006.
 
  •  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 42,000 bpd and had average daily crude oil throughput of 36,894 bpd for the year ended December 31, 2006.
 
  •  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 1,200 rail cars to receive crude oil or distribute our products throughout the United States and Canada. We also have approximately 4.5 million barrels of aggregate finished product storage capacity at our refineries.
 
Business Strategies
 
Our management team is dedicated to increasing the amount of cash available for distribution on each limited partner unit 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 74.9% of our gross profit for the year ended December 31, 2006 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. Historically, we have been able to reduce our exposure to crude oil price fluctuations in this segment through our ability to pass on


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  incremental feedstock costs to our specialty products customers and through our crude oil hedging program. In our fuel products business, we seek to mitigate our exposure to fuel margin volatility by maintaining a long-term hedging program. We believe the diversity of our products, our broad customer base and our hedging activities 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 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 to add new customers, we seek to limit our dependence on a small number of customers.
 
  •  Enhance profitability of our existing assets.  We will 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 increase the profitability of our acquired assets. We intend to further increase the profitability of our existing asset base through various measures which 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 from 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, scheduled for completion in the third quarter of 2007, to increase its aggregate crude oil throughput capacity to approximately 57,000 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.
 
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 250 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 refineries 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 800 companies and we are continually seeking new customers. From 1996 to December 31, 2006, we added an average of approximately 65 new specialty products customers per year, and for the year ended December 31, 2006 we added approximately 90 new specialty products customers. No single customer accounts for more that 10% of our specialty sales.


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  •  Our refineries have advanced technology.  Our refineries are equipped with advanced, flexible technology that allows us to produce high-grade specialty products and to produce gasoline and diesel products that comply with new fuel regulations. Our current gasoline production satisfies the 2006 low sulfur gasoline standard set by the Environmental Protection Agency (EPA), and our Shreveport and Cotton Valley refineries, as currently configured, have the processing capability to satisfy the 2006 ultra low sulfur diesel standard. 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 20 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, for accessing strategic acquisition opportunities and for constructing and enhancing the profitability of new assets.
 
Our Operating Assets
 
General
 
We own and operate refining assets in northwest Louisiana, which consist of: the Princeton refinery, the Cotton Valley refinery and the Shreveport refinery. We also own and operate a terminal in Burnham, Illinois.
 
The following table sets forth information about our combined refinery operations. Refinery production volume differs from sales volume due to changes in inventory.
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
 
Total sales volume (bpd)(1)
    50,345       46,953       24,658  
Total feedstock runs (bpd)(2)
    51,598       50,213       26,205  
Refinery production (bpd)
                       
Specialty products:
                       
Lubricating oils
    11,436       11,556       9,437  
Solvents
    5,361       4,422       4,973  
Waxes
    1,157       1,020       1,010  
Asphalt and other by-products
    6,596       6,313       5,992  
Fuels
    2,038       2,354       3,931  
                         
Total
    26,588       25,665       25,343  
                         
Fuel products:
                       
Gasoline
    9,430       8,278       3  
Diesel
    6,823       8,891       583  
Jet fuel
    6,911       5,080       342  
By-products
    461       417       26  
                         
Total
    23,625       22,666       954  
                         
Total refinery production(3)
    50,213       48,331       26,297  
                         
 
 
(1) Total sales volume includes sales from the production of our refineries and sales of inventories.


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(2) Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our refineries.
 
(3) Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our refineries. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of end products and volume loss.
 
Set forth below is information regarding sales contributed by our principal products.
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
    (In millions)  
 
Sales of specialty products:
                       
Lubricating oils
  $ 509.9     $ 394.4     $ 251.9  
Solvents
    201.9       145.0       114.7  
Waxes
    61.2       43.6       39.5  
Fuels
    41.3       44.0       72.7  
Asphalt and other by-products
    98.8       76.3       51.2  
                         
Total
  $ 913.1     $ 703.3     $ 530.0  
                         
Sales of fuel products:
                       
Gasoline
  $ 336.7     $ 223.6     $  
Diesel
    207.1       230.9       3.3  
Jet fuel
    176.4       121.3        
By-products
    7.7       10.0       6.3  
                         
Total
    727.9       585.8       9.6  
                         
Consolidated sales
  $ 1,641.0     $ 1,289.1     $ 539.6  
                         
 
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 or transported to the Shreveport refinery for further processing into ultra low sulfur diesel. 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.


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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. In addition, in 2004, we modified the crude and vacuum unit to improve fractionation and extend its useful life. The following table sets forth historical information about production at our Princeton refinery.
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
 
Crude oil throughput capacity (bpd)
    10,000       10,000       10,000  
Total feedstock runs (bpd)(1)
    7,574       8,067       8,062  
Refinery production (bpd):
                       
Lubricating oils
    5,085       5,463       5,390  
Fuels
    1,072       1,163       1,475  
Asphalt and other by-products
    1,386       1,356       1,363  
                         
Total refinery production(1)
    7,543       7,982       8,228  
                         
 
 
(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 feedstock and production of end 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 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 feedstock primarily originates from Texas and north Louisiana and is purchased from various marketers and gatherers. The Princeton refinery ships its finished products throughout the country by both truck and rail car 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 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 the Shreveport refinery. The Cotton Valley refinery produces the most complete, single-facility line of paraffinic solvents in the United States.


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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.
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
 
Crude oil throughput capacity (bpd)
    13,500       13,500       13,500  
Total feedstock runs (bpd)(1)(2)
    7,130       7,145       9,093  
Refinery production (bpd):
                       
Solvents
    5,361       4,422       4,973  
Asphalt and by-products
    1,393       1,473       2,330  
Fuels
    966       1,191       1,790  
                         
Total refinery production(2)
    7,720       7,086       9,093  
                         
 
 
(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 feedstock and production of end products and volume loss.
 
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 feedstock for solvent production from the Shreveport refinery. The Cotton Valley refinery ships finished products throughout the country by both truck and rail car service.
 
Shreveport Refinery
 
The Shreveport refinery, located on a 240-acre site in Shreveport, Louisiana, currently has aggregate crude oil throughput capacity of 42,000 bpd and is currently processing paraffinic crude oil and associated feedstocks into fuel products, paraffinic lubricating oils, waxes, residuals, and by-products.


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The Shreveport refinery currently consists of 15 major processing units, approximately 3.2 million barrels of storage capacity in 140 storage tanks and related loading and unloading facilities and utilities. Since its acquisition in 2001, we have expanded the refinery’s capabilities by adding additional processing and blending facilities and a second reactor to the high pressure hydrotreater. In addition, during the fourth quarter of 2004, we resumed production of gasoline, diesel and other fuel products at the refinery. The following table sets forth historical information about production at our Shreveport refinery.
 
                         
    Calumet     Predecessor  
    Years Ended December 31,  
    2006     2005     2004  
 
Crude oil throughput capacity (bpd)
    42,000       42,000       10,000  
Total feedstock runs (bpd)(1)
    36,894       35,342       8,956  
Refinery production (bpd):
                       
Fuels
    23,625       22,666       1,595  
Lubricating oils
    6,351       6,093       4,047  
Waxes
    1,157       1,020       1,010  
By-products
    3,817       3,483       2,325  
                         
Total refinery production(1)(2)
    34,950       33,262       8,977  
                         
 
 
(1) 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 feedstock and production of end products and volume loss.
 
(2) Total refinery production includes certain interplant solvent feedstocks supplied to our Cotton Valley refinery.
 
We commenced construction of an expansion project in the fourth quarter of 2006, scheduled for completion in the third quarter of 2007, to increase our Shreveport refinery’s aggregate crude oil throughput capacity to approximately 57,000 bpd. We received the air permit necessary to commence construction of the project in the fourth quarter of 2006. 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 fluctuates 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 will be 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, jet fuel and diesel 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 rail car service.


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Burnham Terminal and Other Logistics Assets
 
We own and operate a terminal in Burnham, Illinois.  The Burnham terminal receives specialty products exclusively 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.
 
We also lease a fleet of approximately 1,200 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 refineries.
 
Crude Oil and Feedstock Supply
 
We purchase crude oil from major oil companies as well as from various gatherers and marketers in Texas and north Louisiana. The Shreveport refinery can also receive 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.
 
For the year ended December 31, 2006, we purchased approximately 38.5% of our crude oil supply from a subsidiary of Plains under a term contract that expires in February 2008, 37.7% of our crude oil supply through evergreen crude oil supply contracts, which are typically terminable on 30 days’ notice by either party, and the remaining 23.8% of our crude oil supply on the spot market. We also purchase foreign crude oil when its spot market price is attractive relative to the price of crude oil from domestic sources. Due to the location of our refineries, 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, 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 price risk. Please read Item 7A “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” for a discussion of our crude oil hedging program.
 
Markets and Customers
 
We produce a full line of specialty products, including premium 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 over 15 years. Our salespeople regularly visit customers and our sales department works closely with the laboratories at the 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


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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.
 
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.
 
Although our refineries are located in northwest Louisiana, we have the capability to ship our specialty products worldwide. We ship via rail cars, trucks or barges in the United States and Canada. For the year ended December 31, 2006, about 42.1% of our specialty products were shipped in our fleet of approximately 1,200 leased rail cars with the remaining 57.9% of our specialty products shipped in trucks owned and operated by several different third-party carriers. We have the capability to ship large quantities via barge if necessary. For shipments outside of North America, which accounted for less than 10% of our consolidated sales in 2006, we can ship railcars to several ports where the product is loaded on a ship for delivery to a 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 the year ended December 31, 2006, we sold approximately 11,000 bpd of gasoline into the Louisiana, Texas and Arkansas markets, and we sold our 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 also sell the majority of our diesel fuel locally, but similar to gasoline, we occasionally sell the excess volumes to upstream marketers during times of high diesel production or for competitive reasons.
 
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 EPA.
 
The Shreveport refinery also has the capacity to produce about 7,000 bpd of commercial jet fuel that can be marketed to 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 make solvents. Jet fuel sales volumes change as the margin between diesel and jet fuel change. We have a sales contract with Barksdale for approximately 4,500 bpd of jet fuel. This contract is effective until April 2007 and is bid annually.
 
Additionally, we produce a number of fuel-related products including fluid catalytic cracking (“FCC”) feedstock, asphalt vacuum residual 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 rail car to other producers. FCC feedstock is sold to other refiners as a feedstock for their FCC units. Butanes are primarily available in the summer months and are primarily sold to local marketers. If the butane is not sold, it is blended into our gasoline production.
 
Customers
 
Specialty Products.  We have a diverse customer base for our specialty products, with approximately 800 active accounts. Most of our customers are long-term customers who use our products in specialty applications


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which require six months to two years to gain approval for use in their formulations. 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 63 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 option to ship our fuel products to the Midwest through the TEPPCO pipeline, should the need arise. No single customer of our fuel products segment account for more than 10% of our consolidated sales.
 
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 routine and required 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, record keeping 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 from time to time in industrial accidents. 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 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, on scales substantially larger than ours. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these segments. We distinguish our competitors according to the products that they produce. Set forth below is a description of our competitors according to products.
 
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 and Sunoco Lubricants & Special Products.
 
Paraffin Waxes.  Our primary competitors in producing paraffin waxes include Exxon Mobil and The International Group Inc.
 
Solvents.  Our 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.
 
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


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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 $0.2 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; and (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. We are currently in settlement negotiations with the LDEQ to resolve these matters, as well as a number of similar matters at the Princeton refinery, for which no penalty has yet been proposed. We expect that any penalties that may be assessed due to the alleged violations at our Princeton 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 in “— Air.”
 
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 review and periodic renewal. Aside from the alleged air violations discussed above 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


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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 has commenced production of diesel meeting the ultra low sulfur standard.
 
We recently have entered into 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 only in the beginning stages of discussion with the LDEQ and, consequently, while no significant compliance and enforcement expenditures have been requested as a result of the these discussions, we anticipate that we will ultimately 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.
 
In response to recent studies suggesting that emissions of certain gases may be contributing to warming of the Earth’s atmosphere, many foreign nations have agreed to limit emissions of these gases, generally referred to as “greenhouse gases,” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of fossil fuels, are examples of greenhouse gases. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills having already been introduced in the Senate that propose to restrict greenhouse gas emissions. By comparison, several states have already adopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhouse gases. Also, on November 29, 2006, the U.S. Supreme Court heard arguments on a case appealed from the U.S. Circuit Court of Appeals for the District Columbia, Massachusetts, et al. v. EPA, in which the appellate court held that the U.S. Environmental Protection Agency had discretion under the federal Clean Air Act to refuse to regulate carbon dioxide emissions from mobile sources. Passage of climate change legislation by Congress or a Supreme Court reversal of the appellate decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases. Also, any federal or state restrictions on emissions of greenhouse gases that may be imposed in areas of the United States in which we conduct business could adversely affect our operations and demand for our products.
 
On December 27, 2006, the LDEQ approved our application for a modification of our air emissions permit for the Shreveport refinery expansion. We were required to obtain approval of this modified air emissions permit from the LDEQ prior to commencing construction of the expansion activities. Upon receipt of the permit approval from the LDEQ, we have commenced construction of the Shreveport refinery expansion project. On February 22, 2007, we received notice that on February 13, 2007 an individual filed, on behalf of the “Residents for Air Neutralization,” a Petition for Review in the 19th Judicial District Court for East Baton Rouge Parish, Louisiana, asking the Court to review the approval granted by the LDEQ for our application for a modified air emissions permit. The Petition alleges the information in the final LDEQ decision report was inaccurate and that, based on the LDEQ’s decision to grant the modified air emissions permit, the LDEQ had not reviewed the evidence put before them properly. There is a question, unresolved at this time, concerning whether the Petition was timely filed. If it was timely filed, the LDEQ will have sixty days after service of the Petition to file the record of its proceedings with the district court. We believe that the LDEQ will be successful in defending its approval of our application for a modified air emissions permit. Neither we nor any of our subsidiaries is named at this time as a party to the Petition. For a further discussion of the expansion project, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.”


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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 can be no assurance that the future costs will not become material.
 
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.


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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 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.
 
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 the refineries, with 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 208-acre site of the Princeton refinery in Princeton, Louisiana, the 77-acre site of the Cotton Valley refinery in Cotton Valley, Louisiana and the 240-acre site of the Shreveport refinery in Shreveport, Louisiana. In addition, we own the 11-acre site of the Burnham terminal in Burnham, Illinois. Our properties are pledged as collateral under our credit facilities as discussed in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Debt and Credit Facilities.”
 
Office Facilities
 
In addition to our refineries and terminal discussed above, we occupy approximately 19,000 square feet of executive office space in Indianapolis, Indiana under a lease expiring in September 2011. 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.


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Employees
 
As of February 9, 2007, our general partner employs approximately 360 people who provide direct support to the Company’s operations. Of these employees, approximately 200 are covered by collective bargaining agreements. 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, 2008 and March 31, 2007, respectively. Employees at the Shreveport refinery are covered by a collective bargaining agreement with the Paper, Allied-Industrial, Chemical and Energy Workers International Union which expires as of April 30, 2007. None of the employees at the Burnham terminal are 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 Pkwy E. 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 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 Securities and Exchange Commission (“SEC”). The above information is available in print to anyone who requests it.
 
Item 1A.   Risk Factors Related to Our Business
 
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


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  •  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;
 
  •  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 losses and may not make cash distributions during periods when we record net income.
 
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.
 
Our financial results are primarily affected by the relationship, or margin, between our specialty products and fuel 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. Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. A widely used benchmark in the fuel products industry to measure market values and margins is the “3/2/1 crack spread,” which represents the approximate gross margin resulting from processing one barrel of 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 3/2/1 crack spread, as reported by Bloomberg L.P., averaged $3.04 per barrel between 1990 and 1999, $4.61 per barrel between 2000 and 2004, $10.63 per barrel in 2005, $8.68 per barrel in the first quarter of 2006, $15.75 per barrel in the second quarter of 2006, $10.92 per barrel in the third quarter of 2006 and $7.43 per barrel in the fourth quarter of 2006, and $10.70 for the year ended December 31, 2006. Our actual refinery 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. 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.
 
The price at which we sell specialty products, fuel and other refined products is strongly influenced by the commodity price of crude oil. If crude oil prices increase, our operating margins will fall unless we are able to pass along these price increases to our customers. Increases in selling prices typically lag the rising cost of crude oil for 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.


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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. Natural gas prices have historically been volatile.
 
For example, daily prices as reported on the New York Mercantile Exchange (“NYMEX”) ranged between $4.20 and $10.62 per million British thermal units, or MMBtu, in 2006 and between $5.79 and $15.39 per MMBtu in 2005. 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 42.3% and 45.6% of our total operating expenses included in cost of sales for the years ended December 31, 2006 and 2005, respectively.
 
Our hedging activities 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. 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.
 
Prior to 2006, we had not designated all of our derivative instruments as hedges in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. According to SFAS 133, changes in the fair value of derivatives which have not been designated as hedges are to be recorded each period in earnings and reflected in unrealized gain (loss) on derivative instruments in the consolidated statements of operations. For the years ended December 31, 2006, 2005 and 2004, these unrealized gains (losses) were $12.3 million, $(27.6) million, and $(7.8) million, respectively. On April 1, 2006, we designated certain derivative contracts that hedge the purchase of crude oil and sale of fuel products as cash flow hedges to the extent they qualify for hedge accounting. Subsequent to April 1, 2006, we designated certain derivatives related to crude oil and natural gas purchases and fuel product sales, and interest payments as cash flow hedges at the time of their execution. For derivatives designated as cash flow hedges, the change in fair value of these derivatives is reflected in accumulated other comprehensive income in the consolidated balance sheets. A total fair value of $52.3 million of these derivatives is reflected in accumulated other comprehensive income on the consolidated balance sheets as of December 31, 2006.
 
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 in our operations. Furthermore, 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. 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


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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, resulting 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 asset reconfiguration and enhancement initiatives, including the current expansion project at our Shreveport refinery, 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 the reconfiguration and enhancement of our refinery assets. As a specific current example, we have commenced construction of an expansion project at our Shreveport refinery to increase throughput capacity and crude oil processing flexibility. This construction project and the construction of other additions or modifications to our existing refineries involve numerous regulatory, environmental, political, legal 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. As a result, these projects may not be completed at the budgeted cost, on schedule, or at all.
 
We currently anticipate that our expansion project at the Shreveport refinery will cost approximately $150.0 million. We may suffer significant delays to the expected completion date or significant additional cost overruns as a result of increases in construction costs, shortages of workers or materials, transportation constraints, adverse weather, regulatory and permitting challenges, unforeseen difficulties or labor issues. Thus, construction to expand our Shreveport refinery or construction of other additions or modifications to our existing refineries may occur over an extended period of time and we may not receive any material increases in revenues and cash flows until the project is completed, if at all. Until the Shreveport expansion project is put into commercial service and increases our cash flow from operations on a per unit basis, we will be able to issue only 3,233,000 additional common units without obtaining unitholder approval, thereby limiting our ability to raise additional capital through the sale of common units. For further discussion of the Shreveport expansion project, please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.”
 
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 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 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 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 Texas and North Louisiana. For the year ended December 31, 2006, subsidiaries of Plains and Koch Supply and Trading, LP supplied us with approximately 50.6% and 23.5%, respectively, of our total crude oil supplies. Each of our refineries


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is dependent on one or both of these suppliers and the loss 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.”
 
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 most of its refined fuel products to customers, such as pipelines operated by subsidiaries of TEPPCO Partners, L.P. and Exxon Mobil. 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 feedstock 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;


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  •  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
 
  •  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 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 laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. 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 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 environmental 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.
 
We recently have entered into discussions on a voluntary basis with the LDEQ regarding our participation in that agency’s “Small Refinery and Single Site Refinery Initiative.” We are only in the beginning stages of discussion with the LDEQ and, consequently, while no specific compliance and enforcement expenditures have been requested as a result of our discussions, we anticipate that we will ultimately be required to make emissions reductions or other efforts requiring capital investments and increased operating expenditures that may be material.
 
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 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


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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 and terminal operations face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.
 
Our activities are conducted at three refineries in northwest Louisiana and a terminal in Illinois. These facilities are our principal operating assets. 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.
 
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,


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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 will reduce our revenues and cash available for distribution.
 
Our refineries 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 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 refineries 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.
 
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
 
We had total outstanding debt of $49.5 million as of December 31, 2006. We continue to have the ability to incur additional debt, including the ability to borrow up to $225.0 million under our senior secured revolving credit facility, subject to borrowing base limitations in the credit agreement. 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.


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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 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 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:
 
  •  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.
 
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.
 
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 (8.25% as of December 31, 2006). Borrowings under our term loan facility bear interest at a floating rate (8.85% as of December 31, 2006). The rates are subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) or prime rate. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow available for distribution to our unitholders. In addition, an increase in our interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.
 
Our business and operations could be adversely affected by terrorist attacks.
 
Since the September 11th terrorist attacks, the U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. The continued threat of terrorism and the impact of military and other actions will likely lead to increased volatility in prices for natural gas and oil and could affect the markets for our products. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse affect on our business. We do not carry any terrorism risk insurance.


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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 from the refineries we own. Furthermore, almost all 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 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 and in 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 2008, March 2007 and April 2007, respectively. 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.
 
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 62.7% 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 62.7% 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


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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, 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 and Related Party Transactions — 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.
 
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 to our partnership agreement;


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  •  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 did not elect our general partner or its board of directors, and will 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 were dissatisfied with the performance of our general partner, they will 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 initially to remove the general partner without its consent because the general partner and its affiliates will own sufficient units upon completion of the offering 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 64.0% 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.
 
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


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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.
 
During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 3,233,000 additional common units until the completion of the Shreveport refinery expansion project. If, upon completion, this project increases cash flow from operations per unit, our general partner may cause us to issue up to 6,533,000 of additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances described in our partnership agreement.
 
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.
 
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.


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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 and Related Party Transactions.”
 
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 35.2% 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 64.0% 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.
 
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.


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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 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 after this offering or changes in financial estimates by analysts;
 
  •  future sales of our common units; and
 
  •  the other factors described in Item 1A “Risk Factors” of our 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 entity-level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to 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, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our 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 common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the common 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. In addition, 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. If any of these states were to impose a tax on us, the cash available for distribution to common unitholders would be reduced. The partnership agreement provides that if a law is enacted or existing law


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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.
 
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
 
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 our counsel’s conclusions or 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 tax liability that results from that income.
 
Tax gain or loss on disposition of common units could be more or less than expected.
 
If a common unitholder sells his or her common units, he or she will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to a common unitholder in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in that common unit, even if the price is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if a common unitholder sells their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
 
Tax-exempt entities and foreign 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 individual retirement accounts 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.
 
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.


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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 to penalties for failure to comply with those requirements. We own assets and/or do business in Arkansas, California, Connecticut, Florida, Georgia, Indiana, Illinois, Kentucky, Louisiana, Massachusetts, Mississippi, Missouri, New Jersey, New York, Ohio, South Carolina, Pennsylvania, Texas, Utah and Virginia. 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.
 
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.
 
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. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. If this occurs, our unitholders will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to our unitholders with respect to that period.
 
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.


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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. During each quarter in the year ended December 31, 2006, identical cash distributions per unit were paid among all outstanding common and subordinated units.
 
                         
                Cash Distribution
 
    Low     High     per Unit  
 
Year ended December 31, 2006:
                       
First quarter(1)
  $ 21.70     $ 27.95     $ 0.30 (2)
Second quarter
  $ 27.11     $ 36.94     $ 0.45  
Third quarter
  $ 28.79     $ 32.58     $ 0.55  
Fourth quarter
  $ 29.80     $ 44.21     $ 0.60  
 
 
(1) Represents the period from January 26, 2006, the day our common units began trading on the NASDAQ, through March 31, 2006.
 
(2) Reflects the pro rata portion of the $0.45 quarterly distribution per unit paid, representing the period from the January 31, 2006 closing of our initial public offering through March 31, 2006.
 
As of February 9, 2007, there were approximately 14 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 9, 2007, there were 29,432,000 units outstanding. The number of units outstanding on this date includes the 13,066,000 subordinated units for which there is no established trading market. The last reported sale price of our common units by NASDAQ on February 9, 2007 was $44.89.
 
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


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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 14, 2007, we paid a quarterly cash distribution of $0.60 per unit on all outstanding units totaling $18.7 million for the quarter ended December 31, 2006 to all unitholders of record as of the close of business on February 4, 2007.
 
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 600,653 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 $0.3 million to our general partner in incentive distributions pursuant to its incentive distribution rights during the year ended December 31, 2006.
 
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.


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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 (which we define 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 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. As of the closing of our initial public offering, 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;
 
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  •  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;
 
  •  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 the partnership agreement.


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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.
 
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 that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;


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  •  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 from this initial public offering, 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 issued in our initial public offering 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.
 
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
 
The following table summarizes the purchases of equity securities by Calumet GP, LLC, the general partner of Calumet.
 
                                 
                Total Number of
       
                Common Units
    Maximum Number of
 
    Total Number of
          Purchased as a
    Common Units that
 
    Common Units
    Average Price Paid
    Part of Publicly
    May Yet be
 
    Purchased(1)     per Common Unit     Announced Plans     Purchased Under Plans  
 
On December 4, 2006
    1,824     $ 38.01              
                                 
Total
    1,824     $ 38.01              
                                 
 
 
(1) None of the common units were purchased pursuant to publicly announced plans or programs. The common units were purchased through a single broker in open market transactions. A total of 1,824 common units were purchased by Calumet GP, LLC, our general partner, related to the Calumet GP, LLC Long-Term Incentive Plan (the “Plan”). The Plan provides for the delivery of up to 783,960 common units to satisfy awards of phantom units, restricted units or unit options to the employees, consultants or directors of Calumet. Such units may be newly issued by Calumet or purchased in the open market. For more information on the Plan, which did not require approval by our limited partners, refer to Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation — Long-Term, Unit-Based Awards.”


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Item 6.  Selected Financial and Operating Data
 
The following table shows selected historical 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, 2005, 2004, 2003 and 2002 and for the years ended December 31, 2005, 2004, 2003 and 2002, are derived from the consolidated financial statements of the Predecessor. 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.
 
None of the assets or liabilities of the Predecessor’s Rouseville wax processing facility, Reno wax packaging facility and Bareco wax marketing joint venture, which are included in the historical financial statements, were contributed to us at the closing of the initial public offering on 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” of this Annual Report on Form 10-K except for operating data such as sales volume, feedstock runs and refinery 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,  
    2006     2005     2004     2003     2002  
    (In thousands)  
 
Summary of Operations Data:
                                       
Sales
  $ 1,641,048     $ 1,289,072     $ 539,616     $ 430,381     $ 316,350  
Cost of sales
    1,437,804       1,148,715       501,284       385,890       268,911  
                                         
Gross profit
    203,244       140,357       38,332       44,491       47,439  
Operating costs and expenses:
                                       
Selling, general and administrative
    20,430       22,126       13,133       9,432       9,066  
Transportation
    56,922       46,849       33,923       28,139       25,449  
Taxes other than income taxes
    3,592       2,493       2,309       2,419       2,404  
Other
    863       871       839       905       1,392  
Restructuring, decommissioning and asset impairments(1)
          2,333       317       6,694        
                                         
Total operating income (loss)
    121,437       65,685       (12,189 )     (3,098 )     9,128  
                                         
Other income (expense):
                                       
Equity in income (loss) of unconsolidated affiliates
                (427 )     867       2,442  
Interest expense
    (9,030 )     (22,961 )     (9,869 )     (9,493 )     (7,435 )
Interest income
    2,951       204       17              
Debt extinguishment costs
    (2,967 )     (6,882 )                  
Realized gain (loss) on derivative instruments
    (30,309 )     2,830       39,160       (961 )     1,058  
Unrealized gain (loss) on derivative instruments
    12,264       (27,586 )     (7,788 )     7,228        
Other
    (274 )     38       66       32       88  
                                         
Total other income (expense)
    (27,365 )     (54,357 )     21,159       (2,327 )     (3,847 )
                                         
Net income (loss) before income taxes
    94,072       11,328       8,970       (5,425 )     5,281  
Income tax expense
    190                          
                                         
Net income (loss)
  $ 93,882     $ 11,328     $ 8,970     $ (5,425 )   $ 5,281  
                                         


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    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004     2003     2002  
    (In thousands)  
 
Balance Sheet Data (at period end):
                                       
Property, plant and equipment, net
  $ 191,732     $ 127,846     $ 126,585     $ 89,938     $ 85,995  
Total assets
    530,174       399,717       318,206       216,941       217,915  
Accounts payable
    78,752       44,759       58,027       32,263       34,072  
Long-term debt
    49,500       267,985       214,069       146,853       141,968  
Partners’ capital
    378,685       39,054       34,514       25,544       30,968  
Cash Flow Data:
                                       
Net cash flow provided by (used in):
                                       
Operating activities
  $ 166,768     $ (34,001 )   $ (612 )   $ 7,048     $ (4,326 )
Investing activities
    (75,803 )     (12,903 )     (42,930 )     (11,940 )     (9,924 )
Financing activities
    (22,183 )     40,990       61,561       4,884       14,209  
Other Financial Data:
                                       
EBITDA
  $ 117,890     $ 51,557     $ 25,766     $ 10,837     $ 18,592  
Adjusted EBITDA
    104,458       85,821       34,711       6,110       16,277  
Operating Data (bpd):
                                       
Total sales volume(2)
    50,345       46,953       24,658       23,616       19,110  
Total feedstock runs(3)
    51,598       50,213       26,205       25,007       21,665  
Total refinery production(4)
    50,213       48,331       26,297       25,204       21,587  
 
 
(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.
 
(2) Total sales volume includes sales from the production of our refineries and sales of inventories.
 
(3) Feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our refineries.
 
(4) Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other refinery feedstocks at our refineries. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of end products and volume loss.
 
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.

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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 test thereunder. We are required to maintain a consolidated leverage ratio of consolidated debt to Adjusted EBITDA, after giving effect to any proposed distributions, of no greater than 3.75 to 1 in order to make distributions to our unitholders.
 
EBITDA and Adjusted EBITDA should not be considered alternatives to net income, operating incomenet 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 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,  
    2006     2005     2004     2003     2002  
    (In thousands)  
 
Reconciliation of net income to EBITDA and Adjusted EBITDA:
                                       
Net income (loss)
  $ 93,882     $ 11,328     $ 8,970     $ (5,425 )   $ 5,281  
Add:
                                       
Interest expense and debt extinguishment costs
    11,997       29,843       9,869       9,493       7,435  
Depreciation and amortization
    11,821       10,386       6,927       6,769       5,876  
Income tax expense
    190                          
                                         
EBITDA
  $ 117,890     $ 51,557     $ 25,766     $ 10,837     $ 18,592  
                                         
Add:
                                       
Unrealized losses (gains) from mark to market accounting for hedging activities
  $ (13,145 )   $ 27,586     $ 7,788     $ (7,228 )   $  
Non-cash impact of restructuring, decommissioning and asset impairments
          1,766       (1,276 )     2,250        
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays
    (287 )     4,912       2,433       251       (2,315 )
                                         
Adjusted EBITDA
  $ 104,458     $ 85,821     $ 34,711     $ 6,110     $ 16,277  
                                         
 


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    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004     2003     2002  
    (In thousands)  
 
Reconciliation of Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities:
                                       
Adjusted EBITDA
  $ 104,458     $ 85,821     $ 34,711     $ 6,110     $ 16,277  
Add:
                                       
Unrealized (losses) gains from mark to market accounting for hedging activities
    13,145       (27,586 )     (7,788 )     7,228        
Non-cash impact of restructuring, decommissioning and asset impairments
          (1,766 )     1,276       (2,250 )      
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays
    287       (4,912 )     (2,433 )     (251 )     2,315  
                                         
EBITDA
  $ 117,890     $ 51,557     $ 25,766     $ 10,837     $ 18,592  
                                         
Add:
                                       
Interest expense and debt extinguishment costs
    (11,997 )     (29,843 )     (9,869 )     (9,493 )     (7,435 )
Income taxes
    (190 )                        
Restructuring charge
          1,693             874        
Provision for doubtful accounts
    172       294       216       12       16  
Equity in (loss) income of unconsolidated affiliates
                427       (867 )     (2,442 )
Dividends received from unconsolidated affiliates
                3,470       750       2,925  
Debt extinguishment costs
    2,967       4,173                    
Changes in assets and liabilities:
                                       
Accounts receivable
    16,031       (56,878 )     (19,399 )     (4,670 )     (1,025 )
Inventory
    (2,554 )     (25,441 )     (20,304 )     15,547       (16,984 )
Other current assets
    16,183       569       (11,596 )     (563 )     1,295  
Derivative activity
    (13,143 )     31,598       5,046       (6,265 )     (3,682 )
Accounts payable
    33,993       (13,268 )     25,764       (1,809 )     9,587  
Accrued liabilities
    3,083       5,874       1,203       1,379       (2,622 )
Other, including changes in noncurrent assets and liabilities
    4,333       (4,329 )     (1,336 )     1,316       (2,551 )
                                         
Net cash provided by (used in) operating activities
  $ 166,768     $ (34,001 )   $ (612 )   $ 7,048     $ (4,326 )
                                         

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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”) when used in the present tense, prospectively or for historical periods since January 31, 2006 and Calumet Lubricants Co., Limited Partnership (“Predecessor”) for historical periods prior to January 31, 2006 where applicable. These historical consolidated financial statements include the results of operations of the Rouseville and Reno facilities, which have been closed. The following discussion analyzes the financial condition and results of operations of Calumet for the year ended December 31, 2006 and the Predecessor for the years ended December 31, 2005 and 2004. 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 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. Our business is organized into two segments: specialty products and fuel products. In our specialty products segment, we process crude oil 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. The asphalt and other by-products produced in connection with the production of specialty products at the 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 the Shreveport refinery are included in our fuel products segment. The fuels produced in connection with the production of specialty products at the Princeton and Cotton Valley refineries are included in our specialty products segment. For the year ended December 31, 2006, approximately 74.9% of our gross profit was generated from our specialty products segment and approximately 25.1% of our gross profit was generated from our fuel products segment.
 
Subsequent to the acquisition of the Shreveport refinery, our Predecessor streamlined its wax processing and marketing operations by decommissioning its Rouseville facility, closing its Reno facility and terminating its Bareco wax marketing joint venture. None of the assets or liabilities of our Predecessor’s Rouseville facility, Reno facility or Bareco joint venture were contributed to Calumet Specialty Products Partners, L.P. in connection with the closing of our initial public offering on January 31, 2006. Our Predecessor began decommissioning the Rouseville facility in 2003 and completed the decommissioning in 2005. This resulted in restructuring costs of $6.7 million in 2003 and $0.3 million in 2004. In 2005, our Predecessor closed the Reno facility for a restructuring and decommissioning cost of $2.2 million. The combined net book value of the Reno and Rouseville operations was not included within the net assets contributed to Calumet by our Predecessor, and therefore are not included within our results of operations subsequent to January 31, 2006.
 
Our fuel products segment began operations in 2004, as we substantially completed the approximately $39.7 million reconfiguration of the Shreveport refinery to add motor fuels production, including gasoline, diesel and jet fuel, to its existing specialty products slate as well as to increase overall feedstock throughput. The project was fully completed in February 2005. The reconfiguration was undertaken to capitalize on strong fuels refining margins, or crack spreads, relative to historical levels, to utilize idled assets, and to enhance the profitability of the Shreveport refinery’s specialty products segment by increasing overall refinery throughput. We have commenced construction of an expansion project at our Shreveport refinery to increase throughput capacity and feedstock flexibility. Please read “Liquidity and Capital Resources — Capital Expenditures” below.
 
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.


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Our primary raw material is crude oil and our primary outputs are specialty petroleum and fuel products. The prices of crude oil, specialty 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 sales of fuel products. Please read Item 7A “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” As of December 31, 2006, we have hedged 28.8 million barrels of fuel products selling prices through December 2011 at an average refining margin of $12.00 per barrel and average refining margins range from a low of $9.13 in 2011 to a high of $12.66 in the third and fourth quarters of 2007. 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 hedge positions.
 
Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:
 
  •  Sales volumes;
 
  •  Production yields; and
 
  •  Specialty products and fuel products gross profit.
 
Sales volumes.  We view the volumes of specialty 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 refineries. 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 in order to maximize our gross profits and minimize lower margin by-products which we refer to as production yield.
 
Specialty products and fuel products gross profit.  Specialty products and fuel products gross profit are an important measure 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, fuel, utilities, contract services, maintenance and processing materials. We use specialty products and fuel products gross profit as an indicator 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 the maintenance and turnaround activities performed during a specific period. Maintenance expense includes accruals for turnarounds and other maintenance expenses.
 
In addition to the foregoing measures, we also monitor our general and administrative expenditures, substantially all of which are incurred through our general partner, Calumet GP, LLC.


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Results of Operations
 
The following table sets forth information about our combined refinery operations. Refinery production volume differs from sales volume due to changes in inventory.
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
 
Total sales volume (bpd)(1)
    50,345       46,953       24,658  
Total feedstock runs (bpd)(2)
    51,598       50,213       26,205  
Refinery production (bpd)(3):
                       
Specialty products:
                       
Lubricating oils
    11,436       11,556       9,437  
Solvents
    5,361       4,422       4,973  
Waxes
    1,157       1,020       1,010  
Asphalt and other by-products
    6,596       6,313       5,992  
Fuels
    2,038       2,354       3,931  
                         
Total
    26,588       25,665       25,343  
                         
Fuel products:
                       
Gasoline
    9,430       8,278       3  
Diesel
    6,823       8,891       583  
Jet fuel
    6,911       5,080       342  
By-products
    461       417       26  
                         
Total
    23,625       22,666       954  
                         
Total refinery production
    50,213       48,331       26,297  
                         
 
 
(1) Total sales volume includes sales from the production of our refineries and sales of inventories.
 
(2) Feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our refineries.
 
(3) Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other refinery feedstocks at our refineries. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of end products and volume loss.


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The following table sets forth information about the sales of our principal products.
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
    (In millions)  
 
Specialty products:
                       
Lubricating oils
  $ 509.9     $ 394.4     $ 251.9  
Solvents
    201.9       145.0       114.7  
Waxes
    61.2       43.6       39.5  
Fuels
    41.3       44.0       72.7  
Asphalt and other by-products
    98.8       76.3       51.2  
                         
Total
    913.1       703.3       530.0  
                         
Fuel products:
                       
Gasoline
    336.7       223.6        
Diesel
    207.1       230.9       3.3  
Jet fuel
    176.4       121.3        
By-products
    7.7       10.0       6.3  
                         
Total
    727.9       585.8       9.6  
                         
Consolidated sales
  $ 1,641.0     $ 1,289.1     $ 539.6  
                         


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The following table reflects our consolidated results of operations.
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
    (In millions)  
 
Sales
  $ 1,641.0     $ 1,289.1     $ 539.6  
Cost of sales
    1,437.8       1,148.7       501.3  
                         
Gross profit
    203.2       140.4       38.3  
                         
Operating costs and expenses:
                       
Selling, general and administrative
    20.4       22.1       13.1  
Transportation
    56.9       46.9       34.0  
Taxes other than income taxes
    3.6       2.5       2.3  
Other
    0.9       0.9       0.8  
Restructuring, decommissioning and asset impairments
          2.3       0.3  
                         
Operating income (loss)
    121.4       65.7       (12.2 )
                         
Other income (expense):
                       
Equity in loss of unconsolidated affiliates
                (0.4 )
Interest expense
    (9.0 )     (23.0 )     (9.9 )
Interest income
    3.0       0.2        
Debt extinguishment costs
    (3.0 )     (6.9 )      
Realized gain (loss) on derivative instruments
    (30.3 )     2.8       39.2  
Unrealized gain (loss) on derivative instruments
    12.3       (27.6 )     (7.8 )
Other
    (0.3 )     0.1       0.1  
                         
Total other income (expense)
    (27.3 )     (54.4 )     21.2  
Net income before income taxes
    94.1       11.3       9.0  
Income tax expense
    (0.2 )            
                         
Net income
  $ 93.9     $ 11.3     $ 9.0  
                         


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Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
 
Sales.  Sales increased $352.0 million, or 27.3%, to $1,641.0 million in the year ended December 31, 2006 from $1,289.1 million in the year ended December 31, 2005. Sales for each of our principal product categories in these periods were as follows:
 
                         
    Calumet     Predecessor        
    Year Ended December 31,  
    2006     2005     % Change  
    (Dollars in millions)  
 
Sales by segment:
                       
Specialty products:
                       
Lubricating oils
  $ 509.9     $ 394.4       29.3 %
Solvents
    201.9       145.0       39.3 %
Waxes
    61.2       43.6       40.2 %
Fuels(1)
    41.3       44.0       (6.2 )%
Asphalt and by-products(2)
    98.8       76.3       29.6 %
                         
Total specialty products
    913.1       703.3       29.9 %
                         
Total specialty products sales volume (in barrels)
    9,165,000       8,900,000       3.0 %
Fuel products:
                       
Gasoline
  $ 336.7     $ 223.6       50.6 %
Diesel
    207.1       230.9       (10.3 )%
Jet fuel
    176.4       121.3       45.4 %
By-products(3)
    7.7       10.0       (23.1 )%
                         
Total fuel products
    727.9       585.8       24.2 %
                         
Total fuel products sales volumes (in barrels)
    9,211,000       8,238,000       11.8 %
Total sales
  $ 1,641.0     $ 1,289.1       27.3 %
                         
Total sales volumes (in barrels)
    18,376,000       17,138,000       7.2 %
                         
 
 
(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 $352.0 million increase in sales resulted from a $209.9 million increase in sales by the specialty products segment and a $142.0 increase in sales in the fuel products segment.
 
Specialty products segment sales for the year ended December 31, 2006 increased $209.9 million, or 29.9%, primarily due to a 26.1% increase in the average selling price per barrel across all product lines and a more favorable product mix of lubricating oils and solvents. Average selling prices per barrel for lubricating oils, solvents, waxes, fuels, and asphalt and by-product increased at rates comparable to or in excess of the overall 15.6% increase in the cost of crude oil per barrel during the period. In addition, specialty products segment sales were positively affected by a 3.0% increase in volumes sold, from approximately 8.9 million barrels in the year ended December 31, 2005 to 9.2 million barrels in the year ended December 31, 2006 due to increased sales volumes for lubricating oils and solvents, partially offset by decreased sales volume of fuels.
 
Fuel products segment sales for the year ended December 31, 2006 increased $142.0 million, or 24.2%, partially due to an 11.1% increase in the average selling price per barrel. Average selling prices per barrel for gasoline, diesel, jet fuel, and by-products increased at rates comparable to or less than the overall 15.2% increase in the cost of crude oil per barrel for the period due to market conditions. The fuel products segment sales were also


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positively affected by an 11.8% increase in volumes sold attributable to the ramp-up of the fuels operations at the Shreveport refinery in the first quarter of 2005. The settlement of our fuel products cash flow hedges had an immaterial impact on fuel products segment sales for the year ended December 31, 2006.
 
Gross Profit.  Gross profit increased $62.9 million, or 44.8%, to $203.2 million for the year ended December 31, 2006 from $140.4 million for the year ended December 31, 2005. Gross profit for our specialty and fuel products segments were as follows:
 
                         
    Calumet     Predecessor        
    Year Ended December 31,  
    2006     2005     % Change  
    (Dollars in millions)  
 
Gross profit by segment:
                       
Specialty products
  $ 152.3     $ 73.3       107.9 %
Percentage of sales
    16.7 %     10.4 %        
Fuel products
  $ 50.9     $ 67.1       (24.1 )%
Percentage of sales
    7.0 %     11.5 %        
Total gross profit
  $ 203.2     $ 140.4       44.8 %
Percentage of sales
    12.4 %     10.9 %        
 
This $62.9 million increase in total gross profit includes an increase in gross profit of $79.1 million in the specialty products segment offset by a $16.2 million decrease in the fuel products segment.
 
The increase in the specialty products segment gross profit was primarily due the average selling price per barrel increasing by 26.1%, which was more than the increase in the average cost of crude oil of 15.6% during the period. This was primarily driven by price increases across all product lines and a more favorable product mix of lubricating oils and solvents. Specialty products segment gross profit was also positively affected by 3.0% increase in sales volumes, primarily driven by solvents and waxes. The sales price and volume increases were partially offset by the recognition of $9.4 million of derivative losses on our cash flow hedges of crude oil and natural gas purchases reflected in cost of sales in the consolidated statements of operations. The segment gross profit was also positively affected by lower operating costs due to lower costs for plant fuel and maintenance.
 
The decrease in the fuel products segment gross profit of $16.2 million was primarily the result of the average selling price increasing by 11.1%, which was less than the increase in the average cost of crude of 15.2%. Fuel products segment gross profit was also negatively impacted by approximately $13.4 million due primarily to increases in other material costs from the use of certain gasoline blendstocks in the third and fourth quarter of 2006 to maintain compliance with environmental regulations. The Company does not believe it will be necessary to purchase such gasoline blendstocks in 2007. Further contributing to the decrease in segment gross profit was the recognition of $1.7 million of derivative losses from our cash flow hedges of fuel products sales and crude oil purchases. These decreases were partially offset by an 11.8% increase in sales volumes, primarily in gasoline and jet fuel.
 
Selling, general and administrative.  Selling, general and administrative expenses decreased $1.7 million, or 7.7%, to $20.4 million in the year ended December 31, 2006 from $22.1 million in the year ended December 31, 2005. This decrease primarily reflects decreased employee compensation costs due to incentive bonuses. This decrease was offset by increased general and administrative costs incurred as a result of being a public company.
 
Transportation.  Transportation expenses increased $10.1 million, or 21.5%, to $56.9 million in the year ended December 31, 2006 from $46.8 million in the year ended December 31, 2005. The increase in transportation expense over the period is due to significant price increases for rail transportation services as well as the 3.0% increase in volumes for the specialty products segment for the year ended December 31, 2006 compared to the same period in 2005.
 
Restructuring, decommissioning and asset impairments.  Restructuring, decommissioning and asset impairment expenses were $2.3 for the year ended December 31, 2005, and we incurred no such expenses in 2006. The charges recorded in 2005 related to decommissioning and asset impairment costs of the Reno wax packaging assets. No other assets impairments have occurred in 2006.


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Interest expense.  Interest expense decreased $13.9 million, or 60.7%, to $9.0 million in the year ended December 31, 2006 from $23.0 million in the year ended December 31, 2005. This decrease was primarily due to the debt refinancing in December 2005 and the repayment of debt with the proceeds of the initial public offering and follow-on equity offering, which closed on January 31, 2006 and July 5, 2006, respectively.
 
Interest income.  Interest income increased $2.7 million to $3.0 million in the year ended December 31, 2006 from $0.2 million in the year ended December 31, 2005. This increase was primarily due to the investment of the remaining proceeds from our follow-on equity offering, which closed on July 5, 2006, after the pay down of indebtedness. The Predecessor did not have significant cash or cash equivalent balances during 2005.
 
Debt extinguishment costs.  Debt extinguishment costs decreased to $3.0 million for the year ended December 31, 2006 compared to $6.9 million for the year ended December 31, 2005. The $6.9 million recognized in the year ended December 31, 2005 is the result of the repayment of existing credit facilities in the fourth quarter of 2005 using the proceeds of credit agreements entered into in that same period. For the year ended December 31, 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 gain (loss) on derivative instruments.  Realized loss on derivative instruments increased $33.1 million to a $30.3 million loss in the year ended December 31, 2006 from a $2.8 million gain in the year ended December 31, 2005. This increased loss primarily was the result of the unfavorable settlement of crude oil and fuel products margin derivative contracts, which experienced decreases in market value due to rising crack spreads upon their settlement during the year ended December 31, 2006 as compared to 2005.
 
Unrealized gain (loss) on derivative instruments.  Unrealized gain (loss) on derivative instruments increased $39.9 million, to a $12.3 million gain in the year ended December 31, 2006 from a $27.6 million loss for the year ended December 31, 2005. This increase is primarily due to the entire mark to market change of our derivative instruments being recorded to unrealized loss on derivative instruments in the prior year. Calumet designated certain of these derivatives as cash flow hedges on April 1, 2006 and has subsequently recorded the mark to market change on the effective portion of these hedges to accumulated other comprehensive income on the consolidated balance sheet.


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Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
 
Sales.  Sales increased $749.5 million, or 138.9%, to $1,289.1 million in the year ended December 31, 2005 from $539.6 million in the year ended December 31, 2004. Sales for each of our principal product categories in these periods were as follows:
 
                         
    Calumet     Predecessor        
    Year Ended December 31,  
    2005     2004     % Change  
    (Dollars in millions)  
 
Sales by segment:
                       
Specialty products:
                       
Lubricating oils
  $ 394.4     $ 251.9       56.6 %
Solvents
    145.0       114.7       26.4 %
Waxes
    43.6       39.5       10.4 %
Fuels(1)
    44.0       72.7       (39.5 )%
Asphalt and by-products(2)
    76.3       51.2       48.8 %
                         
Total specialty products
    703.3       530.0       32.7 %
                         
Total specialty products volume (in barrels)
    8,900,000       8,807,000       1.1 %
Fuel products:
                       
Gasoline
  $ 223.6     $        
Diesel
    230.9       3.3       6,885.7 %
Jet fuel
    121.3              
By-products(3)
    10.0       6.3       59.0 %
                         
Total fuel products
    585.8     $ 9.6       5,998.2 %
                         
Total fuel products sales volumes (in barrels)
    8,238,000       193,000       4,168.4 %
Total sales
  $ 1,289.1     $ 539.6       138.9 %
                         
Total sales volumes (in barrels)
    17,138,000       9,000,000       90.4 %
                         
 
 
(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 $749.5 million increase in sales resulted primarily from the startup of our fuels operations at Shreveport in the fourth quarter of 2004, which accounted for $576.2 million of the increase, and also from a $173.3 million increase in sales by our specialty products segment.
 
Specialty products segment sales for 2005 increased $173.3 million, or 32.7%, due to a 31.3% increase in the average selling price per barrel and a 1.1% increase in volumes sold, from approximately 8.8 million barrels in 2004 to 8.9 million barrels in 2005. Average selling prices per barrel for lubricating oils, solvents and fuels increased at rates comparable to or in excess of the overall 30.9% increase in the cost of crude oil per barrel during the period. Asphalt and by-product prices per barrel increased by only 7.4% due to market conditions. The slight increase in volumes sold was largely due to higher production volumes offset by downtime in February 2005 at Cotton Valley for a plant expansion project, which resulted in reduced volumes of fuels and solvents for that period. Fuel sales decreased disproportionately more than solvents because we had higher levels of inventory of solvents at Cotton Valley available for sale.


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Fuel products segment sales for 2005 increased $576.2 million which is attributable to the reconfiguration of the Shreveport refinery, which was fully completed by February 2005, and the start-up of our fuel products segment in the fourth quarter of 2004.
 
Gross Profit.  Gross profit increased $102.0 million, or 266.2%, to $140.4 million for the year ended December 31, 2005 from $38.3 million for year ended December 31, 2004. Gross profit for our specialty and fuel products segments were as follows:
 
                         
    Calumet     Predecessor        
    Year Ended December 31,  
    2005     2004     % Change  
    (Dollars in millions)  
 
Gross profit by segment:
                       
Specialty products
  $ 73.3     $ 40.6       80.5 %
Percentage of sales
    10.4 %     7.7 %        
Fuel products
  $ 67.1     $ (2.3 )      
Percentage of sales
    11.5 %     (24.1 )%        
Total gross profit
  $ 140.4     $ 38.3       266.2 %
Percentage of sales
    10.9 %     7.1 %        
 
This $102.0 million increase in total gross profit includes an increase in gross profit of $69.4 million in our fuel products segment, which began operations late in 2004, and an increase of $32.7 million in our specialty product segment gross profit which was driven by a 31.3% increase in selling prices and improved profitability on specialty products manufactured at our Shreveport refinery due to the increase in the refinery’s overall throughput largely resulting from its reconfiguration. The increase in specialty products gross profit was offset by a 30.9% increase in the average price of crude oil per barrel. During 2005, we were able to successfully increase prices on our lubricating oils, solvents and fuels at rates comparable to or in excess of the rising cost of crude oil.
 
Selling, general and administrative.  Selling, general and administrative expenses increased $9.0 million, or 68.5%, to $22.1 million in the year ended December 31, 2005 from $13.1 million in the year ended December 31, 2004. This increase primarily reflects increased employee compensation costs due to incentive bonuses.
 
Transportation.  Transportation expenses increased $12.9 million, or 38.1%, to $46.8 million in the year ended December 31, 2005 from $33.9 million in the year ended December 31, 2004. The year over year increase in transportation expense was due to the overall increase in volumes which was partially offset by more localized marketing of fuels products.
 
Restructuring, decommissioning and asset impairments.  Restructuring, decommissioning and asset impairment expenses increased $2.0 million to $2.3 million in the year ended December 31, 2005 from $0.3 million in the year ended December 31, 2004. During 2005, we recorded a $2.2 million charge related to decommissioning and asset impairment costs of the Reno wax packaging assets. During 2004, we recorded a $0.3 million charge related to the completion of the Rouseville asset decommissioning.
 
Interest expense.  Interest expense increased $13.1 million, or 132.7%, to $23.0 million in the year ended December 31, 2005 from $9.9 million in the year ended December 31, 2004. This increase was primarily due to our debt refinancing and increased borrowings under our prior credit agreements for the reconfiguration of the Shreveport facility entered into during the fourth quarter of 2004. Borrowings under the prior term loan agreement incurred interest at a fixed rate of interest of 14.0%.
 
On December 9, 2005, we repaid our existing facilities from the proceeds of our current credit agreements described later in this section. This resulted in debt extinguishment costs of $6.9 million being recorded in the fourth quarter.
 
Realized gain on derivative instruments.  Realized gain on derivative instruments decreased $36.3 million to $2.8 million in the year ended December 31, 2005 from $39.2 million in the year ended December 31, 2004. This decrease was primarily the result of the unfavorable settlement of crude oil and fuel products margin derivative


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contracts, which experienced decreases in market value upon settlement during the year ended December 31, 2005 as compared to 2004.
 
Unrealized loss on derivative instruments.  Unrealized loss on derivative instruments increased $19.8 million, to $27.6 million in the year ended December 31, 2005 from $7.8 million for the year ended December 31, 2004. This increased loss is primarily due to the decline in fair value on a larger volume of crude oil and fuel products margin derivative contracts due to increased crack spreads as of December 31, 2005.
 
Liquidity and Capital Resources
 
Our principal sources of cash have included proceeds from public offerings, issuance of private debt, bank borrowings, and cash flow from operations. Principal historical uses of cash have included capital expenditures, growth in working capital, distributions and debt service. We expect that our principal uses of cash in the future will be to finance working capital, capital expenditures, distributions and debt service.
 
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, 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 would likely produce a corollary materially adverse effect on our borrowing capacity.
 
The following table summarizes our primary sources and uses of cash in the periods presented:
 
                         
    Calumet     Predecessor        
    Year Ended December 31,  
    2006     2005     2004  
    (Dollars in millions)  
 
Net cash provided by (used in) operating activities
  $ 166.8     $ (34.0 )   $ (0.6 )
Net cash used in investing activities
  $ (75.8 )   $ (12.9 )   $ (42.9 )
Net cash provided by (used in) financing activities
  $ (22.2 )   $ 41.0     $ 61.6  
 
Operating Activities.  Operating activities provided $166.8 million in cash during the year ended December 31, 2006 compared to using $34.0 million in cash during the year ended December 31, 2005. The cash provided by operating activities during the year ended December 31, 2006 primarily consisted of net income after adjusting for non-cash items of $108.9 million and $57.8 million of working capital improvements. Net income after adjustments for non-cash items increased to $108.9 million in 2006 from $28.1 million in 2005 primarily due to an increase in net income of $82.6 million. The improvements in working capital were primarily due to a $34.0 million increase in accounts payable due to improvements in payment terms with suppliers and the issuance of letters of credit, a $29.7 million decrease in current assets primarily due to lower accounts receivable as a result of decreased sales volume in the fourth quarter of 2006 as compared to the same period in 2005 and lower prepaid expenses driven by decreased prepaid crude oil purchases.
 
Operating activities used $34.0 million of cash for the year ended December 31, 2005 compared to using $0.6 million of cash for the year ended December 31, 2004. This increase is primarily due to increases in accounts receivable of $56.9 million and inventory of $25.4 million, which relate to the rising price of crude oil and the increase in throughput in our fuel products segment as the Shreveport reconfiguration was completed in February 2005. The increase was also driven by the decrease in accounts payable which relates to the timing of payments and the increase in purchases from suppliers who required shorter payment terms. The increase was partially offset by the mark to market impact of derivative instruments.
 
Investing Activities.  Cash used in investing activities increased to $75.8 million during the year ended December 31, 2006 as compared to $12.9 million during the year ended December 31, 2005. This increase was primarily due to the $65.5 million of additions to property, plant and equipment related to the Shreveport refinery expansion project during 2006, with no comparable expenditures in 2005. In 2005, capital expenditures primarily consisted of an upgrade to the capacity and enhancement of the product mix at our Cotton Valley refinery.


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In 2004, capital expenditures were primarily due to $36.0 million of additions related to the fuels reconfiguration at our Shreveport refinery.
 
Financing Activities.  Financing activities used cash of $22.2 million for the year ended December 31, 2006 compared to providing $41.0 million for the year ended December 31, 2005. This decrease is primarily due to the use of cash from operations to make distributions to partners of $45.2 million. In addition, we used all of the proceeds of our initial public offering and a portion of the proceeds of our follow-on public offering to paydown debt during the year ended December 31, 2006. The remaining proceeds from our follow-on public offering were invested in highly liquid short-term investments and will be utilized as needed to fund the Shreveport refinery expansion project.
 
Cash provided by financing activities decreased to $41.0 million for the year ended December 31, 2005 compared to $61.6 million for the year ended December 31, 2004. This decrease is primarily due to distributions to our partners of $7.3 million and increased borrowings in 2004 to finance the growth in working capital related to the startup of fuel products operations at Shreveport.
 
On January 5, 2007, the Company declared a quarterly cash distribution of $0.60 per unit on all outstanding units, or $18.7 million, for the quarter ended December 31, 2006. The distribution will be paid on February 14, 2007 to unitholders of record as of the close of business on February 4, 2007. This quarterly distribution of $0.60 per unit equates to $2.40 per unit, or $74.7 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. We expense all maintenance costs associated with major maintenance and repairs (facility turnarounds) through the accrue-in-advance method over the period between turnarounds. The accounting method used for facility turnarounds will change effective January 1, 2007 as discussed below in “— Recent Accounting Prounouncements.”
 
The following table sets forth our capital improvement expenditures, replacement capital expenditures and environmental expenditures.
 
                         
    Calumet     Predecessor        
    Year Ended December 31,  
    2006     2005     2004  
    (Dollars in millions)  
 
Capital improvement expenditures
  $ 69.9     $ 10.1     $ 39.0  
Replacement capital expenditures
  $ 4.5     $ 2.2       2.6  
Environmental expenditures
  $ 1.7     $ 0.7       1.4  
                         
Total
  $ 76.1     $ 13.0     $ 43.0  
                         
 
We anticipate that future capital improvement requirements will be provided through long-term borrowings, other debt financings, equity offerings and/or cash on hand. Until the Shreveport refinery expansion project is complete and increases cash flow from operations per unit, as discussed in Item 1A “Risk Factors,” our ability to raise additional capital through the sale of common units is limited to 3,233,000 common units.
 
Capital improvement expenditures for the year ended December 31, 2006 were primarily related to an expansion project at our Shreveport refinery to increase its throughput capacity and its production of specialty products. The expansion project involves several of the refinery’s operating units and is estimated to result in a crude oil throughput capacity increase of approximately 15,000 bpd, bringing total crude oil throughput capacity of the refinery to approximately 57,000 bpd. The expansion is expected to be completed and fully operational in the third quarter of 2007.


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As part of the Shreveport refinery expansion project, we plan to increase the Shreveport refinery’s capacity to process an additional 8,000 bpd of sour crude oil, bringing total capacity to process sour crude oil to 13,000 bpd. Of the anticipated 57,000 bpd throughput rate upon completion of the expansion project, we expect the refinery to have the capacity to process approximately 42,000 bpd of sweet crude oil and 13,000 bpd of sour crude oil, with the remainder coming from interplant feedstocks.
 
During the second quarter of 2006, we began purchasing equipment for the Shreveport expansion project and have spent a total of $65.5 million on capital expenditures for the expansion through December 31, 2006, of which approximately $13.0 million relates to assets and services yet to be received. In July 2006 we completed a follow-on public offering of 3.3 million common units raising $103.5 million to fund the majority of this project. On December 27, 2006, the LDEQ approved our application for a modification of our air emissions permit for the Shreveport refinery expansion. We were required to obtain approval of this modified air emissions permit from the LDEQ prior to commencing construction of the expansion activities. Upon receipt of the permit approval from the LDEQ, we have commenced construction of the Shreveport refinery expansion project. On February 22, 2007, we received notice that on February 13, 2007 an individual filed, on behalf of the “Residents for Air Neutralization,” a Petition for Review in the 19th Judicial District Court for East Baton Rouge Parish, Louisiana, asking the Court to review the approval granted by the LDEQ for our application for a modified air emissions permit. The Petition alleges the information in the final LDEQ decision report was inaccurate and that, based on the LDEQ’s decision to grant the modified air emissions permit, the LDEQ had not reviewed the evidence put before them properly. There is a question, unresolved at this time, concerning whether the Petition was timely filed. If it was timely filed, the LDEQ will have sixty days after service of the Petition to file the record of its proceedings with the district court. We believe that the LDEQ will be successful in defending its approval of our application for a modified air emissions permit. Neither we nor any of our subsidiaries is named at this time as a party to the Petition.
 
Management estimates that Calumet will incur approximately $84.5 million of capital expenditures in calendar year 2007 on the expansion project. We currently estimate the total cost of the Shreveport refinery expansion project will be approximately $150.0 million. Cash on hand from the follow-on offering, cash flow from operations and borrowings under the secured revolving credit facility, to the extent necessary, will fund these expenditures.
 
Debt and Credit Facilities
 
On December 9, 2005, we repaid all of our existing indebtedness under our prior credit facilities and entered into new credit agreements with syndicates of financial institutions for credit facilities that consist of:
 
  •  a $225.0 million senior secured revolving credit facility, with a standby letter of credit sublimit of $200.0 million; and
 
  •  a $225.0 million senior secured first lien credit facility consisting of a $175.0 million term loan facility and a $50.0 million letter of credit facility to support crack spread hedging.
 
The revolving credit facility borrowings are limited by advance rates of percentages of eligible accounts receivable and inventory (the borrowing base) as defined by the revolving credit agreement. At December 31, 2006 we had borrowings of $49.5 million under our term loan and no borrowings under our revolving credit facility. Our letters of credit outstanding as of December 31, 2006 were $42.8 million under the revolving credit facility and $50.0 million under the $50.0 million letter of credit facility to support crack spread hedging.
 
The secured revolving credit facility currently bears interest at prime or LIBOR plus 150 basis points (which basis point margin may fluctuate), has a first priority lien on our cash, accounts receivable and inventory and a second priority lien on our fixed assets and matures in December 2010. On December 31, 2006, we had availability on our revolving credit facility of $136.0 million, based upon its $178.8 million borrowing base, $42.8 million in outstanding letters of credit, and no outstanding borrowings.
 
The term loan facility bears interest at a rate of LIBOR plus 350 basis points and the letter of credit facility to support crack spread hedging bears interest at a rate of 3.5%. Each facility has a first priority lien on our fixed assets and a second priority lien on our cash, accounts receivable and inventory and matures in December 2012. Under the terms of our term loan facility, we applied a portion of the net proceeds we received from our initial public offering


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and the underwriters’ over-allotment option as a repayment of the term loan facility, and are required to make mandatory repayments of approximately $0.1 million at the end of each fiscal quarter, beginning with the fiscal quarter ended March 31, 2006 and ending with the fiscal quarter ending December 31, 2011. At the end of each fiscal quarter in 2012 we are required to make mandatory repayments of approximately $11.8 million per quarter, with the remainder of the principal due at maturity. On April 24, 2006, the Company entered into an interest rate swap agreement with a counterparty to fix the LIBOR component of the interest rate on a portion of outstanding borrowings under its term loan facility. The notional amount of the interest rate swap agreement is 85% of the outstanding term loan balance over its remaining term, with LIBOR fixed at 5.44%.
 
Our letter of credit facility to support crack spread hedging 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 the 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 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 or 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 3.75 to 1 (as of the end of each fiscal quarter and after giving effect to a proposed distribution) and available liquidity of at least $30.0 million (after giving effect to a proposed distribution). 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 four fiscal quarter period ending on such date. Available liquidity is a measure used under our credit agreements to mean the sum of the cash and borrowing capacity under our revolving credit facility 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 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.
 
In addition, at any time that our borrowing capacity under our revolving credit facility falls below $25.0 million, we must 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). We anticipate that we will continue to be in compliance with the financial covenants contained in our credit facilities and will, therefore, be able to make distributions to our unitholders.
 
In addition, our credit agreements contain various covenants that limit, among other things, our ability 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 two-year period for at least 40%, and no more than 80%, of our anticipated fuels production). On June 19 and 22, 2006, the Company amended its credit agreements to increase the amount of permitted capital expenditures with respect to the Shreveport refinery expansion project as well as annual capital expenditure limitations.


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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 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. As of December 31, 2006, we believe we are in compliance with all debt covenants and has adequate liquidity to conduct its business.
 
Equity Transactions
 
On January 31, 2006, we completed the initial public offering of our common units and sold 5,699,900 of those units to the underwriters of the initial public offering at a price to the public of $21.50 per common unit. We also sold a total of 750,100 common units to certain other investors at a price of $19.995 per common unit. In addition, on February 8, 2006, we sold an additional 854,985 common units to the underwriters at a price to the public of $21.50 per common unit pursuant to the underwriters’ over-allotment option. We received total net proceeds of approximately $144.4 million. The net proceeds were used to: (i) repay indebtedness and accrued interest under the first lien term loan facility in the amount of approximately $125.7 million, (ii) repay indebtedness under the secured revolving credit facility in the amount of approximately $13.1 million and (iii) pay transaction fees and expenses in the amount of approximately $5.6 million.
 
On July 5, 2006, we completed a follow-on public offering of common units in which we sold 3,300,000 common units to the underwriters of this offering at a price to the public of $32.94 per common unit and received net proceeds of $103.5 million. The net proceeds were used (or will be used) to: (i) repay all of our borrowings under our revolving credit facility, which were approximately $9.2 million as of June 30, 2006, (ii) fund the future construction and other start-up costs of the planned expansion project at our Shreveport refinery and (iii) to the extent available, for general partnership purposes. The general partner contributed an additional $2.2 million to us to retain its 2% general partner interest.
 
Contractual Obligations and Commercial Commitments
 
A summary of our total contractual cash obligations as of December 31, 2006, is as follows:
 
                                         
          Payments Due by Period  
          Less Than
    1-3
    3-5
    More Than
 
    Total     1 Year     Years     Years     5 Years  
                (Thousands)              
 
Long-term debt obligations
  $ 49,500     $ 500     $ 1,000     $ 48,000     $  
Operating lease obligations(1)
    34,407       8,837       11,184       7,942       6,444  
Letters of credit(2)
    92,775       42,775             50,000        
Purchase commitments(3)
    301,302       263,317       37,985              
Employment agreements(4)
    1,360       333       666       361        
                                         
Total obligations
  $ 479,344     $ 315,762     $ 50,835     $ 106,303     $ 6,444  
                                         
 
 
(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 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.


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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, 2006, 2005 and 2004. 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 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” 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 upon shipment to the customer.
 
Turnaround
 
Periodic major maintenance and repairs (turnaround costs) applicable to refining facilities are accounted for using the accrue-in-advance method. Accruals are based upon management’s estimate of the nature and extent of maintenance and repair necessary for each facility. Actual expenditures could vary significantly from management’s estimates as the scope of a turnaround may significantly change once the actual maintenance has commenced. In accordance with FASB Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance Activities, the accounting method used for facility turnarounds will change beginning January 1, 2007 as discussed in Note 2 to the consolidated financial statements.
 
Inventory
 
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 $46.7 million and $47.8 million higher at December 31, 2006 and 2005, respectively.
 
Derivatives
 
We utilize derivative instruments to minimize our 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 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”), we recognize all derivative transactions as either assets or liabilities at fair value on the consolidated balance sheets. To the extent designated as an effective cash flow hedge of an exposure to future changes in the value of a purchase or sale transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income until the forecasted transaction being hedged is recognized in the consolidated statements of operations. Cash flow hedges of purchases and sales are recorded in cost of goods sold and sales, respectively, in the consolidated statements of operations. The realized gain or loss upon the settlement of a cash flow hedge of interest payments is recorded to interest expense in the consolidated statement 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


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instruments in the consolidated statement of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized gain or loss on derivative instruments in the consolidated statement of operations. The company utilizes third party valuations and published market data to determine the fair value of these derivatives.
 
The effective portion of the hedges classified in accumulated other comprehensive income related to these natural gas, crude oil, interest and fuel products derivative contracts at December 31, 2006 is $52.3 million and, absent a change in their fair market value, will be reclassified to earnings by December 31, 2012 with balances expected to be recognized as follows:
 
         
    Other
 
    Comprehensive
 
Year
  Income (Loss)  
    (Thousands)  
 
2007
  $ 13,803  
2008
    15,321  
2009
    12,618  
2010
    10,702  
2011
    (59 )
2012
    (134 )
         
Total
  $ 52,251  
         
 
Recent Accounting Pronouncements
 
In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (the “Interpretation”), an interpretation of FASB Statement No. 109. 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 Interpretation is effective for fiscal years beginning after December 15, 2006. This Interpretation will not have a material effect on the financial position, results of operations or cash flows when adopted on January 1, 2007.
 
In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance Activities, which amends certain provisions in the AICPA Industry Audit Guides, Audits of Airlines, and APB Opinion No. 28, Interim Financial Reporting (the “Position”). The Position prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities and requires the use of the direct expensing method, built-in overhaul method, or deferral method. The Position is effective for fiscal years beginning after December 15, 2006.
 
Effective January 1, 2007, we will adopt the Position and elect the deferral method. Under this method, actual costs of an overhaul are capitalized and amortized to cost of sales until the next overhaul date. Prior to the adoption of this standard, we accrued for such overhaul costs in advance of the turnarounds and recorded the expense to cost of sales. The adoption of the position in prior periods would have resulted in a decrease (increase) in turnaround costs, a component of cost of sales, of $1.7 million, $1.6 million and $(0.7) million for the years ended December 31, 2006, 2005 and 2004, respectively. Furthermore, the adoption will result in the capitalization of turnaround costs of $1.5 million and $2.2 million as of December 31, 2006 and 2005, respectively, as compared to turnaround liabilities previously recorded of $5.1 million and $2.7 million for the same dates.
 
In September 2006, the Financial Accounting Standards Board (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 is effective for fiscal years beginning after November 15, 2007. The Company does not anticipate that this Statement will have a material effect on its financial position, results of operations or cash flows.


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Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
Interest Rate Risk
 
Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates.
 
We are exposed to market risk from fluctuations in interest rates. As of December 31, 2006, we had approximately $49.5 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, 2006 would be expected to have an impact on net income and cash flows for 2006 of approximately $0.5 million.
 
The Company has entered into a forward swap contract to manage interest rate risk related to its variable priced term loan. The Company has hedged 85% of its future interest payments related to this term loan indebtedness. The Company has a $225.0 million revolving credit facility, bearing interest at the prime rate or LIBOR, at its option. No borrowings were outstanding under this facility as of December 31, 2006.
 
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. 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 $9.2 million and our fuel product segment cost of sales by $9.2 million based on our results for the year ended December 31, 2006.
 
Crude Oil Hedging Policy
 
Because we typically do not set prices for our specialty products in advance of our crude oil purchases, we can take into account the cost of crude oil in setting prices. We further manage our exposure to fluctuations in crude oil prices in our specialty products segment through the use of derivative instruments. Our policy is generally to enter into crude oil contracts for three to nine months forward and for 50% to 70% of our anticipated crude oil purchases related to our specialty products production. 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 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 $2.5 million based on our results for the year ended December 31, 2006.
 
Natural Gas Hedging Policy
 
In order to manage our exposure to natural gas prices, we enter into derivative contracts. Our policy is generally to enter into natural gas swap contracts during the summer months for approximately 50% of our anticipated natural gas requirements for the upcoming fall and winter months.


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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 forecasted fuel products segment sales by $9.2 million based on our results for the year ended December 31, 2006.
 
Fuel Products Hedging Policy
 
In order to manage our exposure to changes in gasoline, diesel, and jet fuel selling prices, we enter into fuels product swap contracts. Our policy is 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 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 fuels product margins for a rolling two-year period for at least 40%, and no more than 80%, of our anticipated fuels production.
 
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. Please read “Derivatives” in Note 7 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.
 
Existing Commodity Derivative Instruments
 
The following tables provide information about our derivative instruments related to our fuel products segment as of December 31, 2006:
 
                         
Crude Oil Swap Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)  
 
First Quarter 2007
    1,710,000       19,000       65.14  
Second Quarter 2007
    1,728,000       18,989       64.68  
Third Quarter 2007
    1,742,000       18,935       65.51  
Fourth Quarter 2007
    1,742,000       18,935       65.51  
Calendar Year 2008
    8,143,000       22,249       67.37  
Calendar Year 2009
    7,482,500       20,500       66.04  
Calendar Year 2010
    5,840,000       16,000       67.40  
Calendar Year 2011
    363,500       996       65.99  
                         
Totals
    28,751,000                  
Average price
                  $ 66.49  
 
                         
Diesel Swap Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)  
 
First Quarter 2007
    1,080,000       12,000       81.10  
Second Quarter 2007
    1,092,000       12,000       80.74  
Third Quarter 2007
    1,102,000       11,978       81.36  
Fourth Quarter 2007
    1,102,000       11,978       81.36  
Calendar Year 2008
    4,941,000       13,500       82.18  
Calendar Year 2009
    4,562,500       12,500       80.50  
Calendar Year 2010
    3,650,000       10,000       80.52  
Calendar Year 2011
    273,000       748       76.52  
                         
Totals
    17,802,500                  
Average price
                  $ 81.07  


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Gasoline Swap Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)  
 
First Quarter 2007
    630,000       7,000       72.09  
Second Quarter 2007
    636,000       6,989       71.38  
Third Quarter 2007
    640,000       6,957       72.67  
Fourth Quarter 2007
    640,000       6,957       72.67  
Calendar Year 2008
    3,202,000       8,749       76.17  
Calendar Year 2009
    2,920,000       8,000       73.45  
Calendar Year 2010
    2,190,000       6,000       75.27  
Calendar Year 2011
    90,500       248       70.87  
                         
Totals
    10,948,500                  
Average price
                  $ 74.30  
 
The following table provides a summary of these derivatives and implied crack spreads for the crude oil, diesel and gasoline swaps disclosed above.
 
                         
                Implied Crack
 
Swap Contracts by Expiration Dates
  Barrels     BPD     Spread ($/Bbl)  
 
First Quarter 2007
    1,710,000       19,000       12.64  
Second Quarter 2007
    1,728,000       18,989       12.62  
Third Quarter 2007
    1,742,000       18,935       12.66  
Fourth Quarter 2007
    1,742,000       18,935       12.66  
Calendar Year 2008
    8,143,000       22,249       12.45  
Calendar Year 2009
    7,482,500       20,500       11.71  
Calendar Year 2010
    5,840,000       16,000       11.15  
Calendar Year 2011
    363,500       996       9.13  
                         
Totals
    28,751,000                  
Average price
                  $ 12.00  
 
The following tables provide information about our derivative instruments related to our specialty products segment as of December 31, 2006:
 
                                                 
                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 2007
    248,000       8,000     $ 48.66     $ 58.66     $ 68.66     $ 78.66  
February 2007
    224,000       8,000       49.28       59.28       69.28       79.28  
March 2007
    248,000       8,000       50.85       60.85       70.85       80.85  
                                                 
Totals
    720,000                                          
Average price
                  $ 49.61     $ 59.61     $ 69.61     $ 79.61  
 
                 
Natural Gas Swap Contracts by Expiration Dates
  Mmbtu     $/MMbtu  
 
First Quarter 2007
    600,000     $ 8.87  
Third Quarter 2007
    100,000     $ 7.99  
Fourth Quarter 2007
    150,000     $ 7.99  
First Quarter 2008
    150,000     $ 7.99  
                 
Totals
    1,000,000          
Average price
          $ 8.52  


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As of February 9, 2007, the Company has added the following derivative instruments to the above transactions for our fuel products segment:
 
                         
Crude Oil Swap Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)  
 
Calendar Year 2008
    366,000       1,000       63.46  
Calendar Year 2010
    365,000       1,000       62.93  
Calendar Year 2011
    182,500       500       63.36  
                         
Totals
    913,500                  
Average price
                  $ 63.23  
 
                         
Diesel Swap Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)  
 
Calendar Year 2008
    183,000       500       78.96  
Calendar Year 2010
    365,000       1,000       76.23  
Calendar Year 2011
    182,500       500       74.76  
                         
Totals
    730,500                  
Average price
                  $ 76.55  
 
                         
Gasoline Swap Contracts by Expiration Dates
  Barrels     BPD     ($/Bbl)  
 
Calendar Year 2008
    183,000       500       70.56  
                         
Totals
    183,000                  
Average price
                  $ 70.56  
 
The following table provides a summary of these derivatives and implied crack spreads for the crude oil, diesel and gasoline swaps disclosed above.
 
                         
                Implied Crack
 
Swap Contracts by Expiration Dates
 
Barrels
    BPD     Spread ($/Bbl)  
 
Calendar Year 2008
    366,000       1,000       11.30  
Calendar Year 2010
    365,000       1,000       13.30  
Calendar Year 2011
    182,500       500       11.40  
                         
Totals
    913,500                  
Average price
                  $ 12.12  
 
As of February 9, 2007, the Company has added the following derivative instruments to the above transactions for our specialty products segment:
 
                                                 
                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)  
 
April 2007
    240,000       8,000     $ 42.25     $ 52.25     $ 62.25     $ 72.25  
May 2007
    124,000       4,000       45.38       55.38       65.38       75.38  
                                                 
Totals
    364,000                                          
Average price
                  $ 43.29     $ 53.29     $ 63.29     $ 73.29  


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Item 8.   Financial Statements
 
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, 2006 and 2005 and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2006. 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits 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 Company’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 financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated 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, 2006 and 2005 and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
 
/s/  Ernst & Young LLP
 
Indianapolis, Indiana
February 22, 2007


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
CONSOLIDATED BALANCE SHEETS
 
                 
    Calumet     Predecessor  
    December 31,  
    2006     2005  
    (In thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 80,955     $ 12,173  
Accounts receivable:
               
Trade, less allowance for doubtful accounts of $782 and $750, respectively
    97,740       109,757  
Other
    1,260       5,537  
                 
      99,000       115,294  
                 
Inventories
    110,985       108,431  
Prepaid expenses
    1,506       10,799  
Derivative assets
    40,802       3,359  
Deposits and other current assets
    1,961       8,851  
                 
Total current assets
    335,209       258,907  
Property, plant and equipment, net
    191,732       127,846  
Other noncurrent assets, net
    3,233       12,964  
                 
Total assets
  $ 530,174     $ 399,717  
                 
 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
               
Accounts payable
  $ 78,752     $ 44,759  
Accrued salaries, wages and benefits
    5,675       8,164  
Turnaround costs
    5,105       2,679  
Taxes payable
    7,038       4,209  
Other current liabilities
    2,424       2,418  
Current portion of long-term debt
    500       500  
Derivative liabilities
    2,995       30,449  
                 
Total current liabilities
    102,489       93,178  
Long-term debt, less current portion
    49,000       267,485  
                 
Total liabilities
    151,489       360,663  
                 
Commitments and contingencies
               
Partners’ capital:
               
Predecessor partners’ capital
  $     $ 38,557  
Common unitholders (16,366,000 units issued and outstanding)
    272,973        
Subordinated unitholders (13,066,000 units issued and outstanding)
    40,802        
General partner’s interest
    12,659        
Accumulated other comprehensive income
    52,251       497  
                 
Total partners’ capital
    378,685       39,054  
                 
Total liabilities and partners’ capital
  $ 530,174     $ 399,717  
                 
 
See accompanying notes to consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
    (In thousands except per unit data)  
 
Sales
  $ 1,641,048     $ 1,289,072     $ 539,616  
Cost of sales
    1,437,804       1,148,715       501,284  
                         
Gross profit
    203,244       140,357       38,332  
                         
Operating costs and expenses:
                       
Selling, general and administrative
    20,430       22,126       13,133  
Transportation
    56,922       46,849       33,923  
Taxes other than income taxes
    3,592       2,493       2,309  
Other
    863       871       839  
Restructuring, decommissioning and asset impairments
          2,333       317  
                         
Operating income (loss)
    121,437       65,685       (12,189 )
                         
Other income (expense):
                       
Equity in loss of unconsolidated affiliates
                (427 )
Interest expense
    (9,030 )     (22,961 )     (9,869 )
Interest income
    2,951       204       17  
Debt extinguishment costs
    (2,967 )     (6,882 )      
Realized (loss) gain on derivative instruments
    (30,309 )     2,830       39,160  
Unrealized (loss) gain on derivative instruments
    12,264       (27,586 )     (7,788 )
Other
    (274 )     38       66  
                         
Total other income (expense)
    (27,365 )     (54,357 )     21,159  
                         
Net income before income taxes
    94,072       11,328       8,970  
Income tax expense
    190              
Net income
  $ 93,882     $ 11,328     $ 8,970  
                         
Allocation of net income:
                       
Net income applicable to Predecessor for the period through January 31, 2006
    4,408                  
                         
Net income applicable to Calumet
    89,474                  
Minimum quarterly distribution to common unitholders
    (24,495 )                
General partner’s incentive distribution rights
    (18,157 )                
General partner’s interest in net income
    (840 )                
Common unitholders’ share of income in excess of minimum quarterly distribution
    (17,958 )                
                         
Limited partners’ interest in net income
    28,024                  
Basic net income per limited partner unit:
                       
Common
  $ 2.81                  
Subordinated
  $ 2.14                  
Diluted net income per limited partner unit:
                       
Common
  $ 2.81                  
Subordinated
  $ 2.14                  
Weighted average limited partner common units outstanding — basic
    14,642                  
Weighted average limited partner subordinated units outstanding — basic
    13,066                  
Weighted average limited partner common units outstanding — diluted
    14,642                  
Weighted average limited partner subordinated units outstanding — diluted
    13,066                  
 
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  
 
Balance at January 1, 2004
  $ 25,544                                     $ 25,544  
Net income
    8,970                                       8,970  
                                                 
Balance at December 31, 2004
    34,514                                       34,514  
Comprehensive income:
                                               
Net income
    11,328                                       11,328  
Change in fair value of cash flow hedges
          $ 497                               497  
                                                 
Total comprehensive income
                                            11,825  
Distributions to partners
    (7,285 )                                     (7,285 )
                                                 
Balance at December 31, 2005
    38,557       497     $     $     $       39,054  
Comprehensive income through January 31, 2006 for the Predecessor:
                                               
Net income through January 31, 2006
    4,408                                       4,408  
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
    (30,439 )             609       9,128       20,702        
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
                    10,470       41,917       37,087       89,474  
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
                                            140,147  
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     $ 12,659     $ 272,973     $ 40,802     $ 378,685  
                                                 
 
See accompanying notes to consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Calumet     Predecessor  
    Year Ended December 31,  
    2006     2005     2004  
          (In thousands)        
 
Operating activities
                       
Net income
  $ 93,882     $ 11,328     $ 8,970  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                       
Depreciation and amortization
    11,760       10,386       6,927  
Provision for doubtful accounts
    172       294       216  
Loss on disposal of property and equipment
    91       232       59  
Amortization of vested phantom units
    61              
Equity in loss of unconsolidated affiliates
                427  
Restructuring charge
          1,693        
Debt extinguishment costs
    2,967       4,173        
Dividends received from unconsolidated affiliates
                3,470  
Other
                332  
Changes in assets and liabilities:
                       
Accounts receivable
    16,031       (56,878 )     (19,399 )
Inventories
    (2,554 )     (25,441 )     (20,304 )
Prepaid expenses
    9,293       6,473       (8,472 )
Derivative activity
    (13,143 )     31,598       5,046  
Deposits and other current assets
<