Calumet Specialty Products Partners 10K 2005 Annual report

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, 2005
		OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR THE SECURITIES EXCHANGE ACT OF 1934

Commission File number000-51734

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

None		N/A

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Common units representing limited partner interests.

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 he 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 ofRegulation 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 thisForm 10-K or any amendment to thisForm 10-K. þ

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” inRule 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 inRule 12b-2 of the Act). Yes o No þ

The registrant’s common units were not publicly traded as of the last business day of the registrant’s most recently completed fiscal year. 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 $167.2 million on March 13, 2006, based on $25.83 per unit, the closing price of the common units as reported on the NASDAQ on such date.

At March 13, 2006, there were 13,066,000 common units and 13,066,000 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
NONE.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-K — 2005 ANNUAL REPORT

Table of Contents


		Page

Part I
Items 1 and 2.	Business and Properties		4
Item 1A.	Risk Factors Related to Our Business		17
Item 1B.	Unresolved Staff Comments		32
Item 3.	Legal Proceedings		32
Item 4.	Submission of Matters to a Vote of Security Holders		32

Part II
Item 5.	Market for the Registrant’s Common Equity, and Related Unitholder Matters and Issuer Purchases of Equity Securities		32
Item 6.	Selected Financial and Operating Data		38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		56
Item 8.	Financial Statements		61
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure		89
Item 9A.	Controls and Procedures		89
Item 9B.	Other Information		89

Part III
Item 10.	Directors and Executive Officers of Our General Partner		89
Item 11.	Executive Compensation		92
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		95
Item 13.	Certain Relationships and Related Party Transactions		97
Item 14.	Principal Accountant Fees and Services		100

Part IV
Item 15.	Exhibits		100
Amendment No.1 to Contribution, Conveyance and Assumption Agreement
Sarbanes-Oxley Section 302 certification of F. William Grube
Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II
Section 1350 certification of F. William Grube and R. Patrick Murray, II

FORWARD-LOOKING STATEMENTS

This annual report onForm 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. 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 thisForm 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 thisForm 10-K to “Calumet Specialty Products Partners,” “the Company,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the assets of Calumet Lubricants Co., Limited Partnership and its subsidiaries that were contributed to Calumet Specialty Products Partners, L.P. and its subsidiaries in connection with the closing of its initial public offering on January 31, 2006. When used in the present tense or prospectively, those terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References in thisForm 10-K to “our general partner” refer to Calumet GP, LLC.

PART I


Items 1 and 2.	*Business and Properties*

Overview

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 8,067 bpd for the year ended December 31, 2005.

	•	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 7,145 bpd for the year ended December 31, 2005.

	•	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 fuel and jet fuel. The Shreveport refinery has aggregate crude oil throughput capacity of approximately 42,000 bpd and had average daily crude oil throughput of 35,342 bpd for the year ended December 31, 2005.

	•	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 52.2% of our gross profit for the year ended December 31, 2005 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 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 small 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 to increase lubricating oil and fuels production.

	•	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 1,000 companies and we are continually seeking new customers. From 1996 to December 31, 2005, we added an average of approximately 80 new specialty products customers per year, and for the year ended December 31, 2005, we added 85 new specialty products customers.

	•	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. 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. Refining production volume differs from sales volume due to changes in inventory.


	Year Ended December 31,
	2005		2004		2003

Total sales volume (bpd)(1)		46,953		24,658		23,616
Total feedstock runs (bpd)(2)		50,213		26,205		25,007
Refinery production (bpd)
Specialty products:
Lubricating oils		11,556		9,437		8,290
Solvents		4,422		4,973		4,623
Waxes		1,020		1,010		699
Asphalt and other by-products		6,313		5,992		5,159
Fuels		2,354		3,931		6,433

Total		25,665		25,343		25,204

Fuel products (bpd):
Gasoline		8,278		3		—
Diesel fuel		8,891		583		—
Jet fuel		5,080		342		—
Asphalt and other by-products		417		26		—

Total		22,666		954		—

Total refinery production(3)		48,331		26,297		25,204


(1)		Total sales volume includes sales from the production of our refineries and sales of inventories.

(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.

Set forth below is information regarding sales contributed by our principal products.


	Year Ended December 31,
	2005		2004		2003
	(In millions)

Sales of specialty products:
Lubricating oils	$	394.4	$	251.9	$	205.9
Solvents		145.0		114.7		87.6
Waxes		43.6		39.5		32.3
Fuels		44.0		72.7		83.5
Asphalt and other by-products		76.3		51.2		21.1

Total		703.3		530.0		430.4

Sales of fuel products:
Gasoline	$	223.6	$	—	$	—
Diesel fuel		230.9		3.3		—
Jet fuel		121.3		—		—
Asphalt and other by-products		10.0		6.3		—

Total		585.8		9.6		—

Consolidated sales	$	1,289.1	$	539.6	$	430.4

Princeton Refinery

The Princeton refinery, located on a208-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 fuel and asphalt. The high sulfur diesel fuel may be blended to produce lubricating oil or transported to the Shreveport refinery for further processing into ultra low sulfur diesel fuel. The asphalt may be processed or blended for coating and roofing applications at the Princeton refinery or transported to the Shreveport refinery for processing into bright stock.

The Princeton refinery currently consists of seven major processing units, 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 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 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.


	Year Ended December 31,
	2005		2004		2003

Crude oil throughput capacity (bpd)		10,000		10,000		10,000
Total feedstock runs(1)		8,067		8,062		7,548
Refinery production (bpd):
Lubricating oils		5,463		5,390		5,141
Fuels		1,163		1,475		1,104
Asphalt and other by-products		1,356		1,363		1,246

Total refinery production (1)		7,982		8,228		7,491


(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.

The Princeton refinery has a high-pressure 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 a77-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, 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.

The Cotton Valley refinery currently consists of three major processing units that include a crude unit, a hydrotreater and a fractionation train, 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.


	Year Ended December 31,
	2005		2004		2003

Crude oil throughput capacity (bpd)		13,500		13,500		13,500
Total feedstock runs (bpd)(1)(2)		7,145		9,093		9,370
Refinery production (bpd):
Solvents		4,422		4,973		4,623
By-products		1,473		2,330		2,866
Fuels		1,191		1,790		1,882

Total refinery production (1)(2)		7,086		9,093		9,371


(1)		The refinery was temporarily shut down in February 2005 for an expansion project, thus temporarily lowering feedstock runs in 2005 compared to our historical levels.

(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.

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 occasionally receives feedstock for solvent production from the Shreveport refinery. The Cotton Valley refinery ships finished products throughout the country by both railcar and truck service.

Shreveport Refinery

The Shreveport refinery, located on a240-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 oil products, waxes and residuals, including asphalt and other by-products.

The Shreveport refinery currently consists of 15 major processing units, 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 initiated resumption of gasoline and diesel production at the refinery. The following table sets forth historical information about production at our Shreveport refinery.


	Years Ended December 31,
	2005		2004		2003

Crude oil throughput capacity (bpd)		42,000		10,000		10,000
Total feedstock runs (bpd)(1)		35,342		8,956		8,089
Refinery production (bpd):
Fuels		22,666		1,595		3,448
Lubricating oils		6,093		4,047		3,149
Waxes		1,020		1,010		699
Asphalt and other by-products		3,483		2,325		1,047

Total refinery production(1)		33,262		8,977		8,343


(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.

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.

The Shreveport refinery currently makes low sulfur diesel and has the capability to make ultra low sulfur diesel fuel and all of its gasoline production currently meets low sulfur standards. It also has the ability to produce low emission diesel fuel for sale in Texas. We anticipate that this product will have greater margins than regular diesel fuel. If this market develops at the currently anticipated margins, we will be able to provide product for that demand. The Shreveport refinery also has the capacity to produce about 7,000 bpd of commercial jet fuel.

The Shreveport refinery receives crude oil from common carrier pipeline systems operated by subsidiaries of Plains and ExxonMobil 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 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.

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 to and from each of our refineries throughout the United States and Canada.

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 or foreign crude oils through the LOOP or other terminal locations.

For the year ended December 31, 2005, we purchased approximately 28.8% of our crude oil supply from a subsidiary of Plains under a term contract that expires in 2008. During that period, we purchased approximately 46.8% 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 24.4% 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 typically lags the rising cost of crude oil for specialty products. 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 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 railcars, trucks or barges in the United States and Canada. For the year ended December 31, 2005, about 54.8% of our specialty products were shipped in our fleet of approximately 1,200 leased rail cars with the remaining 45.2% 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 business in 2005, we can ship railcars to several ports where the product can be 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. Any excess volumes are sold to marketers further up the pipeline.

During the fourth quarter 2005, we sold approximately 7,000 bpd of gasoline into the Louisiana and Texas 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 and Texas 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 similarly 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 fuel and all of the Shreveport refinery’s gasoline production meets low sulfur standards set by the EPA. Our Shreveport refinery also has the ability to produce low emission diesel fuel for sale in Texas. We anticipate that this product will have greater margins than regular diesel fuel. If this market develops at the currently anticipated margins, we will be able to provide product for that demand.

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 made into solvents. Jet fuel volumes change as the margin between diesel fuel and jet fuel change. We have a contract with Barksdale for approximately 3,500 bpd of jet fuel. This contract is effective until April 2006 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 together 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 current refinery production of gasoline.

Customers

Specialty Products. We have a diverse customer base for our specialty products, with approximately 1,000 active accounts. Most of our customers are long-term customers who use our products in specialty applications which require six months to two years to gain approval for use in their formulations.

Fuel Products. We have a diverse customer base for our fuel products, with 57 active accounts. We are able to sell the majority of the fuel products we produce to the local markets of Louisiana and east Texas. 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 specialty products or fuel products segments account for more than 10% of our 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 theQS 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 ExxonMobil 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 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 and supplemental projects totaling $191,280 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.

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 for which we are currently discussing settlement with the LDEQ, we believe that we are in substantial compliance with the Clean Air Act and similar state and local laws.

The Clean Air Act authorizes the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with the fuel product’s final use. For example, in December 1999, the EPA promulgated regulations limiting the sulfur content allowed in gasoline. These regulations required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those Western states exhibiting lesser air quality problems. Similarly, the EPA promulgated regulations that limit the sulfur content of highway diesel fuel beginning in 2006 from its current level of 500 parts per million (“ppm”) to 15 ppm. The Shreveport refinery has implemented the sulfur standard with respect to gasoline in its production and thus currently satisfies the sulfur standard for gasoline. The Shreveport refinery already has the capability to satisfy the sulfur standard for diesel fuel and we have commenced production of diesel fuel meeting this sulfur standard beginning in 2006.

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 these discussions, we anticipate that we will ultimately be required to make emissions reductions requiring capital investmentsand/or increased operating expenditures at our three Louisiana refineries. We can provide no assurance that capital expenditures or other liabilities ultimately arising out of these discussions will not be material.

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.

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 the208-acre site of the Princeton refinery in Princeton, Louisiana, the77-acre site of the Cotton Valley refinery in Cotton Valley, Louisiana and the240-acre site of the Shreveport refinery in Shreveport, Louisiana. In addition, we own the11-acre site of the Burnham terminal in Burnham, Illinois. Our properties are pledged as collateral under our credit facilities.

Office Facilities

In addition to our refineries and terminal discussed above, we occupy approximately 15,893 square feet of executive office space in Indianapolis, Indiana under a lease expiring in May 2010. We have an additional 4,232 square feet of executive office space in Indianapolis under a lease expiring in July 2006. 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.

Employees

As of March 13, 2006, the Company’s general partner employs approximately 350 people who provide direct support to the Company’s operations. Of these employees, approximately 190 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 or will make the following information available free of charge on our website:


	•	Annual Report onForm 10-K;

	•	Quarterly Reports onForm 10-Q;

	•	Current Reports onForm 8-K;

	•	Amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934;

	•	Charter for the Audit Committee; 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 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

	•	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, $6.52 per barrel in the first quarter of 2005, $9.10 per barrel in the second quarter of 2005, $17.07 per barrel in the third quarter of 2005 and $9.81 per barrel in the fourth quarter of 2005. 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.

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 $5.79 and $15.39 per million British thermal units, or MMBtu, in 2005 and between $4.57 and $8.75 per MMBtu in 2004. 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 45.6% and 48.1% of our total operating expenses included in cost of sales for the year ended December 31, 2005 and the year ended December 31, 2004, respectively.

Our hedging activities may reduce our earnings, profitability and cash flows.

We utilize derivative financial instruments related to the future price of crude oil, natural gas and crack spreads 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. We are exposed to fluctuations in commodity prices.

Historically, we have 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, 2005, 2004 and 2003, these unrealized gains (losses) were $(27,586,000), $(7,788,000) and $7,228,000, respectively.

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 crack spreads that we realize in our operations. Furthermore, we have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel 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 production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase 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.

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 feedstocks for our refineries. 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, 2005, subsidiaries of Plains and Genesis Crude Oil, L.P. supplied us with approximately 61.2% and 11.1%, respectively, of our total crude oil supplies. Each of our refineries 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.

Each of our refineries 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 ExxonMobil. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. If any of these third-party pipelines become unavailable to transport crude oil feedstock or our refined 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 product customers are primarily in the industrial goods, consumer goods and automotive goods industries and we are therefore susceptible to changing demand patterns and products in those industries. Consequently, it is important that we develop and manufacture new products to replace the sales of products that mature and decline in use. If we are unable to manage successfully the maturation of our existing specialty products and the introduction of new specialty products our revenues, net income and cash available for distribution to unitholders could be reduced.

Distributions to unitholders could be adversely affected by a decrease in demand for fuel products in the markets we serve.

Any sustained decrease in demand for fuel products in the markets we serve could result in a significant reduction in our cash flows, reducing our ability to make distributions to unitholders. Factors that could lead to a decrease in market demand include:


	•	a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;

	•	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of fuel products;

	•	an increase in fuel economy or the increased use of alternative fuel sources;

	•	an increase in the market price of crude oil that lead to higher refined product prices, which may reduce demand for fuel products;

	•	competitor actions; and

	•	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 significant 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 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 customersand/or counterparties could reduce our ability to make distributions to our unitholders.

Our reconfiguration and enhancement of assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our business, operating results, cash flows and financial condition.

One of the ways we may grow our business is through the reconfiguration and enhancement of our refinery assets. The construction of additions or modifications to our existing refineries involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand an existing refinery, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed.

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 face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.

Our refining activities are conducted at three refineries in northwest Louisiana. These refineries are our principal operating assets. Our operations are subject to significant interruption, and our cash from operations could decline if any of our refineries 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 injuryand/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, 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.

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.

Following our application of the net proceeds from our initial public offering, we had total outstanding debt of $144.4 million as of February 2, 2006. On February 8, 2006, we repaid an additional $17.1 million of our term loan facility, including accrued interest, from the overallotment proceeds related to our initial public offering. As of February 28, 2006, we had $86.7 million of outstanding indebtedness. 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 significant level of indebtedness could have important consequences to us, including the following:


	•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

	•	covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;


	•	we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

	•	our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investmentsand/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.

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.

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 feedstocksand/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 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 2008, 2007 and 2007, respectively. 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.

Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. In addition, our natural gas costs tend to be higher during the winter months. As a result, our operating results for the first and fourth calendar quarters for those businesses are generally lower than those for the second and third calendar quarters of each year.

Risks Inherent in an Investment in Us

The Fehsenfeld and Grube families, The Heritage Group and certain of their affiliates own a 73.4% 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 Heritage Group, the Fehsenfeld and Grube families, including certain relatives of the chairman of our general partner to whom we directly sold 750,100 common units in connection with our initial public offering (the “Fehsenfeld Investors”), and certain of their affiliates own a 73.4% limited partner interest in us. In addition, The Heritage Group and the Fehsenfeld and Grube families own our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:


	•	our general partner is allowed to take into account the interests of parties other than us, such as its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;


	•	our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

	•	our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to unitholders;

	•	our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

	•	our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a capital expenditure for acquisitions or capital improvements, which does not. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

	•	our general partner has the flexibility to cause us to enter into a broad variety of derivative transactions covering different time periods, the net cash receipts from which will increase operating surplus and adjusted operating surplus, with the result that our general partner may be able to shift the recognition of operating surplus and adjusted operating surplus between periods to increase the distributions it and its affiliates receive on their subordinated units and incentive distribution rights or to accelerate the expiration of the subordination period; and

	•	in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

The Heritage Group and certain of its affiliates may engage in limited competition with us.

Pursuant to the omnibus agreement, 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;

	•	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 will 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, certain of their affiliates and the Fehsenfeld Investors own 74.9% 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 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 6,533,000 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.

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, not including the Fehsenfeld Investors, own approximately 44.1% 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 72.0% 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. UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we call the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of the units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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 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 common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), other retirement plans, andnon-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 tonon-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, andnon-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.

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 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.

PART II


Item 5.	*Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities*

Market Information

Our common units began trading on the NASDAQ National Market under the symbol “CLMT” on January 26, 2006 in conjunction with our initial public offering. On March 13, 2006, the closing market price for the common units was $25.83 per unit and 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 March 13, 2006, there were 26,132,000 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.

Cash Distribution Policy

General. Within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2006, we will distribute our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from January 31, 2006, the closing of the initial public offering, through March 31, 2006 based on the actual length of the period.

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 will distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.45 per unit, or $1.80 per

year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreements. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for a discussion of the restrictions in our credit agreements that restrict our ability to make distributions.

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 533,306 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.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus. Operating surplus generally consists of:


	•	our cash balance on the closing date of the initial public offering; plus

	•	$10.0 million (as described below); plus

	•	all of our cash receipts after the closing of the initial public offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

	•	all of our operating expenditures after the closing of the initial public offering (including the repayment of working capital borrowings, but not the repayment of other borrowings) and maintenance capital expenditures; less

	•	the amount of cash reserves established by our general partner for future operating expenditures.

Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand the existing operating capacity of our assets or to expand the operating capacity or revenues of existing or new assets, whether through construction or acquisition. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as operations and maintenance expenses as we incur them. Our partnership agreement provides that our general partner determines how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.

Capital Surplus. Capital surplus consists of:


	•	borrowings other than working capital borrowings;

	•	sales of our equity and debt securities; and

	•	sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $10.0 million. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General. Our partnership agreement provides that, during the subordination period (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;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and


	•	the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:


	•	operating surplus generated with respect to that period; less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	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.

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;


	•	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 onForm 10-K.

Sales of Unregistered Securities

In September 2005, in connection with our formation we issued to: (i) Calumet GP, LLC the 2% general partner interest in us for $20 and (ii) The Heritage Group, F. William Grube, Calumet, Incorporated, Fred Fehsenfeld, Jr. and certain trusts for the benefit of the Fehsenfeld family the 98% limited partner interest in us for $980. This issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities in the last year.

Issuer Purchases of Equity Securities

None.

Initial Public Offering

On January 31, 2006, Calumet Specialty Products Partners, L.P. completed the initial public offering of its common units and sold 5,699,900 of those units to the underwriters in the initial public offering at a price to the public of $21.50 per common unit. The managing underwriter for the offering was Goldman, Sachs & Co. The Partnership also sold a total of 750,100 common units to the Fehsenfeld Investors at a price of $19.995 per common unit. In addition, on February 8, 2006, the Partnership 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. Each of these issuances was made pursuant to the Partnership’s Registration Statement onForm S-1 (FileNo. 333-128880) as declared effective by the Securities and Exchange Commission on January 29, 2006. The proceeds received by the Partnership (net of underwriting discounts and structuring fees and before expenses) from the sale of an aggregate of 7,304,985 units were 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 $13.7 million and (iii) pay transaction fees and expenses in the amount of approximately $5.0 million. Underwriting discounts totaled approximately $11.6 million (including certain structuring fees paid to certain of the underwriters of approximately $2.4 million).


Item 6.	*Selected Financial and Operating Data*

The following table shows selected historical financial and operating data of Calumet Lubricants Co., Limited Partnership and its consolidated subsidiaries (“Calumet Predecessor”). The selected historical financial data as of December 31, 2005, 2004, 2003, 2002 and 2001 and for the years ended December 31, 2005, 2004, 2003, 2002 and 2001, are derived from the consolidated financial statements of Calumet Predecessor.

None of the assets or liabilities of Calumet 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 cash flow from 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 financial statements and the accompanying notes included in Item 8 of this Annual Report onForm 10-K except for operating data such as sales volume, feedstock runs and refinery production. The table 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,
	2005			2004			2003			2002			2001
													(Unaudited)
	(In thousands)

Summary of Operations Data:
Sales	$	1,289,072		$	539,616		$	430,381		$	316,350		$	306,760
Cost of sales		1,148,715			501,284			385,890			268,911			272,523

Gross profit		140,357			38,332			44,491			47,439			34,237
Operating costs and expenses:
Selling, general and administrative		22,126			13,133			9,432			9,066			7,844
Transportation		46,849			33,923			28,139			25,449			24,096
Taxes other than income taxes		2,493			2,309			2,419			2,404			1,400
Other		871			839			905			1,392			1,038
Restructuring, decommissioning and asset impairments(1)		2,333			317			6,694			—			9,015

Total operating income (loss)		65,685			(12,189	)		(3,098	)		9,128			(9,156	)

Other income (expense):
Equity in income (loss) of unconsolidated affiliates		—			(427	)		867			2,442			1,636
Interest expense		(22,961	)		(9,869	)		(9,493	)		(7,435	)		(6,235	)
Debt extinguishment costs		(6,882	)		—			—			—			—
Realized gain (loss) on derivative instruments		2,830			39,160			(961	)		1,058			—
Unrealized gain (loss) on derivative instruments		(27,586	)		(7,788	)		7,228			—			—
Other		242			83			32			88			471

Total other income (expense)		(54,357	)		21,159			(2,327	)		(3,847	)		(4,128	)

Net income (loss)	$	11,328		$	8,970		$	(5,425	)	$	5,281		$	(13,284	)

Balance Sheet Data (at period end):
Property, plant and equipment, net	$	127,846		$	126,585		$	89,938		$	85,995		$	76,316
Total assets		399,717			318,206			216,941			217,915			192,118
Accounts payable		44,759			58,027			32,263			34,072			24,485
Long-term debt		267,985			214,069			146,853			141,968			127,759
Partners’ capital		39,054			34,514			25,544			30,968			17,362


	Calumet Predecessor
	Year Ended December 31,
	2005			2004			2003			2002			2001
													(Unaudited)
	(In thousands)

Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	(34,001	)	$	(612	)	$	7,048		$	(4,326	)	$	(13,774	)
Investing activities		(12,903	)		(42,930	)		(11,940	)		(9,924	)		(31,059	)
Financing activities		40,990			61,561			4,884			14,209			44,872
Other Financial Data:
EBITDA	$	51,557		$	25,766		$	10,837		$	18,592
Adjusted EBITDA		85,821			34,711			6,110			16,277
Operating Data (bpd):
Total sales volume(2)		46,953			24,658			23,616			19,110			19,021
Total feedstock runs(3)		50,213			26,205			25,007			21,665			18,941
Total refinery production(4)		48,331			26,297			25,204			21,587			18,991


(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 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.

Non-GAAP Financial Measures

We include in this Annual Report onForm 10-K the non-GAAP financial measures EBITDA and Adjusted EBITDA, and provide reconciliations of EBITDA and Adjusted EBITDA to net income and cash flow from operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.

EBITDA and Adjusted EBITDA are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest costs support our indebtedness, and meet minimum quarterly distributions;

	•	our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

We define EBITDA as net income plus interest expense, 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 income, cash flows from 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 EBITDA and Adjusted EBITDA to net income and cash flow from operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated:


	Calumet Predecessor
	Year Ended December 31,
	2005		2004			2003			2002
	(In thousands)

Reconciliation of EBITDA and Adjusted EBITDA to net income:
Net income	$	11,328	$	8,970		$	(5,425	)	$	5,281
Add:
Interest expense and debt extinguishment costs		29,843		9,869			9,493			7,435
Depreciation and amortization		10,386		6,927			6,769			5,876
Income tax expense		—		—			—			—

EBITDA	$	51,557	$	25,766		$	10,837		$	18,592

Add:
Unrealized losses (gains) from mark to market accounting for hedging activities	$	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		4,912		2,433			251			(2,315	)

Adjusted EBITDA	$	85,821	$	34,711		$	6,110		$	16,277


	Calumet Predecessor
	Year Ended December 31,
	2005			2004			2003			2002
	(In thousands)

Reconciliation of EBITDA and Adjusted EBITDA to net cash provided by (used) in operating activities:
Net cash provided by (used) in operating activities	$	(34,001	)	$	(612	)	$	7,048		$	(4,326	)
Add:
Interest expense		29,843			9,869			9,493			7,435
Restructuring charge		(1,693	)		—			(874	)		—
Provision for doubtful accounts		(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		(4,173	)		—			—			—
Changes in operating working capital:
Accounts receivable		56,878			19,399			4,670			1,025
Inventory		25,441			20,304			(15,547	)		16,984
Other current assets		(569	)		11,596			563			(1,295	)
Derivative activity		(31,101	)		(5,046	)		6,265			3,682
Accounts payable		13,268			(25,764	)		1,809			(9,587	)
Accrued liabilities		(5,874	)		(1,203	)		(1,379	)		2,622
Other, including changes in noncurrent assets and liabilities		3,832			1,336			(1,316	)		2,551

EBITDA	$	51,557		$	25,766		$	10,837		$	18,592

Add:
Unrealized losses (gains) from mark to market accounting for hedging activities	$	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		4,912			2,433			251			(2,315	)

Adjusted EBITDA	$	85,821		$	34,711		$	6,110		$	16,277


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

The historical consolidated financial statements included in this Annual Report onForm 10-K reflect all of the assets, liabilities and results of operations of Calumet Lubricants Co., Limited Partnership. We refer to these assets, liabilities and operations as Calumet Predecessor. These historical consolidated financial statements include the results of operations of the Rouseville and Reno facilities, which have been closed, and the Bareco joint venture, which has been terminated as described below. The following discussion analyzes the financial condition and results of operations of Calumet Predecessor. Unitholders should read the following discussion of the financial condition and results of operations for Calumet Predecessor in conjunction with the historical consolidated financial statements and notes of Calumet Predecessor included elsewhere in this Annual Report onForm 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 fuel 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 asphalt and other 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, 2005, approximately 52.2% of our gross profit was generated from our specialty products segment and approximately 47.8% of our gross profit was generated from our fuel products segment.

Subsequent to the acquisition of the Shreveport refinery, Calumet Predecessor undertook to streamline its wax processing and marketing operations by decommissioning its Rouseville facility, closing its Reno facility and terminating its Bareco joint venture. None of the assets or liabilities of Calumet Predecessor’s Rouseville facility, Reno facility or Bareco joint venture were contributed to Calumet Specialty Products Partners, L.P. in connection with the initial public offering on January 31, 2006. Calumet 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, Calumet Predecessor closed the Reno facility for a restructuring cost of $1.7 million. In 2003, Calumet Predecessor terminated its Bareco joint venture. The results of operations of Bareco are reflected in equity in (loss) income of unconsolidated affiliates in the consolidated statements of operations. The combined net book value of the Reno and Rouseville operations as of December 31, 2005 was $0.4 million.

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. Since completion of the reconfiguration of the Shreveport refinery, crack spreads have increased, which has further improved the profitability of the fuel products segment.

Our sales and net income are principally affected by the price of crude oil, demand for specialty and fuel products, prevailing crack spreads for fuel products, the price of natural gas used as fuel in our operations and our results from derivative instrument activities.

Our primary raw 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 product prices. We enter into derivative contracts for future periods in quantities which do not exceed our projected purchases of crude oil and fuels production. Please read Item 7A “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

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 through the spreading of fixed costs over greater 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 will also monitor our general and administrative expenditures, substantially all of which will be incurred through our general partner, Calumet GP, LLC. We estimate that we will incur incremental general and administrative expenses of approximately $4.5 million per year as a result of being a publicly traded limited partnership. These costs include those associated with annual and quarterly reports to unitholders, independent auditors’ fees, tax return andSchedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, management and director compensation and incremental insurance costs, including director and officer liability and business interruption insurance.

On January 31, 2006, Calumet Specialty Products Partners, L.P. completed the initial public offering of its common units and sold 5,699,900 of those units to the underwriters in the initial public offering at a price to the public of $21.50 per common unit. The managing underwriter for the offering was Goldman, Sachs & Co. The Partnership also sold a total of 750,100 common units to the Fehsenfeld Investors at a price of $19.995 per common unit. In addition, on February 8, 2006, the Partnership 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. Each of these issuances was made pursuant to the Partnership’s Registration Statement onForm S-1 (FileNo. 333-128880) declared effective by the Securities and Exchange Commission on January 29, 2006. The proceeds received by the Partnership (net of underwriting discounts and structuring fees and before expenses) from the sale of an aggregate of 7,304,985 units were 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 $13.7 million and (iii) pay transaction fees and expenses in the amount of approximately $5.0 million. Underwriting discounts totaled approximately $11.6 million (including certain structuring fees paid to certain of the underwriters of approximately $2.4 million).

Results of Operations

The following table sets forth information about our combined refinery operations. Refining production volume differs from sales volume due to changes in inventory.


	Year Ended December 31,
	2005		2004		2003

Total sales volume (bpd)(1)		46,953		24,658		23,616
Total feedstock runs (bpd)(2)		50,213		26,205		25,007
Refinery production (bpd)(3):
Specialty products:
Lubricating oils		11,556		9,437		8,290
Solvents		4,422		4,973		4,623
Waxes		1,020		1,010		699
Asphalt and other by-products		6,313		5,992		5,159
Fuels		2,354		3,931		6,433

Total		25,665		25,343		25,204

Fuel products:
Gasoline		8,278		3		—
Diesel fuel		8,891		583		—
Jet fuel		5,080		342		—
Asphalt and other by-products		417		26		—

Total		22,666		954		—

Total refinery production		48,331		26,297		25,204


(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.

The following table sets forth information about the sales of our principal products.


	Year Ended December 31,
	2005		2004		2003
	(In millions)

Specialty products:
Lubricating oils	$	394.4	$	251.9	$	205.9
Solvents		145.0		114.7		87.6
Waxes		43.6		39.5		32.3
Fuels		44.0		72.7		83.5
Asphalt and other by-products		76.3		51.2		21.1

Total		703.3		530.0		430.4

Fuel products:
Gasoline		223.6		—		—
Diesel fuel		230.9		3.3		—
Jet fuel		121.3		—		—
Asphalt and other by-products		10.0		6.3		—

Total		585.8		9.6		—

Consolidated sales	$	1,289.1	$	539.6	$	430.4

The following table reflects our consolidated results of operations.


	Year Ended December 31,
	2005			2004			2003
	(In millions)

Sales	$	1,289.1		$	539.6		$	430.4
Cost of sales		1,148.7			501.3			385.9

Gross profit		140.4			38.3			44.5

Operating costs and expenses:
Selling, general and administrative		22.1			13.1			9.4
Transportation		46.9			34.0			28.2
Taxes other than income taxes		2.5			2.3			2.4
Other		0.9			0.8			0.9
Restructuring, decommissioning and asset impairments		2.3			0.3			6.7

Operating income (loss)		65.7			(12.2	)		(3.1	)

Other income (expense):
Equity in (loss) income of unconsolidated affiliates		—			(0.4	)		0.9
Interest expense		(23.0	)		(9.9	)		(9.5	)
Debt extinguishment costs		(6.9	)		—			—
Realized gain (loss) on derivative instruments		2.8			39.2			(1.0	)
Unrealized gain (loss) on derivative instruments		(27.6	)		(7.8	)		7.3
Other		0.3			0.1			—

Total other income (expense)		(54.4	)		21.2			(2.3	)

Net income (loss)	$	11.3		$	9.0		$	(5.4	)

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:


	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		—		—
Asphalt and 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 asphalt and other 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.

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 thestart-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:


	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 $2.0 million charge related to asset impairment 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.

Gain (loss) on derivative instruments. Gains (loss) on derivative instruments decreased $56.1 million, to a $24.8 million loss in the year ended December 31, 2005 from a $31.4 million gain in the year ended December 31, 2004. This decrease primarily was the result of marking to fair value a new mix of fuel product margin collar and swap contracts which experienced significant declines in value due to increased crack spreads as of December 31, 2005.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Sales. Sales increased $109.2 million, or 25.4%, to $539.6 million in the year ended December 31, 2004 from $430.4 million in the year ended December 31, 2003. Sales for each of our principal product categories in these periods were as follows:


	Year Ended December 31,
	2004		2003		% Change
	(Dollars in millions)

Sales by segment:
Specialty products:
Lubricating oils	$	251.9	$	205.9		22.3	%
Solvents		114.7		87.6		30.9
Waxes		39.5		32.3		22.3
Fuels(1)		72.7		83.5		(13.0	)
Asphalt and by-products(2)		51.2		21.1		142.7

Total specialty products	$	530.0	$	430.4		23.1	%
Total specialty products volumes (in barrels)		8,807,000		8,620,000		2.2	%
Fuel products:
Gasoline	$	—	$	—		—
Diesel		3.3		—		—
Jet fuel		—		—		—
Asphalt and by-products(3)		6.3		—		—

Total fuel products	$	9.6	$	—		—

Total fuel products volumes (in barrels)		193,000		—		—

Total sales	$	539.6	$	430.4		25.4	%

Total sales volumes (in barrels)		9,000,000		8,620,000		4.4	%


(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 and Cotton Valley refineries.

(3)		Represents asphalt and other by-products produced in connection with the production of fuels at the Shreveport refinery.

This $109.2 million increase in sales resulted primarily from a 23.1% increase in specialty products sales, and also from the addition of $9.6 million in sales from the start-up of our fuel products operations at the Shreveport refinery. The increase in specialty product sales resulted primarily from an increase of 20.5% in the average price per barrel of product sold, and also from a 2.2% increase in volumes sold, from approximately 8.6 million barrels in 2003 to 8.8 million barrels in 2004. Sales price increases were driven by an average 32.5% increase in the cost of crude oil per barrel over the same period. Increases in prices for waxes lagged our average increase in price per barrel of product sold compared to the increase in prices for lubricating oils, solvents and fuels. In 2004 as compared to 2003, sales volumes of fuels decreased and sales volumes of asphalt and by-products increased due to a different mix of feedstock.

Gross Profit. Gross profit decreased $6.2 million, or 13.8%, to $38.3 million for the year ended December 31, 2004 from $44.5 million for the year ended December 31, 2003. Gross profit for our specialty and fuel products segments were as follows:


	Year Ended December 31,
	2004			2003			% Change
	(Dollars in millions)

Gross profit by segment:
Specialty products	$	40.6		$	44.5			(8.6	)%
Percentage of sales		7.7	%		10.3	%
Fuel products		(2.3	)		—			—
Percentage of sales		(24.1	)%		—			—
Total gross profit	$	38.3		$	44.5			(13.8	)%
Percentage of sales		7.1	%		10.3	%

This $6.2 million decrease in total gross profit includes a decrease of $3.9 million in specialty products gross profit and a loss of $2.3 million in our fuel products segment which began operations in late 2004. The decrease in specialty products gross profit resulted from a 32.3% increase in the average price of crude oil per barrel which was partially offset by a 20.5% increase in selling prices and 2.2% increase in sales volumes. The increase in selling prices lagged behind the rising costs of crude oil feedstocks for specialty products. However, we sought to manage the financial impact of this lag through the use of derivative instruments, which provided gains in the 2003 and 2004 periods as described in gain (loss) on derivative instruments below.

Selling, general and administrative. Selling, general and administrative expenses increased $3.7 million, or 39.2%, to $13.1 million in the year ended December 31, 2004 from $9.4 million in the year ended December 31, 2003. This increase primarily reflects $2.2 million of increased compensation costs due to our incentive bonuses.

Transportation. Transportation expenses increased $5.8 million, or 20.6%, to $33.9 million in the year ended December 31, 2004 from $28.1 million in the year ended December 31, 2003. This increase primarily reflects fuel surcharges and rail rate increases.

Restructuring, decommissioning and asset impairments. Restructuring, decommissioning and asset impairment expenses decreased $6.4 million to $0.3 million in the year ended December 31, 2004 from $6.7 million in the year ended December 31, 2003. In 2004, we recorded a $0.3 million charge related to the completion of the Rouseville asset decommissioning. In 2003, we recorded a $6.7 million charge related to the decommissioning of the Rouseville facility and related asset impairment.

Interest expense. Interest expense increased $0.4 million, or 4.0%, to $9.9 million in the year ended December 31, 2004 from $9.5 million in the year ended December 31, 2003. This increase was primarily due to increased borrowings under the credit agreement with a limited partner and borrowings under the term loan agreement related to the reconfiguration of the Shreveport refinery entered into during the fourth quarter of 2004.

Gain (loss) on derivative instruments. Gains on derivative instruments increased $25.1 million, or 400.6%, to $31.4 million in the year ended December 31, 2004 from $6.3 million in the year ended December 31, 2003. This increase was the result of marking to fair value gains due to the rising price of crude oil in relation to the contractual strike prices on our derivative instruments and our new mix of fuel product margin collar and swap contracts during 2004.

Liquidity and Capital Resources

Our principal historical sources of cash have included the issuance of private debt, bank borrowings, and cash flow from operations. Principal historical uses of cash have included capital expenditures, growth in working capital 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 flows 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:


	Year Ended December 31,
	2005			2004			2003

Net cash provided by (used in) operating activities	$	(34.0	)	$	(0.6	)	$	7.0
Net cash used in investing activities		(12.9	)		(42.9	)		(11.9	)
Net cash provided by (used in) financing activities	$	41.0		$	61.6		$	4.9

Operating Activities. Operating activities used $34.0 million in cash during the year ended December 31, 2005 compared to $0.6 million during 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 payment for capital expenditures 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.

Operating activities used $0.6 million of cash for the year ended December 31, 2004 compared to generating $7.0 million of cash for the year ended December 31, 2003. This decrease is primarily due to increased levels of accounts receivable and inventory which more than offset increases in net income and accounts payable. This net increase in accounts payable was driven primarily by capital expenditures related to the Shreveport reconfiguration incurred but not paid at the end of 2004 and the rising cost of crude oil.

Investing Activities. Cash used in investing activities decreased to $12.9 million during the year ended December 31, 2005 as compared to $42.9 million during the year ended December 31, 2004. This decrease is primarily due to the $36.0 million of additions to property, plant and equipment related to the reconfiguration at our Shreveport refinery incurred during 2004, with no comparable expenditures in 2005, offset by an upgrade to the capacity and enhancement of product mix at our Cotton Valley refinery in 2005.

Cash used in investing activities increased to $42.9 million for the year ended December 31, 2004 compared to $11.9 million for the year ended December 31, 2003. This increase is primarily due to $36.0 million of additions to property, plant and equipment related to the reconfiguration at our Shreveport refinery incurred during 2004.

Financing Activities. Financing activities provided cash of $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 2005 to finance the growth in working capital related to the startup of fuel products operations at Shreveport.

Cash provided by financing activities increased to $61.6 million for the year ended December 31, 2004 compared to $4.9 million for the year ended December 31, 2003. This increase is primarily due to the third party borrowings of $49.8 million and additional borrowings from a limited partner obtained to finance the reconfiguration at our Shreveport refinery.

Capital Expenditures

Our capital requirements consist of capital improvement expenditures, replacement capital expenditures and environmental 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 expenditures include property additions to meet or exceed environmental and operating regulations. We expense all maintenance costs with major maintenance and repairs (facility turnarounds) accrued in advance over the period between turnarounds.

The following table sets forth our capital improvement expenditures, replacement capital expenditures and environmental expenditures in each of the periods shown.


	Year Ended December 31,
	2005		2004		2003

Capital improvement expenditures	$	8.8	$	39.0	$	7.5
Replacement capital expenditures	$	3.5		2.6		4.3
Environmental expenditures	$	0.7		1.4		0.4

Total	$	13.0	$	43.0	$	12.2

The capital improvement expenditures for the year ended December 31, 2005 were primarily used to complete the reconfiguration of our Shreveport refinery and to upgrade the capacity and enhance the product mix at the Cotton Valley refinery. Significant capital improvement expenditures in 2004 made to enhance our refineries’ product mix and capacity consisted primarily of $36.0 million related to the reconfiguration of the Shreveport refinery. Significant capital improvement expenditures in 2003 made to enhance our refineries’ product mix and capacity consisted primarily of expenditures to upgrade the Shreveport hydrotreater and the Princeton refinery.

As part of our $39.7 million Shreveport refinery reconfiguration, we modified our Shreveport refinery with the capability to make all of its low sulfur diesel fuel into ultra low sulfur diesel fuel as required by the EPA’s 2006 ultra low sulfur diesel standards. Our Cotton Valley refinery may similarly make all of its low sulfur diesel fuel into ultra low sulfur diesel fuel. Our Princeton refinery may blend its high sulfur diesel fuel to produce lubricating oils or transport it to the Shreveport refinery for further processing into ultra low sulfur diesel fuel. Our Shreveport refinery’s gasoline production currently meets the EPA’s 2006 low sulfur gasoline standards.

We anticipate that future capital improvement requirements will be provided through long-term borrowings, other debt financings, equity offeringsand/or cash on hand.

We are currently pursuing capital improvement projects at our Shreveport refinery which we expect will be completed in multiple phases over the next several quarters and which we believe will significantly increase this refinery’s operating capacity. These projects include:


	•	DDD Expansion — Initially, the Distillate Desulfurization and Dewaxing (DDD) unit and crude unit will be debottlenecked which should increase the refinery’s throughput by approximately 5% - 10% over current rates. This portion of the project is in the implementation phase and is scheduled for completion during the second quarter of 2006. Subsequently, we intend to undertake a more major expansion project which should result in an additional capacity increase of approximately 10,000 bpd. This portion of the project is expected to be completed in 2007 and is currently in the planning and engineering stage.

	•	Sour Crude Project — This project will allow the refinery to process sour crude in order to lower the Shreveport refinery’s total feedstock cost. We began implementing this project during the fourth quarter of 2005 and expect to complete the first phase of the project during the second quarter of 2006. Upon completion of the first phase, we anticipate we will be running approximately 5,000 bpd of sour crude.

We currently anticipate incurring approximately $20 million in capital expenditures in 2006 with respect to these projects. We will incur additional capital expenditures related to these projects in 2007. In addition, we are currently evaluating similar product and capacity enhancements which would utilize currently idle equipment at all of our refineries.

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; 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.

At December 31, 2005 we had borrowings of $175.0 million under our term loan and $93.0 million under our revolving credit facility. Our letters of credit outstanding as of December 31, 2005 were $37.7 million under the revolving credit facility and $11.0 million under the $50 million letter of credit facility. After applying the proceeds from the initial public offering and the underwriters’ over-allotment option, as of February 28, 2006, we had borrowings of $50.0 million under our term loan facility and $36.7 million under our revolving credit facility.

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. We borrowed $75.3 million under the secured revolving credit facility at the time of the refinancing. On February 10, 2006, following the application of the net proceeds we received from the initial public offering and the underwriters’ over-allotment option, we had availability on our revolving credit facility of $101.4 million, based upon its $187.8 million borrowing base, $39.7 million in outstanding letters of credit, and borrowings of $46.7 million.

The term loan facility was fully drawn at the time of the refinancing. 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 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.

Our letter of credit facility to support crack spread hedging is secured by a first priority lien on our fixed assets. As long as this first priority lien is in effect, we will have no obligation to post additional cash, letters of credit or other collateral to supplement this $50.0 million letter of credit to secure our crack spread hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices.

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 dividends 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 refining margins in our fuels segment for a rolling two-year period for at least 40%, and no more than 80%, of our anticipated fuels production).

If an event of default exists under our credit agreements, the lenders will be able to accelerate the maturity of the credit facilities and exercise other rights and remedies. Each of the following is an event of default:


	•	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.

Contractual Obligations and Commercial Commitments

A summary of our total contractual cash obligations as of December 31, 2005, 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	$	267,985	$	500	$	1,500	$	93,985	$	172,000
Operating lease obligations(1)		34,113		8,387		13,673		5,609		6,444
Letters of credit(2)		48,746		48,746		—		—		—
Purchase commitments(3)		779,538		375,295		400,191		4,052		—

Total obligations	$	1,130,382	$	432,928	$	415,364	$	103,646	$	178,444


(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)		Standby 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.

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, 2005, 2004 and 2003. 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 that appear elsewhere in this Annual Report onForm 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 theaccrue-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.

Inventory

The cost of inventories is determined using thelast-in, first-out (LIFO) method. Costs include material, labor and manufacturing 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 $47.8 million and $26.9 million higher at December 31, 2005 and 2004, respectively.

Derivatives

We utilize derivative financial instruments to reduce commodity price risks. We do not hold or issue derivative financial instruments for trading purposes. Statement of Financial Accounting Standards (or 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”), establishes accounting and reporting standards for derivative instruments and hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial condition and measure those instruments at fair value.

Derivatives that are not designated as hedges are adjusted to fair value through earnings. If the derivative is designated as a hedge, depending upon the nature of the hedge, changes in the fair value of the derivatives are either offset against the changes in the fair value of assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value is immediately recognized into income.

On December 1, 2005, all derivatives hedging natural gas and crude oil purchases for our specialty products segment were designated as cash flow hedges. During 2003 and 2004 and through November 30, 2005, none of our outstanding derivative transactions were designated as hedges. Changes in the market value of derivative contracts currently outstanding related to the crack spreads will continue to be reflected in earnings. In the future the Company intends to designate and qualify all derivative transactions, as well as amend our existing contracts, to hedge refining margins as cash flow hedges under SFAS 133. Adjustments to the market value of the effective portion of derivative instruments that qualify as a cash flow hedge will be reflected as a component of other comprehensive income (outside earnings) and reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. As of December 31, 2005, $0.5 million was recorded in other comprehensive income related to our natural gas and crude oil cash flow hedges. As a result, gain (loss) on derivative transactions recognized in our historical financial statements may not be consistent with our future gains (losses) on derivative transactions.

Recent Accounting Pronouncements

In November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting (SFAS) No. 151, Inventory Costs — an amendment of Accounting Research Bulletin (ARB) No. 43, Chapter 4. The Statement clarifies that abnormal amounts of idle facility expense, freight, handling costs and wasted materials should be recognized as current-period expenses regardless of how abnormal the circumstances. In addition, this Statement requires that the allocation of fixed overheads to the costs of conversion be based upon normal production capacity levels. The Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not anticipate that this Statement will have a material effect on our financial position, results of operations or cash flows.

On December 16, 2004, the FASB issued Statement No. 123 (revised 2004), Share-Based Payment, which is a revision of FASB Statement No. 123, Accounting for Stock Based Compensation. Statement 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in Statement 123(R) is similar to the approach described in Statement 123. However, Statement 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

Statement 123(R) is effective for fiscal years beginning after July 1, 2005. We expect to adopt Statement 123(R) using the “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of Statement 123(R) for all share-based payments granted after the effective date and based on the requirements of Statement 123 for all awards granted to employees prior to the effective date of Statement 123(R) that remain unvested on the effective date. The total impact of adoption of Statement 123(R) cannot be predicted at this time because it will depend on levels of share-based payments granted in the future.

In 2005, the FASB Interpretation No. 47 (FIN 47),Accounting for Conditional Asset Retirement Obligationswas issued. We were required to adopt this interpretation as of December 31, 2005. We have conditional asset retirement obligations related to our Cotton Valley, Shreveport and Princeton refineries related to asbestos. We believe that there is an indeterminate settlement date for these obligations so that a fair value cannot be reasonably estimated. Therefore, we did not expect to record any liability for asset retirement obligations related to these refineries upon adoption of FIN 47.


Item 7A.	*Quantitative and Qualitative Disclosures About Market Risk*

Interest Rate Risk

We are exposed to market risk from fluctuations in interest rates. As of December 31, 2005, we had approximately $268.0 million of variable rate debt. Holding other variables constant (such as debt levels) and not taking into account our use of the net proceeds we received from our initial public offering, a one hundred basis point change in interest rates on our variable rate debt as of December 31, 2005 would be expected to have an impact on net income and cash flows for 2006 of approximately $2.7 million.

Commodity Price Risk

Both our profitability and our cash flows are affected by volatility in prevailing crude oil and natural gas prices and crack spreads (the difference between crude oil prices and refined product sale 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 and specialty 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 $8.9 million and our fuel product segment cost of sales by $8.2 million on an annual basis based on our results for the year ended December 31, 2005.

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 historical policy had generally been to enter into crude oil contracts for a period no greater than twelve months forward and for no more than 70% of our anticipated crude oil purchases related to non-fuels production. Our policy going forward is generally to enter into crude oil contracts for three to six months forward and for 50% to 70% of our anticipated crude oil purchases related to our specialty products production.

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 $2.4 million on an annual basis based on our results for the year ended December 31, 2005.

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.

Crack Spread Volatility

Our profitability and cash flows are also significantly impacted by the crack spreads we experience. Crack spreads represent the difference between the prices we are able to realize for our fuel products and the cost of the crude oil we must purchase to produce those products. Holding other variables constant, and excluding the impact of our current hedges, we expect a $0.50 change in the Gulf Coast 2/1/1 crack spread per barrel would change our annual fuel products segment gross profit by $4.1 million based on our results for the year ended December 31, 2005.

Crack Spread Hedging Policy

In order to manage our exposure to crack spreads, we enter into fuels product margin swap and collar contracts. We began to implement this policy in October 2004. Our historical policy had been to enter into crack spread hedging contracts for a period no greater than two years and for no more than 75% of anticipated fuels production. Following the completion of our initial public offering, our policy is to enter into derivative contracts to hedge our refining margins for a period no greater than five years and for no more than 75% of anticipated fuels production.

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 refining margins for a rolling two-year period for at least 40%, and no more than 80%, of our anticipated fuels production.

The historical impact of fair value fluctuations in our derivative instruments has been reflected in the realized/unrealized gain (loss) on derivative instruments line items in our consolidated statements of operations. It is our intention to designate future derivative transactions as hedges. As a result, gain (loss) on derivative transactions recognized in our historical financial statements may not be consistent with future periods.

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 2 to our consolidated financial statements for a discussion of the accounting treatment for the various types of derivative transactions, and see Note 7 “Derivative Instruments” for a further discussion of our derivatives policy.

Existing Derivative Instruments

The following tables provide information about our derivative instruments as of December 31, 2005:

2006 Derivative Transactions


			Lower Put		Upper Put		Call Floor		Call Ceiling
Crude Oil Put/Call Spreads	Barrels		($/Bbl)		($/Bbl)		($/Bbl)		($/Bbl)

January 2006		248,000	$	46.02	$	55.57	$	65.57	$	75.57
February 2006		224,000		46.13		55.71		65.71		75.71
March 2006		248,000		45.64		55.41		65.41		75.41
April 2006		240,000		45.85		55.58		65.58		75.58

Annual Totals		960,000
Average Price			$	45.90	$	55.56	$	65.56	$	75.56


2/1/1 Crack Spread Swaps	Barrels		($/Bbl)

First Quarter 2006		1,035,000	$	9.00
Second Quarter 2006		1,039,000		8.98
Third Quarter 2006		1,043,000		8.65
Fourth Quarter 2006		1,043,000		8.28

Annual Totals		4,160,000
Average Price			$	8.73


					Ceiling
			Floor Price		Price
2/1/1 Crack Spread Collars	Barrels		($/Bbl)		($/Bbl)

First Quarter 2006		675,000	$	7.29	$	9.62
Second Quarter 2006		680,000		7.82		10.15
Third Quarter 2006		685,000		7.59		9.59
Fourth Quarter 2006		685,000		6.30		8.30

Annual Totals		2,725,000
Average Price			$	7.25	$	9.41


Natural Gas Swaps	MMBtu		$/MMBtu

First Quarter 2006		600,000	$	9.84
Second Quarter 2006		—		—
Third Quarter 2006		—		—
Fourth Quarter 2006		—		—

Annual Totals		600,000
Average Price			$	9.84

2007 Derivative Transactions


2/1/1 Crack Spread Swaps	Barrels		($/Bbl)

First Quarter 2007		1,260,000	$	11.59
Second Quarter 2007		1,273,000		11.56
Third Quarter 2007		1,282,000		11.60
Fourth Quarter 2007		1,282,000		11.60

Annual Totals		5,097,000
Average Price			$	11.58

As of March 6, 2006, the company has added the following derivative instruments to the above transactions:

2006 Derivative Transactions


			Lower Put		Upper Put		Call Floor		Call Ceiling
Crude Oil Put/Call Spreads	Barrels		($/Bbl)		($/Bbl)		($/Bbl)		($/Bbl)

May 2006		248,000	$	52.60	$	62.60	$	72.60	$	82.60

Annual Totals		248,000
Average Price			$	52.60	$	62.60	$	72.60	$	82.60


Natural Gas Swaps	MMBtu		$/MMBtu

Third Quarter 2006		200,000	$	8.52
Fourth Quarter 2006		300,000		8.52

Annual Totals		500,000
Average Price			$	8.52

2007 Derivative Transactions


Crack Spread Swaps	Barrels		($/Bbl)

First Quarter 2007		180,000	$	15.20
Second Quarter 2007		182,000		15.20
Third Quarter 2007		184,000		15.20
Fourth Quarter 2007		184,000		15.20

Annual Totals		730,000
Average Price			$	15.20


Natural Gas Swaps	MMBtu		$/MMBtu

First Quarter 2007		300,000	$	8.52

Annual Totals		300,000
Average Price			$	8.52

2008 Derivative Transactions


2/1/1 Crack Spread Swaps	Barrels		($/Bbl)

First Quarter 2008		910,000	$	10.48
Second Quarter 2008		910,000		10.85
Third Quarter 2008		920,000		11.22
Fourth Quarter 2008		920,000		11.22

Annual Totals		3,660,000
Average Price			$	10.94

2009 Derivative Transactions


2/1/1 Crack Spread Swaps	Barrels		($/Bbl)

First Quarter 2009		810,000	$	10.76
Second Quarter 2009		819,000		10.76
Third Quarter 2009		828,000		10.76
Fourth Quarter 2009		828,000		10.76

Annual Totals		3,285,000
Average Price			$	10.76

2010 Derivative Transactions


2/1/1 Crack Spread Swaps	Barrels		($/Bbl)

First Quarter 2010		180,000	$	10.10
Second Quarter 2010		182,000		10.10
Third Quarter 2010		184,000		10.10
Fourth Quarter 2010		184,000		10.10

Annual Totals		730,000
Average Price			$	10.10


Item 8.	*Financial Statements*

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of

Calumet Lubricants Co., Limited Partnership

We have audited the accompanying consolidated balance sheets of Calumet Lubricants Co., Limited Partnership as of December 31, 2005 and 2004 and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2005. 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 Lubricants Co., Limited Partnership at December 31, 2005 and 2004 and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Indianapolis, Indiana

March 9, 2006

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

CONSOLIDATED BALANCE SHEETS


	December 31,
	2005		2004
	(In thousands)

ASSETS
Current assets:
Cash	$	12,173	$	18,087
Accounts receivable:
Trade, less allowance for doubtful accounts of $750 in 2005 and $456 in 2004		109,757		53,798
Other		5,537		4,912

		115,294		58,710

Inventories		108,431		82,990
Prepaid expenses		10,799		17,272
Derivative assets		3,359		4,011
Deposits and other current assets		8,851		3,150

Total current assets		258,907		184,220
Property, plant and equipment, net		127,846		126,585
Other noncurrent assets, net		12,964		7,401

Total assets	$	399,717	$	318,206


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	44,759	$	58,027
Accrued salaries, wages and benefits		8,164		1,978
Turnaround costs		2,679		2,098
Other taxes payable		4,209		435
Asset retirement obligation		—		100
Other accrued expenses		2,418		2,747
Other current liabilities		—		4,238
Current portion of long-term debt		500		19,795
Derivative liabilities		30,449		—

Total current liabilities		93,178		89,418
Long-term debt, less current portion		267,485		194,274

Total liabilities		360,663		283,692

Commitments and contingencies
Total partners’ capital		39,054		34,514

Total liabilities and partners’ capital	$	399,717	$	318,206

See accompanying notes to consolidated financial statements.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2005			2004			2003
	(In thousands except per unit data)

Sales	$	1,289,072		$	539,616		$	430,381
Cost of sales		1,148,715			501,284			385,890

Gross profit		140,357			38,332			44,491

Operating costs and expenses:
Selling, general and administrative		22,126			13,133			9,432
Transportation		46,849			33,923			28,139
Taxes other than income taxes		2,493			2,309			2,419
Other		871			839			905
Restructuring, decommissioning and asset impairments		2,333			317			6,694

Operating income (loss)		65,685			(12,189	)		(3,098	)

Other income (expense):
Equity in (loss) income of unconsolidated affiliates		—			(427	)		867
Interest expense		(22,961	)		(9,869	)		(9,493	)
Debt extinguishment costs		(6,882	)		—			—
Realized gain (loss) on derivative instruments		2,830			39,160			(961	)
Unrealized gain (loss) on derivative instruments		(27,586	)		(7,788	)		7,228
Other		242			83			32

Total other income (expense)		(54,357	)		21,159			(2,327	)

Net income (loss)	$	11,328		$	8,970		$	(5,425	)

General partner’s interest in net income (loss)	$	1,133		$	897		$	(542	)
Limited partners’ interest in net income (loss)	$	10,195		$	8,073		$	(4,883	)
Basic and diluted net income (loss) per limited partner unit	$	10,195		$	8,073		$	(4,883	)

Limited partnership units, basic and diluted		1,000			1,000			1,000

See accompanying notes to consolidated financial statements.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Accumulated Other		Partners’ Capital
	Comprehensive		General			Limited
	Income		Partner			Partners			Total
	(In thousands)

Balance at December 31, 2002	$	—	$	3,097		$	27,872		$	30,969
Net loss		—		(542	)		(4,883	)		(5,425	)

Balance at December 31, 2003		—		2,555			22,989			25,544
Net income		—		897			8,073			8,970

Balance at December 31, 2004		—		3,452			31,062			34,514
Net income		—		1,133			10,195			11,328
Distributions to partners		—		(728	)		(6,557	)		(7,285	)
Other comprehensive income		497		—			—			497

Balance at December 31, 2005	$	497	$	3,857		$	34,700		$	39,054

See accompanying notes to consolidated financial statements.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2005			2004			2003
	(In thousands)

Operating activities
Net income (loss)	$	11,328		$	8,970		$	(5,425	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation		9,920			6,224			6,181
Amortization		466			703			588
Provision for doubtful accounts		294			216			12
Loss on disposal of property and equipment		232			59			943
Equity in loss (income) of unconsolidated affiliates		—			427			(867	)
Restructuring charge		1,693			—			874
Debt extinguishment costs		4,173			—			—
Other		497			332			926
Dividends received from unconsolidated affiliates		—			3,470			750
Changes in assets and liabilities:
Accounts receivable		(56,878	)		(19,399	)		(4,670	)
Inventories		(25,441	)		(20,304	)		15,547
Prepaid expenses		6,473			(8,472	)		(834	)
Derivative activity		31,101			5,046			(6,265	)
Deposits and other current assets		(5,904	)		(3,124	)		271
Other noncurrent assets		(4,561	)		161			(550	)
Accounts payable		(13,268	)		25,764			(1,809	)
Accrued salaries, wages and benefits		6,186			1,323			(1,107	)
Accrued turnaround costs		581			246			375
Other taxes payable		3,774			(53	)		191
Asset retirement obligation		(100	)		(1,276	)		1,376
Other accrued expenses		(329	)		963			544
Other current liabilities		(4,238	)		(1,135	)		436
Other noncurrent liabilities		—			(753	)		(439	)

Net cash provided by (used in) operating activities		(34,001	)		(612	)		7,048
Investing activities
Additions to property, plant and equipment		(12,963	)		(43,033	)		(12,163	)
Proceeds from disposal of property, plant and equipment		60			103			223

Net cash used in investing activities		(12,903	)		(42,930	)		(11,940	)
Financing activities
Proceeds from borrowings — credit agreements with third parties		1,415,374			93,940			—
Payments of borrowings — credit agreements with third parties		(1,197,184	)		(44,145	)		—
Debt issuance costs		(5,641	)		(5,656	)		—
Proceeds from borrowings — credit agreement with limited partners		546,565			586,410			260,159
Payments of borrowings — credit agreement with limited partners		(710,839	)		(568,988	)		(255,275	)
Distributions to partners		(7,285	)		—			—

Cash provided by financing activities		40,990			61,561			4,884

Net increase (decrease) in cash		(5,914	)		18,019			(8	)
Cash at beginning of period		18,087			68			76

Cash at end of period	$	12,173		$	18,087		$	68

Supplemental disclosure of cash flow information
Interest paid	$	22,890		$	9,367		$	9,189

See accompanying notes to consolidated financial statements.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands, except operating, unit and per unit data)


1.	Description of the Business

Calumet Lubricants Co., Limited Partnership (Calumet or the Company) is an Indiana limited partnership. The general partner is Calumet, Incorporated. The general partner owns 10% of Calumet while the remaining 90% is owned by limited partners, which collectively hold all 1,000 of Calumet’s limited partnership units. Calumet is engaged in the production and marketing of crude oil-based specialty lubricating oils, fuels, solvents and waxes. Calumet owns a refinery located in Princeton, Louisiana, a refinery located in Cotton Valley, Louisiana, a terminal located in Burnham, Illinois, a wax blending, packaging and warehousing facility located in Reno, Pennsylvania, and a refinery located in Shreveport, Louisiana (the Shreveport Refinery).

Effective October 25, 2004 in conjunction with financing agreements entered into related to the Shreveport Refinery as discussed in Notes 3 and 6, Calumet contributed the assets and certain liabilities related to the Shreveport Refinery to an Indiana limited liability company, Calumet Shreveport, LLC (Calumet Shreveport). Calumet is the sole member of Calumet Shreveport. Calumet Shreveport, LLC then contributed the assets and certain liabilities of the Shreveport Refinery to two Indiana limited liability companies, Calumet Shreveport Fuels, LLC (Fuels) and Calumet Shreveport Lubricants & Waxes, LLC (Lubricants & Waxes). The sole member of both Fuels and Lubricants & Waxes is Calumet Shreveport.


2.	Summary of Significant Accounting Policies

Consolidation

The consolidated financial statements include the accounts of Calumet and its wholly-owned subsidiary, Calumet Shreveport and Calumet Shreveport’s wholly owned subsidiaries Fuels and Lubricants & Waxes. All intercompany transactions and accounts have been eliminated. Hereafter, the consolidated companies are referred to as the Company.

Use of Estimates

The Company’s financial statements are prepared in conformity with U.S. generally accepted accounting principles which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash

Cash includes all highly liquid investments with a maturity of three months or less at the time of purchase.

Inventories

The cost of inventories is determined using thelast-in, first-out (LIFO) method. Inventories are valued at the lower of cost or market value.

Inventories consist of the following:


	December 31,
	2005		2004

Raw materials	$	28,299	$	39,476
Work in process		29,737		12,669
Finished goods		50,395		30,845

	$	108,431	$	82,990

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The replacement cost of these inventories, based on current market values, would have been $47,763 and $26,942 higher at December 31, 2005 and 2004, respectively.

Accounts Receivable

The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Receivables are generally due within 30 days. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical credit experience and expected future trends. The activity in the allowance for doubtful accounts was as follows:


	December 31,
	2005			2004		2003

Beginning balance	$	456		$	240	$	242
Provision		317			216		12
Write-offs, net		(23	)		—		(14	)

Ending balance	$	750		$	456	$	240

Prepaid Expenses

Prepaid expenses as of December 31, 2005 and 2004 include payments made to crude oil suppliers in the amount of $8,271 and $14,334, respectively, to prepay for certain of the Company’s future crude oil purchases.

Property, Plant and Equipment

Property, plant and equipment are stated on the basis of cost. Depreciation is calculated generally on composite groups, using the straight-line method over the estimated useful lives of the respective groups.

Property, plant and equipment, including depreciable lives, consists of the following:


	December 31,
	2005			2004

Land	$	973		$	957
Buildings and improvements (10 to 40 years)		1,602			1,550
Machinery and equipment (2 to 20 years)		162,651			148,992
Furniture and fixtures (5 to 10 years)		2,235			1,928
Construction-in-progress		3,878			5,368

		171,339			158,795
Less accumulated depreciation		(43,493	)		(32,210	)

	$	127,846		$	126,585

Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related depreciation are retired, and any gain or loss is reflected in earnings.

During the years 2005, 2004, and 2003, the Company incurred $23,154, $10,171, and $9,493, respectively, of interest expense of which $193, $302, and $0, respectively, were capitalized as a component of property, plant and equipment.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Turnaround Costs

Periodic major maintenance and repairs (turnaround costs) applicable to refining facilities are accounted for using theaccrue-in-advance method. Normal maintenance and repairs of all other property, plant and equipment are charged to cost of sales as incurred. Renewals, betterments and major repairs that materially extend the life of the properties are capitalized. Turnaround activity was as follows:


	December 31,
	2005			2004			2003

Beginning balance	$	2,098		$	1,852		$	1,477
Provision		3,939			2,129			2,125
Usage		(3,358	)		(1,883	)		(1,750	)

Ending balance	$	2,679		$	2,098		$	1,852

Impairment of Long-Lived Assets

The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In that event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair market value of the long-lived asset. Fair market value is determined primarily using the anticipated cash flows discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.

Revenue Recognition

The Company recognizes revenue on orders received from its customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under the Company’s normal billing and credit terms, all of the Company’s obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is upon shipment to the customer.

Income Taxes

The Company, as a partnership, is not liable for income taxes. Income taxes are the responsibility of the partners, with earnings of the Company included in partners’ earnings.

Derivatives

The Company enters into several types of derivative instruments related to the purchase of crude oil, natural gas, as well as fuels product margins (crack spreads), in an effort to minimize the financial impact of fluctuations in the prices of certain commodities related to its business, as further described in Note 7. The Company’s policy is generally to enter into crude oil contracts for a period no greater than three to six months forward and for 50% to 70% of anticipated crude oil purchases related to speciality products production. The Company’s policy is generally to enter into crack spread contracts for a period no greater than five years forward and for no more than 75% of fuels production. Although the counterparties expose the Company to credit risk in the event of nonperformance, the Company does not expect nonperformance.

During 2003, 2004 and through November 30, 2005, the Company had not designated any of its derivative instruments as hedges in accordance with the provisions of Statement of Financial Accounting Standards

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(SFAS) No. 133,Accounting for Derivative Instruments and Hedging Activities. Changes in the fair value of derivatives which have not been designated as hedges are recorded each period in earnings and reflected in unrealized gain (loss) on derivative instruments in the consolidated statements of operations.

Beginning on December 1, 2005, the Company began designating certain derivative contracts related to the purchase of crude oil for its specialty products segment and natural gas purchases for all of the Company’s refineries as cash flow hedges to the extent they were effective. Changes in the fair value of these derivative hedge contracts subsequent to December 1, 2005 are recorded in other comprehensive income. The crude and natural gas other comprehensive income balances of $1,231 and $(734), respectively, will be reclassified to earnings in the same period as the hedged transaction. The entire other comprehensive income balance at December 31, 2005 will be reclassified to earnings by April 2006 for the crude hedges and March 2006 for the natural gas hedges.

Equity Investments in Unconsolidated Affiliates

Bareco Products (Bareco) was a South Carolina general partnership which marketed finished wax products. The Company acquired a 50% interest in Bareco during 2000. The Company accounts for this investment under the equity method of accounting. Therefore, the Company’s share of income and loss generated by Bareco is reflected as equity in income (loss) of unconsolidated affiliates in the consolidated statements of operations. As further discussed in Note 4, during December 2003 the Company and its joint venture partner entered into an agreement to dissolve the Bareco Products partnership.

Other Noncurrent Assets

Other noncurrent assets at December 31, 2005 and 2004 include $5,565 and $5,647, net of accumulated amortization of $76 and $226 of deferred debt issuance costs, which are being amortized on a straight-line basis over the life of the related debt instruments.

Other noncurrent assets also include $1,021 and $1,476 at December 31, 2005 and 2004, respectively, of intangible assets, net of accumulated amortization, purchased to facilitate the sales of horticultural spray oil products. These intangible assets are being amortized using the straight-line method, over an estimated useful life of five years. Annual amortization for 2006 and 2007 will be $455, with the remaining balance of approximately $111 amortized in 2008. Accumulated amortization on these intangible assets was $1,255 and $800 at December 31, 2005 and 2004, respectively.

Shipping and Handling Costs

The Company adheres to Emerging Issues Task Force (EITF) 00-10,Accounting for Shipping and Handling Fees and Costs. This EITF requires the classification of shipping and handling costs billed to customers in sales and the classification of shipping and handling costs incurred in cost of sales, or if classified elsewhere to be disclosed. The Company has reflected $46,849, $33,923 and $28,139 for the years ended December 31, 2005, 2004, and 2003, respectively, for costs billed to customers in transportation in the consolidated statements of operations.

New Accounting Pronouncements

In November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting (SFAS) No. 151, Inventory Costs — an amendment of Accounting Research Bulletin (ARB) No. 43, Chapter 4. The Statement clarifies that abnormal amounts of idle facility expense, freight, handling costs and wasted materials should be recognized as current-period expenses regardless of how abnormal the circumstances. In addition, this Statement requires that the allocation of fixed overheads to the costs of conversion be based upon normal production capacity levels. The Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company does not anticipate that this Statement will have a material effect on its financial position, results of operations or cash flows.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Statement 123(R) is effective for fiscal years beginning after July 1, 2005. The Company expects to adopt Statement 123(R) using the “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of Statement 123(R) for all share-based payments granted after the effective date and based on the requirements of Statement 123 for all awards granted to employees prior to the effective date of Statement 123(R) that remain unvested on the effective date. The total impact of adoption of Statement 123(R) cannot be predicted at this time because it will depend on levels of share-based payments granted in the future.

In 2005, the FASB Interpretation No. 47 (FIN 47),Accounting for Conditional Asset Retirement Obligationswas issued. The Company adopted this interpretation as of December 31, 2005. The Company has conditional asset retirement obligations related to its Cotton Valley, Shreveport and Princeton refineries related to asbestos. However, the Company believes that there is an indeterminate settlement date for these obligations and; thus, fair value cannot be reasonably estimated. Therefore, at the date of adoption, December 31, 2005, the Company did not record any liability for asset retirement obligations related to these refineries.


3.	Shreveport Reconfiguration

During 2004, the Company substantially completed the reconfiguration of the Shreveport Refinery to add motor fuels production, including gasoline, diesel and jet fuel, as well as to increase overall feedstock throughput. The Shreveport Refinery was fully operational and met its completion requirements as of February 28, 2005, as required by the Company’s loan agreements then in effect. The capital project, of which $35,967 had been expended through December 31, 2004, and $39,663 had been expended through December 31, 2005, included the recommissioning of several existing idled fuel production units. As discussed in Note 1, the Company formed legal entities to hold the assets and liabilities related to the Shreveport Refinery. In conjunction with the reconfiguration and as described in Note 6, Calumet Shreveport, Fuels and Lubricants & Waxes entered into standalone financing arrangements during 2004, including a term loan agreement and a revolving loan agreement to fund capital expenditures and additional working capital requirements. These financing arrangements were repaid on December 9, 2005 as described in Note 6.


4.	Restructuring, Decommissioning and Asset Impairments

Rouseville

In connection with the Company’s decision to exit its multigrade wax processing facility located in Rouseville, Pennsylvania (Rouseville), in 2003 the Company began implementation of a plan to demolish the Rouseville facility assets. The demolition was completed during 2004. The facility assets included operating units, equipment, tankage and real property. As a result of the decision to demolish the Rouseville facility assets, the Company recorded a facility asset impairment charge in 2003 for the full amount of the carrying value of the assets as of the decision date to demolish the assets. The Company also incurred asset decommissioning costs during 2003, consisting primarily of asbestos abatement costs at the Rouseville wax processing facility. Asset decommissioning costs of $4,202 and the asset impairment charge of $2,492 related to this facility are reflected in restructuring, decommissioning and asset impairments in the consolidated statements of operations for the year ended December 31, 2003. In 2004, the Company incurred additional charges totaling $317 primarily related to the completion of the Rouseville asset decommissioning.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In accordance with Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations, the Company recorded an asset retirement obligation during 2003 for obligations associated with the retirement of fixed assets at its Rouseville wax processing facility as of its decision date to demolish the facility, as discussed above. This obligation consisted primarily of remaining asbestos abatement costs as well as other costs, which were substantially completed by the end of 2004.

A rollforward of the Company’s asset retirement obligation for the years ended December 31, 2005, 2004 and 2003 is as follows:


Balance January 1, 2003	$	—
2003 Rouseville asset retirement obligation provision		1,618
2003 Interest cost accretion		14
2003 Payments		(256	)

Balance December 31, 2003		1,376

2004 Rouseville asset retirement obligation provision		—
2004 Interest cost accretion		35
2004 Payments		(1,311	)

Balance December 31, 2004		100
2005 Payments		(100	)

Balance December 31, 2005	$	—

Bareco Products

During December 2003, the Company entered into an agreement with its joint venture partner to dissolve the Bareco Products partnership and for each partner to pursue its own wax marketing interests. Per the terms of the agreement, all significant business activities undertaken by the partnership ended as of December 31, 2003. The affairs of Bareco Products were wound down during 2004, and legal dissolution of the partnership was completed during 2005.

As a result of the dissolution agreement, the Company recorded a $564 asset impairment loss in 2003, which is reflected in equity in (loss) income of unconsolidated affiliates in the consolidated statements of operations for the year ended December 31, 2003, related to its equity investment in Bareco Products which represented management’s estimate of the difference between the carrying value of the Company’s investment and the Company’s share of proceeds from liquidation of the partnership. In 2004, the Company incurred costs in excess of amounts estimated in 2003 related to the liquidation of the partnership. These costs are reflected in equity in (loss) income of unconsolidated affiliates in the consolidated statements of operations for the year ended December 31, 2004.

Reno

In June 2005, the Company began the process of closing its wax packaging facility in Reno, Pennsylvania (Reno) including the termination of employees and the commencement of decommissioning activities. Given these circumstances, the Company evaluated the carrying amount of long-lived assets at Reno in accordance with Statement of Financial Accounting Standards No. 144,Accounting for Impairment or Disposal of Long-lived Assets(SFAS 144). The Company concluded that the carrying value of these assets was impaired. Thus, an impairment charge of $1,718 has been recorded in restructuring, decommissioning and asset impairments in the consolidated statements of operations for the year ended December 31, 2005 in order to write-down the carrying value to estimated fair value. This facility has historically been included in the specialty products segment and served to package multigrade waxes.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Commitments and Contingencies

Leases

The Company has various operating leases for the use of land, storage tanks, compressor stations, rail cars, equipment, precious metals, operating unit catalyst and office facilities that extend through August 2015. Renewal options are available on certain of these leases in which the Company is the lessee. Rent expense for the years ended December 31, 2005, 2004, and 2003 was $8,389, $7,415 and $7,317, respectively.

As of December 31, 2005, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows:


Year	Commitment

2006	$	8,387
2007		6,075
2008		3,938
2009		3,660
2010		3,051
Thereafter		9,002

Total	$	34,113

Effective March 1, 2005, the Company entered into a crude purchase contract with a supplier that contains minimum annual purchase requirements. To the extent the Company does not meet this requirement, it would be required to pay $0.25 per barrel on the difference between the minimum purchase requirement and the actual purchases. Since inception of the contract, the Company has taken delivery of all minimum requirements. As of December 31, 2005, the estimated minimum purchase requirements under this contract and other crude purchase contracts were as follows:


Year	Commitment

2006	$	375,295
2007		305,309
2008		69,813
2009		25,069
2010		4,052
2011		—
Thereafter		—

Total	$	779,538

Contingencies

From time to time, the Company is a party to certain claims and litigation incidental to its business. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position or results of operations.

Environmental

The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations can impair the Company’s operations that affect the environment in many ways, such as requiring the acquisition of permits to

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

conduct regulated activities; restricting the manner in which the Company can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities for pollution resulting from its operations. Certain environmental laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes, or other materials have been released or disposed.

Failure to comply with environmental laws and regulations may result in the triggering of administrative, civil and criminal measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of the Company’s operations. On occasion, the Company receives notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. In particular, the Louisiana Department of Environmental Quality (“LDEQ”) has proposed penalties and supplemental projects totaling $191,280 for the following alleged violations: (i) a May 2001 notification received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations, as identified in the course of the Company’s Leak Detection and Repair program, and also for failure to submit various reports related to the facility’s air emissions; (ii) a December 2002 notification received by the Company’s Cotton Valley refinery from the LDEQ regarding alleged violations for excess emissions, as identified in the LDEQ’s file review of the Cotton Valley refinery; 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. The Company is 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. Management is of the opinion that the ultimate resolution of this matter will not have a material adverse impact on the Company’s financial position or results of operations.

The Company has recently 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. The Company expects that the LDEQ’s primary focus under the state initiative will be on four compliance and enforcement concerns: (i) Prevention of Significant Deterioration/New Source Review; (ii) New Source Performance Standards for fuel gas combustion devices, including flares, heaters and boilers; (iii) Leak Detection and Repair requirements; and (iv) Benzene Waste Operations National Emission Standards for Hazardous Air Pollutants. The Company is 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 Company’s discussions, the Company anticipates that it will ultimately be required to make emissions reductions requiring capital investmentsand/or increased operating expenditures at the Company’s three Louisiana refineries.

The Company is indemnified by Shell Oil Company, as successor to Pennzoil-Quaker State Company and Atlas Processing Company, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to its acquisition of the facility. The indemnity is unlimited in amount and duration, but requires the Company to contribute up to $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities.

Standby Letters of Credit

The Company has agreements with various financial institutions for standby letters of credit which have been issued to domestic vendors. As of December 31, 2005 and 2004, the Company had outstanding standby letters of credit of $37,746 and $19,430, respectively.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


6.	Long-Term Debt

Long-term debt consisted of the following:


	December 31,
	2005		2004

Borrowings under revolving credit agreement with third-party lenders, interest at prime (7.25% at December 31, 2005), interest payments monthly, borrowings due December 2010	$	92,985	$	—
Borrowings under term loan agreement with third-party lenders, interest at rate of LIBOR plus 3.50% (7.99% at December 31, 2005), interest payments quarterly, borrowings due December 2012		175,000		—
Borrowings under credit agreement with a limited partner, interest at variable rates (5.3% at December 31, 2004), interest payments monthly, borrowings due June 30, 2007		—	$	152,874
Notes payable to limited partners, interest at prime rate (5.3% at December 31, 2004), interest payments monthly, principal due June 30, 2007		—		11,400
Borrowings under term loan agreement with a third-party lender, interest at a fixed rate of 14%, interest payments monthly, borrowings due December 31, 2008		—		30,000
Borrowings under revolving loan agreement with third-party lenders, interest at variable rates (5.3% at December 31, 2004), interest payments monthly, borrowings due December 31, 2008		—		19,795

Total long-term debt		267,985		214,069
Less current portion of long-term debt		500		19,795

	$	267,485	$	194,274

On December 9, 2005, the Company paid off its existing indebtedness by entering into a $225,000 senior secured revolving credit facility due December 2010 and a $225,000 senior secured first lien credit facility consisting of a $175,000 term loan facility and a $50,000 letter of credit facility to support crack spread hedging, which bears interest at 3.50%. These facilities contain financial covenants including a fixed charge coverage ratio and a consolidated leverage ratio. The revolving credit facility borrowings are limited by advance rates of percentages of eligible accounts receivable and inventory as defined by the revolving credit agreement. The maximum borrowing capacity at December 31, 2005 was $196,211, with $65,480 available for additional borrowings based on collateral and specified availability limitations. Subsequent to December 31, 2005, the Company repaid approximately $13.7 million of the revolving credit facility with proceeds from the closing of the IPO. The term loan facility borrowings are secured by a first lien on the property, plant and equipment of the Company and its subsidiaries. After the repayment of approximately $125.7 million of the term loan facility and the associated accrued interest with proceeds from the closing of the IPO, the term loan requires quarterly principal payments of $0.1 million through December 2011 and quarterly principal payments of approximately $11.8 million thereafter until maturing in December 2012. The Company is in compliance with all covenants and restrictions defined in these credit agreements. As of December 31, 2005, the Company had $11.0 million of letters of credit outstanding on the crack spread hedging facility.

The credit agreement with a limited partner that was repaid on December 9, 2005 with the above credit facilities provided up to $180,000 in long-term borrowings. The Company was a limited guarantor of a bank credit facility of the limited partner and two other related party co-obligors. The guarantee was limited to advances to the Company from any party to the bank credit facility, which would include the credit agreement with a limited partner of $152,874 and the notes payable to limited partners of $11,400 as of December 31, 2004. In addition, all assets of the Company, excluding those assets related to the Shreveport Refinery, were pledged as collateral to the bank credit

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

facility. All guarantees and pledges of assets under this agreement were released with the entering into the current credit agreements on December 9, 2005.

The term loan agreement with a third-party lender was entered into effective October 25, 2004 by Calumet Shreveport, Fuels and Lubricants & Waxes to fund the reconfiguration of the Shreveport Refinery and was repaid on December 9, 2005 with the above credit facilities. The term loan agreement allowed for prepayments; however, such prepayments were subject to additional fees of $2.7 million which were paid on December 9, 2005 upon the repayment of this loan. All of the assets of Calumet Shreveport, Fuels and Lubricants & Waxes were pledged as collateral to the term loan agreement. All guarantees and pledges of assets under this agreement were released with the entering into the current credit agreements on December 9, 2005.

The revolving loan agreement with third-party lenders was entered into effective October 25, 2004 by Calumet Shreveport, Fuels and Lubricants & Waxes to fund working capital requirements related to the reconfiguration of the Shreveport Refinery. Calumet Lubricants Co., Limited Partnership was neither an obligor nor guarantor under the revolving loan agreement. The revolving loan agreement provided up to $125,000 in total borrowings. Borrowings under the revolving loan were limited generally by advance rates of percentages of eligible accounts receivable and inventory as defined in the revolving loan agreement. All of the assets of Calumet Shreveport, Fuels and Lubricants & Waxes were pledged as collateral to the revolving loan agreement. All guarantees and pledges of assets under this agreement were released with the entering into the current credit agreements on December 9, 2005.

As of December 31, 2005, maturities of the Company’s long-term debt is as follows:


Year	Maturity

2006	$	500
2007		500
2008		500
2009		500
2010		93,485
2011 and thereafter	$	172,500

Total	$	267,985


7.	Derivatives

Crude Oil Call Option Contracts

During 2005 and 2004, the Company entered into crude oil call option contracts with counterparties in which the Company acquired the right, but not the obligation, to purchase a specified portion of the Company’s anticipated crude oil purchases at the option strike price. These call option rights were acquired by the Company through the payment of option premiums to the counterparty. These agreements require the counterparty to pay the Company if the market price is greater than the option strike price stated in the contract. No payments are made between the Company and the counterparty if the market price is less than the option strike price stated in the contract as the option would expire unexercised by the Company. The payments are calculated based on the difference between the market price and the option strike price per barrel multiplied by the number of barrels stated in each contract. At December 31, 2005 all crude oil call options had expired and were recognized as a component of realized gain (loss) on derivative instruments in the consolidated statements of operations.

Crude oil call option contracts consisted of the following at December 31, 2004:


			Low Call		High Call
Option Contract Expiration Dates	Barrels		($/Bbl)		($/Bbl)		Average

January 1, 2005 to December 31, 2005		1,460,000	$	45.00	$	45.00	$	45.00

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Crude Oil Collar Contracts

The Company also entered into crude oil collar contracts in 2005 and 2004 with counterparties in which the Company either (i) purchased a crude oil call option contract from the counterparty while simultaneously selling a crude oil put option contract to the counterparty, (ii) purchased a crude oil call option contract from the counterparty while simultaneously selling both a crude oil put option with a lower strike price than the purchased crude oil call option contract and a crude oil call option with a higher strike price than the purchased crude oil call option contract, or (iii) purchased and sold both crude oil call and put options contracts (4-way collar) with the counterparty at varying strike prices with the purchased put option at the lowest strike price, the sold put option at the next highest strike price, the purchased call option at the third highest strike price and the sold call option at the highest strike price. Generally, these crude oil collar contracts required no net premium to be paid by the Company to the counterparty as the premium for the purchased call option was offset by the proceeds of the sold calland/or put options, as applicable. For agreements for collar types (i) or (ii), the counterparty will pay the Company if the market price is greater than the purchased call option strike price stated in the contract, the Company will pay the counterparty if the market price is less than the sold put option strike price stated in the contract, and the Company will pay the counterparty if the market price is greater than the sold call option strike price. No payments are made between the Company and the counterparty if the market price is greater than or equal to the sold put option strike price but less than or equal to the purchased call option strike price stated in the contract as both options would expire unexercised by both the Company and the counterparty. For agreements for collar type (iii), the counterparty pays the Company if the market price is greater than the purchased call option strike price and the payment from the counterparty to the Company is capped at the difference between the sold call option strike price and the purchased call option strike price. The Company pays the counterparty if the market price is lower than the sold put option strike price and the payment from the Company to the counterparty is capped at the difference between the purchased put option strike price and the sold put option strike price. If the market price is greater than the sold put option strike price, but lower than the purchased call option strike price, no payments between the Company and the counterparty are made. The payments are calculated based on the difference between the market price and the call option or put option strike price per barrel, whichever is applicable, multiplied by the number of barrels stated in each contract.

Crude oil collar contracts consisted of the following at December 31, 2005:


			Lower Put		Upper Put		Call Floor		Call Ceiling
Crude Oil Put/Call Spread Contracts Expiration Dates	Barrels		($/Bbl)		($/Bbl)		($/Bbl)		($/Bbl)

January 2006		248,000	$	46.02	$	55.57	$	65.57	$	75.57
February 2006		224,000		46.13		55.71		65.71		75.71
March 2006		248,000		45.64		55.41		65.41		75.41
April 2006		240,000		45.85		55.58		65.58		75.58

Totals		960,000
Average price			$	45.90	$	55.56	$	65.56	$	75.56

Crude oil collar contracts consisted of the following at December 31, 2004:


			Lower Put		Call Floor		Call Ceiling
Crude Oil Put/Call Spread Contracts Expiration Dates	Barrels		($/Bbl)		($/Bbl)		($/Bbl)

January 1, 2005 to December 31, 2005		2,920,000	$	38.67	$	50.99	$	60.06

Fuels Product Margin (Crack Spread) Swap Contracts

Beginning in 2004, the Company began entering into fuels product margin (crack spread) swap contracts with counterparties to fix the margins of the difference between certain fuels product selling prices and the cost of crude oil, beginning in 2005. For purposes of the swap contracts, crack spread is defined as the difference between the sum of the selling prices of one barrel of gasoline and one barrel of diesel fuel less the price of two barrels of crude oil,

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

with all component pricing based on standard market indices as defined in the contracts. The Company enters into various combinations of these swap contracts to achieve this defined 2/1/1 crack spread ratio. These contracts require the counterparty to pay the Company if the market crack spread is less than the stated crack spread in the contract or the Company to pay the counterparty if the market crack spread is greater than the stated crack spread in the contract. The payments are calculated based on the difference between the market crack spread and the stated crack spread per barrel multiplied by the number of barrels stated in each contract.

Fuel product margin swap contracts consisted of the following at December 31, 2005:


2/1/1 Crack Spread Swap Contracts Expiration Dates	Barrels		($/Bbl)

First Quarter 2006		1,035,000	$	9.00
Second Quarter 2006		1,039,000		8.98
Third Quarter 2006		1,043,000		8.65
Fourth Quarter 2006		1,043,000		8.28
First Quarter 2007		1,260,000		11.59
Second Quarter 2007		1,273,000		11.56
Third Quarter 2007		1,282,000		11.60
Fourth Quarter 2007		1,282,000		11.60

Totals		9,257,000
Average price			$	10.30

Fuel product margin swap contracts consisted of the following at December 31, 2004:


2/1/1 Crack Spread Swap Contracts Expiration Dates	Barrels		($/Bbl)

January 1, 2005 to December 31, 2005		2,482,000	$	6.91
January 1, 2006 to December 31, 2006		912,500		6.91

Totals		3,394,500
Average price			$	6.91

Fuels Product Margin (Crack Spread) Collar Contracts

In 2004, the Company began entering into fuels product margin (crack spread) collar contracts with counterparties whereby the Company purchased a crack spread put option while simultaneously selling a crack spread call option. For purposes of the collar contracts, crack spread is defined as the same as for the swap contracts above. These crack spread collar contracts require no net premium to be paid by the Company to the counterparties as the premium for the purchased crack spread put option is offset by the premium for the sold crack spread call option. These contracts require the counterparty to pay the Company if the market crack spread is less than the put option strike price and the Company to pay the counterparty to if the market crack spread is greater than the call option strike price. No payments are made between the Company and the counterparty if the market crack spread is greater than or equal to the put option strike price but less than or equal to the call option strike price. The payments are based on the difference between the market crack spread and the put option or call option strike price per barrel, whichever is applicable, multiplied by the number of barrels stated in each contract.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fuel product margin collar contracts consisted of the following at December 31, 2005:


			Put Option		Call Option
			Strike Price		Strike Price
2/1/1 Crack Spread Collar Contracts Expiration Dates	Barrels		($/Bbl)		($/Bbl)

First Quarter 2006		675,000	$	7.29	$	9.62
Second Quarter 2006		680,000		7.82		10.15
Third Quarter 2006		685,000		7.59		9.59
Fourth Quarter 2006		685,000		6.30		8.30

Totals		2,725,000
Average price			$	7.25	$	9.41

Fuel product margin collar contracts consisted of the following at December 31, 2004:

Put Option

Call Option

Strike Price

2/1/1 Crack Spread Collar Contracts Expiration Dates

Barrels

($/Bbl)

January 1, 2005 to December 31, 2005

2,372,500

5.36

8.00

Natural Gas Swap Contracts

The Company entered into natural gas price swap contracts with a counterparty which fix the price of a specified portion of the Company’s natural gas purchases. These contracts require the counterparty to pay the Company if the market price for natural gas is greater than the stated fixed price in the contract or the Company to pay the counterparty if the market price for natural gas is less than the stated fixed price in the contract. The payments are calculated based on the difference between the market price and the stated contract price per MMBtu multiplied by the number of MMBtus stated in each contract.

Natural gas swap contracts consisted of the following at December 31, 2005:


Natural Gas Swap Contracts Expiration Dates	MMbtu		$/MMbtu

First Quarter 2006		600,000	$	9.84
Second Quarter 2006		—		—
Third Quarter 2006		—		—
Fourth Quarter 2006		—		—

Totals		600,000
Average price			$	9.84


8.	Fair Value of Financial Instruments

Based upon borrowing rates available to the Company for debt with similar terms and the same remaining maturities, the fair value of long-term debt approximates carrying value at December 31, 2005 and 2004. In addition, based upon fees charged for similar agreements, the face values of outstanding standby letters of credit approximate their fair value at December 31, 2005 and 2004.


9.	Partnership Distributions

The Company’s policy is that distributions will be limited to the amount necessary to pay each partner’s federal income tax and any state income tax on the amount of partnership income. However, additional distributions to the partners may be made at the sole discretion of the general partner. During the year ended December 31, 2005, distributions of $7.3 million were made to the partners. During 2004 and 2003, there were no distributions to the partners. In January 2006, the Company made a distribution of $6.9 million to the partners.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


10.	Employee Benefit Plan

The Company participates in a defined contribution plan sponsored by one of the limited partners. All full-time employees who have completed at least one hour of service are eligible to participate in the plan. Participants are allowed to contribute 0% to 100% of their pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% contribution by the participant up to 3% and 50% of each additional 1% contribution up to 5% for a maximum contribution by the Company of 4% per participant. The Company’s matching contribution was $839, $791, and $742 for the years ended December 31, 2005, 2004 and 2003, respectively. The plan also includes a profit-sharing component. Contributions under the profit-sharing component are determined by the Board of Directors of the Company’s general partner and are discretionary. The Company’s profit sharing contribution was $452, $426, and $0 for the years ended December 31, 2005, 2004 and 2003, respectively.


11.	Transactions with Related Parties

During the years ended December 31, 2005, 2004 and 2003, the Company had sales to related parties of $209, $9 and $29,037, respectively. Trade accounts and other receivables from related parties at December 31, 2005 and 2004 were $110 and $90, respectively. The Company also had purchases from related parties during the years ended December 31, 2005, 2004 and 2003 of $1,114, $864 and $687, respectively. Accounts payable to related parties at December 31, 2005 and 2004 were $1,704 and $1,517, respectively.

Certain of the Company’s partners had loaned the Company funds under long-term notes, which have been repaid as discussed in Note 6. The interest expense associated with the affiliated borrowings was approximately $9,659, $8,940 and $9,493 for the years ended December 31, 2005, 2004 and 2003, respectively.

A limited partner provides management, administrative, and accounting services to the Company for an annual fee. Such services include, but are not necessarily limited to, advice and assistance concerning any and all aspects of the operation, planning, and financing of the Company. Payments for the years ended December 31, 2005, 2004 and 2003 were $633, $623 and $604, respectively.

The Company participates in a self-insurance program for medical benefits with a limited partner and several other related companies. In connection with this program, contributions are made to a voluntary employees’ benefit association (VEBA) trust. Contributions made by the Company to the VEBA for the years ended December 31, 2005, 2004 and 2003 totaled $3,167, $2,784 and $3,239, respectively.

The Company participates in a self-insurance program for workers’ compensation with a limited partner and several related companies. In connection with this program, contributions are made to the limited partner. Contributions made by the Company to the limited partner for the years ended December 31, 2005, 2004 and 2003 totaled $294, $327 and $230, respectively.

The Company participates in a self-insurance program for general liability with a limited partner and several related companies. In connection with this program, contributions are made to the limited partner. Contributions made by the Company to the limited partner for the years ended December 31, 2005, 2004 and 2003 totaled $590, $337 and $415, respectively.


12.	Segments and Related Information

a. Segment Reporting

Under the provisions of SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information, the Company has two reportable segments: Specialty Products and Fuel Products. The Specialty Products segment produces a variety of lubricating oils, solvents and waxes. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The Fuel Products segment produces a variety of fuel and fuel-related products including gasoline, diesel and jet fuel.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The accounting policies of the segments are the same as those described in the summary of significant accounting policies except that the Company evaluates segment performance based on income from operations. The Company accounts for intersegment sales and transfers at cost plus a specified mark-up. Reportable segment information is as follows (in thousands):


	Specialty		Fuel		Combined					Consolidated
Year Ended December 31, 2005	Products		Products		Segments		Eliminations			Total

Sales:
External customers	$	703,214	$	585,858	$	1,289,072	$	—		$	1,289,072
Intersegment sales		552,563		15,020		567,583		(567,583	)		—

Total sales	$	1,255,777	$	600,878	$	1,856,655	$	(567,583	)	$	1,289,072

Depreciation and amortization		10,386		—		10,386		—			10,386
Income (loss) from operations		4,430		61,255		65,685		—			65,685
Reconciling items to net income:
Equity in (loss) income of unconsolidated affiliates											—
Interest expense											(22,961	)
Debt extinguishment costs											(6,882	)
Gain (loss) on derivative instruments											(24,756	)
Other											242

Net income											11,328

Capital expenditures	$	12,963	$	—	$	12,963	$	—		$	12,963
Assets	$	606,023	$	375,153	$	981,176	$	(581,459	)	$	399,717


	Specialty			Fuel			Combined						Consolidated
Year Ended December 31, 2004	Products			Products			Segments			Eliminations			Total

Sales:
External customers	$	530,009		$	9,607		$	539,616		$	—		$	539,616
Intersegment sales		15,651			—			15,651			(15,651	)		—

Total sales	$	545,660		$	9,607		$	555,267		$	(15,651	)	$	539,616

Depreciation and amortization		6,927			—			6,927			—			6,927
Income (loss) from operations		(9,406	)		(2,783	)		(12,189	)		—			(12,189	)
Reconciling items to net income:
Equity in (loss) income of unconsolidated affiliates														(427	)
Interest expense														(9,869	)
Gain (loss) on derivative instruments														31,372
Other														83

Net income														8,970

Capital expenditures	$	43,033		$	—		$	43,033		$	—		$	43,033
Assets	$	315,336		$	69,400		$	384,736		$	(66,530	)	$	318,206

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Specialty			Fuel		Combined					Consolidated
Year Ended December 31, 2003	Products			Products		Segments			Eliminations		Total

Sales:
External customers	$	430,381		$	—	$	430,381		$	—	$	430,381
Intersegment sales		—			—		—			—		—

Total sales	$	430,381		$	—	$	430,381		$	—	$	430,381

Depreciation and amortization		6,769			—		6,769			—		6,769
Income (loss) from operations		(3,098	)		—		(3,098	)		—		(3,098	)
Reconciling items to net income:
Equity in (loss) income of unconsolidated affiliates												867
Interest expense												(9,493	)
Gain (loss) on derivative instruments												6,267
Other												32

Net loss												(5,425	)

Capital expenditures	$	12,163		$	—	$	12,163		$	—	$	12,163
Assets	$	216,941		$	—	$	216,941		$	—	$	216,941

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2005, 2004 and 2003.

c. Product Information

The Company offers products primarily in four general categories consisting of fuels, lubricants, waxes and solvents. Other includes asphalt and other by-products. The following table sets forth the major product category sales (dollars in thousands):


	December 31,
	2005		2004		2003

Fuels	$	619,842	$	82,288	$	83,564
Lubricants		394,363		251,880		205,871
Waxes		43,638		39,526		32,276
Solvents		144,967		114,694		87,599
Other		86,262		51,228		21,071

Total sales	$	1,289,072	$	539,616	$	430,381

d. Major Customers

No customer represented 10% or greater of consolidated sales in each of the three years ended December 31, 2005, 2004 and 2003.

CALUMET LUBRICANTS CO., LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


13.	Quarterly Financial Data (Unaudited)


	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter			Total(1)
	(In thousands)

2005
Sales	$	229,549		$	301,562		$	363,870		$	394,091		$	1,289,072
Gross profit		26,117			30,536			38,754			44,950			140,357
Operating income		10,745			13,539			20,767			20,634			65,685
Net income (loss)		(128	)		18,717			(39,406	)		32,145			11,328
2004
Sales	$	115,235		$	137,337		$	140,464		$	146,580		$	539,616
Gross profit		11,196			9,731			10,289			7,116			38,332
Operating loss		(192	)		(3,281	)		(3,224	)		(5,492	)		(12,189	)
Net income (loss)		12,926			(2,651	)		8,491			(9,796	)		8,970


(1)		The sum of the four quarters may not equal the total year due to rounding.


14.	Subsequent Events

On January 31, 2006, Calumet Specialty Products Partners, L.P. (“the Partnership”) completed the initial public offering of its common units and sold 5,699,900 of those units to the underwriters in the initial public offering at a price to the public of $21.50 per common unit. The managing underwriter for the offering was Goldman, Sachs & Co. The Partnership also sold a total of 750,100 common units to the Fehsenfeld Investors at a price of $19.995 per common unit. In addition, on February 8, 2006, the Partnership 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. Each of these issuances was made pursuant to the Partnership’s Registration Statement onForm S-1 (FileNo. 333-128880) declared effective by the Securities and Exchange Commission on January 29, 2006. The proceeds received by the Partnership (net of underwriting discounts and structuring fees and before expenses) from the sale of an aggregate of 7,304,985 units were 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 $13.7 million and (iii) pay transaction fees and expenses in the amount of approximately $5.0 million. Underwriting discounts totaled approximately $11.6 million (including certain structuring fees paid to certain of the underwriters of approximately $2.4 million).

In January 2006, the predecessor paid discretionary cash bonuses totaling $5.0 million, which were accrued at December 31, 2005, to certain of its executive officers and key members of its management based on the predecessor’s 2005 financial performance.

Calumet GP, LLC (the GP), the Partnership’s general partner, has adopted a Long-Term Incentive Plan (the “Plan”) for its employees, consultants and directors and its affiliates who perform services for the Partnership. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy our general partner’s tax withholding obligations are available for delivery pursuant to other awards. If the Plan is implemented, the Plan will be administered by the compensation committee of the GP’s board of directors.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Calumet Specialty Products Partners, L.P.

We have audited the accompanying balance sheet of Calumet Specialty Products Partners, L.P. as of December 31, 2005. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Calumet Specialty Products Partners, L.P. at December 31, 2005, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Indianapolis, Indiana

March 9, 2006.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

BALANCE SHEET

December 31, 2005


Assets
Cash	$	965

Total assets	$	965

Partners’ capital
Limited partners’ capital	$	946
General partner’s capital		19

Total partners’ capital	$	965

See accompanying note to the balance sheet.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTE TO BALANCE SHEET


1.	Nature of Operations

Calumet Specialty Products Partners, L.P. (“Partnership”) is a Delaware limited partnership formed on September 27, 2005, to acquire a 100% undivided ownership interest in Calumet Lubricants Co., Limited Partnership. In order to simplify Partnership’s obligations under the laws of selected jurisdictions in which Partnership will conduct business, Partnership’s activities will be conducted through wholly owned operating subsidiaries.

On January 31, 2006, the Partnership offered 6,450,000 common units representing limited partner interests to the public, pursuant to an initial public offering. The Partnership concurrently issued to Fred Fehsenfeld, Jr., F. William Grube, Calumet, Incorporated, The Heritage Group and certain affiliated trusts 5,761,015 common units and 13,066,000 subordinated units, representing additional limited partner interests, and to Calumet GP, LLC (the “General Partner”) a 2% general partner interest and incentive distribution rights in exchange for the contribution of 100% of the ownership interests in Calumet Lubricants Co., Limited Partnership. In addition, on February 8, 2006, the Partnership sold an additional 854,985 common units to the public at $21.50 per common unit pursuant to the underwriters’ over-allotment option.

The General Partner initially contributed $20 and The Heritage Group, Calumet Incorporated, F. William Grube, Fred Fehsenfeld, Jr. and trusts for the benefit of the Fehsenfeld family, as the organizational limited partners, initially contributed an aggregate of $980 to Partnership on September 29, 2005. There have been no other significant transactions involving Partnership as of December 31, 2005.

On February 8, 2006, Calumet GP, LLC contributed an additional $375,147 to the Partnership to maintain its 2% general partner interest in the Partnership as a result of the exercise of the over-allotment option by the underwriters of the initial public offering of the Partnership.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of

Calumet GP, LLC

We have audited the accompanying balance sheet of Calumet GP, LLC as of December 31, 2005. This financial statement is the responsibility of Calumet GP, LLC’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of Calumet GP, LLC’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Calumet GP, LLC’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Calumet GP, LLC at December 31, 2005, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Indianapolis, Indiana

March 9, 2006.

CALUMET GP, LLC

BALANCE SHEET

December 31, 2005


Assets
Cash	$	945
Investment in Calumet Specialty Products Partners, L.P.		19

Total assets	$	964

Members’ capital
Members’ capital	$	964

Total members’ capital	$	964

See accompanying note to the balance sheet.

CALUMET GP, LLC

NOTE TO BALANCE SHEET


1.	Nature of Operations

Calumet GP, LLC (“General Partner”) is a Delaware limited liability company formed on September 27, 2005 to become the general partner of Calumet Specialty Products Partners, L.P. (“Partnership”). General Partner is owned by The Heritage Group, Fred Fehsenfeld, Jr. and F. William Grube. General Partner owns a 2% general partner interest in Partnership.

On September 29, 2005, the members contributed $1,000 to Calumet GP, LLC in exchange for a 100% ownership interest.

General Partner has invested $20 in Partnership as of December 31, 2005. There have been no other significant transactions involving General Partner as of December 31, 2005.

On February 8, 2006, the General Partner contributed an additional $375,147 to the Partnership to maintain its 2% general partner interest in the Partnership as a result of the exercise of the over-allotment option by the underwriters of the initial public offering of the Partnership.


Item 9.	*Changes In and Disagreements With Accountants on Accounting and Financial Disclosure*

None.


Item 9A.	*Controls and Procedures*

(a) Evaluation of disclosure controls and procedures.

Our principal executive officer and principal financial officer have evaluated, as required byRule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange ActRule 13a-15(e)) as of the end of the period covered by the Annual Report onForm 10-K. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(b) Changes in internal control over financial reporting.

There have been no changes in our internal control over financial reporting (as defined inRule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.


Item 9B.	*Other Information*

None.

PART III


Item 10.	*Directors and Executive Officers of Our General Partner*

Management of Calumet Specialty Products Partners, L.P.

Our general partner, Calumet GP, LLC, manages our operations and activities. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to our unitholders. However, our partnership agreement also contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are nonrecourse to it.

The directors of our general partner oversee our operations. The owners of our general partner have appointed seven members to our general partner’s board of directors. The directors of our general partner are generally elected by a majority vote of the owners of our general partner. However, as long as our chief executive officer and president, F. William Grube, or trusts established for the benefit of his family members, continue to own at least 30% of the membership interests in our general partner, Mr. Grube (or in certain specified instances, his designee or transferee) will have the right to serve as a director of our general partner. The NASDAQ National Market does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee.

The board of directors of our general partner is required to have and has an audit committee comprised of three directors who meet the independence and experience standards established by the NASDAQ National Market and the Exchange Act. The board of directors of our general partner has previously determined that Messrs. James Carter, Robert Funk and Michael Smith meet such independence standards and such directors constitute the membership of the audit committee. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof and pre-approves any

non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee.

In addition at least two members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NASDAQ National Market and the Securities Exchange Act of 1934 to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

The board of directors of our general partner will also have a compensation committee, which will, among other things, oversee the compensation plans described below. As of March 13, 2006, neither the members of the compensation committee nor the members of the conflicts committee have been selected by the board of directors.

Since we did not complete our intial public offering until January 31, 2006, the board of directors of our general partner did not hold any meetings in 2005.

The officers of our general partner manage theday-to-day affairs of our business.

Directors and Executive Officers

The following table shows information regarding the directors and executive officers of Calumet GP, LLC as of March 13, 2006. Directors are elected for one-year terms.


Name	Age		Position with Calumet GP, LLC

Fred M. Fehsenfeld, Jr.		55	Chairman of the Board
F. William Grube		58	Chief Executive Officer, President and Director
Allan A. Moyes, III		59	Executive Vice President
R. Patrick Murray, II		34	Vice President, Chief Financial Officer and Secretary
Robert M. Mills		52	Vice President — Crude Oil Supply
Jeffrey D. Smith		43	Vice President — Planning and Economics
William A. Anderson		37	Vice President — Sales and Marketing
James S. Carter		57	Director
William S. Fehsenfeld		55	Director
Robert E. Funk		60	Director
Nicholas J. Rutigliano		58	Director
Michael L. Smith		57	Director

The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors.

Fred M. Fehsenfeld, Jr. has served as the chairman of the board of directors of our general partner since September 2005. Mr. Fehsenfeld has also served as the vice chairman of the board of our predecessor since 1990. Mr. Fehsenfeld has worked for The Heritage Group in various capacities since 1977 and has served as its managing trustee since 1980. Mr. Fehsenfeld received his B.S. in Mechanical Engineering from Duke University and his M.S. in Management from the Massachusetts Institute of Technology Sloan School.

F. William Grubehas served as the chief executive officer, president and director of our general partner since September 2005. Mr. Grube has also served as president and chief executive officer of our predecessor since 1990. From 1974 to 1990, Mr. Grube served as executive vice president of the Rock Island Refinery. Mr. Grube received

his B.S. in Chemical Engineering from Rose-Hulman Institute of Technology and his M.B.A. from Harvard University.

Allan A. Moyes, IIIhas served as executive vice president of our general partner since September 2005. Mr. Moyes has also served as executive vice president of our predecessor since 1997. From 1994 to 1997, Mr. Moyes served as manager of planning and economics for our predecessor. From 1989 to 1994, Mr. Moyes worked for Marathon Oil Company as the technical service manager in its Indianapolis refinery. From 1978 to 1989, Mr. Moyes worked in various capacities at the Rock Island Refinery. Mr. Moyes received his Computer Science degree at Memphis State Technical University.

R. Patrick Murray, IIhas served as vice president, chief financial officer and secretary of our general partner since September 2005. Mr. Murray has also served as the vice president and chief financial officer of our predecessor since 1999 and from 1998 to 1999 served as its controller. From 1993 to 1998, Mr. Murray was a senior auditor with Arthur Andersen. Mr. Murray is a certified public accountant and received his B.B.A. in Accountancy from the University of Notre Dame.

Robert M. Millshas served as vice president — crude oil supply of our general partner since September 2005. Mr. Mills has also served as the vice president — crude oil supply of our predecessor since 1995 and from 1993 to 1995 served as manager of supply and distribution. Mr. Mills received his B.S. in Business Administration from Louisiana State University.

Jeffrey D. Smithhas served as vice president — planning and economics of our general partner since September 2005. He has also served as the vice president — planning and economics of our predecessor since 2002. Mr. Smith joined our predecessor in 1994 and served in various capacities prior to becoming vice president. Mr. Smith received his B.S. in Geology from Louisiana Tech University.

William A. Andersonhas served as vice president — sales and marketing of our general partner since September 2005. Mr. Anderson has also served as the vice president — sales and marketing of our predecessor since 2000 and served in various other capacities for our predecessor from 1993 to 2000. Mr. Anderson received his B.A. in Communications from DePauw University.

James S. Carterhas served as a member of the board of directors of our general partner since January 2006. Mr. Carter served as U.S. regional director of ExxonMobil Fuels Company, the fuels subsidiary of ExxonMobil Corporation, from 1999 until his retirement in 2003. Mr. Carter received his M.B.A. in Finance and Accounting from Tulane University.

William S. Fehsenfeldhas served as a member of the board of directors of our general partner since January 2006. Mr. Fehsenfeld has served as vice president and secretary of Schuler Books, Inc., the independent bookstore company he founded with his wife, since 1982. He has also served as a trustee of The Heritage Group from 2003 to the present. Mr. Fehsenfeld received his B.G.S. from the University of Michigan and his M.B.A. from Grand Valley State University. He is also a first cousin of the chairman of the board of directors of our general partner, Mr. Fred M. Fehsenfeld, Jr.

Robert E. Funkhas served as a member of the board of directors of our general partner since January 2006. Mr. Funk previously served as vice president-corporate planning and economics of Citgo Petroleum Corporation, a refiner and marketer of transportation fuels, lubricants, petrochemicals, refined waxes, asphalt and other industrial products, from 1997 until his retirement in December 2004. Mr. Funk previously served Citgo or its predecessor, Cities Services Company, as general manager-facilities planning from 1988 to 1997, general manager-lubricants operations from 1983 to 1988 and manager-refinery east, Lake Charles refinery from 1982 to 1983. Mr. Funk received his B.S. in Chemical Engineering from the University of Kansas.

Nicholas J. Rutiglianohas served as a member of the board of directors of our general partner since January 2006. Mr. Rutigliano has served as president of Tobias Insurance Group, Inc., a commercial insurance brokerage business he founded, since 1973. He has also served as a trustee of The Heritage Group from 1980 to the present. Mr. Rutigiliano received his B.S. in Business from the University of Evansville. He is also thebrother-in-law of the chairman of the board of directors of our general partner, Mr. Fred M. Fehsenfeld, Jr.

Michael L. Smithhas served as a member of the board of directors of our general partner since January 2006. Mr. Smith is the chairman of the audit committee of our board of directors and previously served as executive vice president and chief financial officer of Wellpoint Inc. (f/k/a Anthem Inc.), a publicly traded health benefits company, from 1999 until his retirement in January 2005. Mr. Smith previously served as senior vice president of Anthem and chief financial officer of Anthem Blue Cross and Blue Shield’s Midwest and Connecticut operations from 1998 to 1999. From 1996 to 1998, he was chief operating officer and chief financial officer of American Health Network, a former Anthem subsidiary. Mr. Smith is a member of the board of directors of First Indiana Corporation and its principal subsidiary, First Indiana Bank, Kite Realty Group Trust, Vectren Corporation, InterMune Inc. and Emergency Medical Services Corporation. He also serves on the Board of Trustees of DePauw University. Mr. Smith received his B.A. in Economics from DePauw University.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics that applies to all officers, directors and employees.

Available on our website atwww.calumetspecialty.com are copies of our Audit Committee Charter, and Code of Business Conduct and Ethics, all of which also will be provided to unitholders without charge upon their written request to Jennifer Straumins, Vice President — Investor Relations, at Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, IN 46214.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities and Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and NASDAQ National Market initial reports of ownership and reports of changes in ownership of such equity securities. However, since we did not complete our initial public offering until January 31, 2006, Section 16(a) of the Securities Exchange Act of 1934 did not apply during the year ended December 31, 2005 to our directors, executive officers and 10% unitholders.


Item 11.	*Executive Compensation*

Both we and our general partner were formed in September 2005 and began reporting separately from Calumet Predecessor with the conclusion of our initial public offering on January 31, 2006. Accordingly, our general partner did not accrue any obligations with respect to management compensation, incentives or retirement benefits for its directors and officers for the 2005 fiscal year. The compensation of the executive officers of our general partner will be set by the compensation committee of our general partner’s board of directors. The officers and employees of our general partner may participate in employee benefit plans and arrangements sponsored by us, our general partner or its affiliates, including plans that may be established in the future.

On December 30, 2005, our predecessor approved discretionary cash bonuses totaling $5.0 million to be paid to certain of its executive officers and key members of its management based on our predecessor’s financial performance. These cash bonuses were paid by our predecessor prior to the completion of our initial public offering.

Employment Agreement

Upon consummation of the initial public offering, F. William Grube entered into an employment agreement with our general partner. Pursuant to the employment agreement, Mr. Grube serves as president and chief executive officer of our general partner as well as a member of the board of directors of our general partner. The employment agreement provides that Mr. Grube will have powers and duties and responsibilities that are customary to this position and that are assigned to him by the board of directors of our general partner in connection with his general management and supervision of the operations of our general partner.

The employment agreement has an initial term of five years, with automatic annual extensions beginning on the third anniversary of its effective date. The agreement provides for an annual base salary of approximately $333,000, subject to annual adjustment by the compensation committee of the board of directors of our general partner, as well as the right to participate in our Long Term Incentive Plan and other bonus plans. Mr. Grube will generally be entitled to receive a payout or distribution of at least 150% of the amount of any cash, equity or other

payout or distribution that may be made to any other executive officer under the terms of these plans. The employment agreement also contains non-competition provisions.

Mr. Grube’s employment agreement may be terminated at any time by either party with proper notice. If Mr. Grube’s employment is terminated without cause, as defined in the agreement, or by Mr. Grube for good reason, as defined in the agreement, then our general partner will be required to pay Mr. Grube a lump sum equal to three times his then current base salary as well as a lump sum cash payment for amounts accrued under our various incentive and benefit plans. In addition, all equity based awards will vest in full in the event of such a termination.

Long-Term Incentive Plan

General. Our general partner adopted a Long-Term Incentive Plan (the “Plan”) on January 24, 2006 for its employees, consultants and directors and its affiliates who perform services for us. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy our general partner’s tax withholding obligations are available for delivery pursuant to other awards. If the Plan is utilized, the Plan will be administered by the compensation committee of our general partner’s board of directors.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or our general partner, subject to any contrary provisions in the award agreement.

If a grantee’s employment, consulting or membership on the board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the grant agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.

Distributions made by us on restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit.

We intend for the restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Unit Options. The Plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant.

Upon exercise of a unit option, our general partner will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then

traded, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring the common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

On October 22, 2004, the American Jobs Creation Act of 2004 (H.R. 4520) (the “AJCA”) was signed into law by the President. The AJCA added new Section 409A to the Internal Revenue Code (“Section 409A”) which significantly alters the rules relating to the taxation of deferred compensation. Section 409A broadly applies to deferred compensation and potentially results in additional tax to participants. The Department of Treasury and IRS have issued guidance and proposed regulations under Section 409A, however further guidance is anticipated. Based on current guidance, the award of options to employees, consultants and directors of certain of our affiliates may be very limited in order to meet the requirements of Section 409A. However, we expect that we will be able to structure awards under the plan in a manner that complies with Section 409A. Because we expect additional guidance to be issued under Section 409A, we may be required to alter certain provisions of the plan and future awards.

Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, our general partner or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

Termination of Long-Term Incentive Plan. Our general partner’s board of directors, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by the board of directors of our general partner or when common units are no longer available for delivery pursuant to awards under the Plan. Our general partner’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the board of directors of our general partner may increase the number of common units that may be delivered with respect to awards under the Plan.

Compensation of Directors

Officers or employees of our general partner who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner receives compensation for attending meetings of the board of directors, as well as committee meetings. The primary fees paid to non-employee directors are as follows:


	•	Annual fee of $30,000;

	•	The annual award of restricted units in the amount of $40,000 with a four-year vesting period;

	•	Annual fee of $8,000 to the audit committee chairperson;

	•	Annual fee of $4,000 to each audit committee member; and

	•	Annual fee of $5,000 to all other committee chairpersons.

In addition, each non-employee director will be reimbursed for hisout-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

Reimbursement of Expenses of Our General Partner

Our general partner does not receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates are, however, reimbursed for all expenses incurred on our behalf.

These expenses include the cost of employee, officer and director compensation benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner determine the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters*

The following table sets forth the beneficial ownership of our units as of March 13, 2006 held by:


	•	each person who beneficially owns 5% or more of our outstanding units;

	•	each director of our general partner;

	•	each named executive officer of our general partner; and

	•	all directors, and executive officers of our general partner as a group.

The amounts and percentages of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The address for the beneficial owners listed below, other than The Heritage Group, is 2780 Waterfront Pkwy E. Drive, Suite 200, Indianapolis, Indiana 46214. The address for The Heritage Group is 5400 W. 86th St., Indianapolis, Indiana46268-0123.


								Percentage of
	Common		Percentage of			Subordinated		Subordinated			Percentage of
	Units		Common Units			Units		Units			Total Units
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner	Owned		Owned			Owned		Owned			Owned

The Heritage Group(1)		3,499,277		26.78	%		7,936,370		60.74	%		43.76	%
Calumet, Incorporated(2)		591,886		4.53	%		1,342,401		10.27	%		7.40	%
Janet K. Grube(2)(3)		1,180,089		9.03	%		2,676,183		20.48	%		14.76	%
F. William Grube(2)(3)		88,783		0.68	%		201,360		1.54	%		1.11	%
Fred M. Fehsenfeld, Jr.(1)(2)		173,424		1.33	%		393,323		3.01	%		2.17	%
Allan A. Moyes, III		14,000		*			—		—	%		*
R. Patrick Murray, II		6,000		*			—		—	%		*
Robert M. Mills		11,400		*			—		—	%		*
William A. Anderson		6,000		*			—		—	%		*
Jeffrey D. Smith		5,000		*			—		—	%		*
James S. Carter		4,000		*			—		—	%		*
William S. Fehsenfeld(1)(5)		12,000		*			—		—	%		*
Robert E. Funk		5,000		*			—		—	%		*
Nicholas J. Rutigliano(1)(4)		25,000		*			—		—	%		*
Michael L. Smith		—		—	%		—		—	%		—	%
All directors and executive officers as a group (12 persons)		350,607		2.68	%		594,683		4.55	%		3.62	%


*		= less than 1 percent.

(1)		Thirty grantor trusts indirectly own all of the outstanding general partner interests in The Heritage Group, an Indiana general partnership. The direct or indirect beneficiaries of the grantor trusts are members of the Fehsenfeld family. Each of the grantor trusts has five trustees, Fred M. Fehsenfeld, Jr., James C. Fehsenfeld, Nicholas J. Rutigliano, William S. Fehsenfeld and Nancy A. Smith, each of whom exercises equivalent voting rights with respect to each such trust. Each of Fred M. Fehsenfeld, Jr., Nicholas J. Rutigliano and William S. Fehsenfeld, who are directors of our general partner, disclaims beneficial ownership of all of the common and subordinated units owned by The Heritage Group, and none of these units are shown as being beneficially owned by such directors in the table above.

(2)		F. William Grube is a director of and owns 15% of the common shares of Calumet, Incorporated, an Indiana corporation. Accordingly, 88,783 of the common units and 201,360 of the subordinated units owned by Calumet, Incorporated are also shown as being beneficially owned by F. William Grube in the table above. Janet K. Grube, the spouse of F. William Grube, has no voting or investment power over these units, and none of these units are shown as being beneficially owned by Janet K. Grube in the table above. The remaining 85% of the common shares of Calumet, Incorporated are indirectly owned 45.8% by The Heritage Group and 5.1% by Fred M. Fehsenfeld, Jr. personally. Fred M. Fehsenfeld, Jr. is also a director of Calumet, Incorporated. Accordingly, 230,244 of the common units and 522,194 of the subordinated units owned by Calumet, Incorporated are also shown as being beneficially owned by The Heritage Group in the table above, and 25,451 of the common units and 57,723 of the subordinated units owned by Calumet, Incorporated are also shown as being beneficially owned by Fred M. Fehsenfeld, Jr. in the table above. Each of F. William Grube, The Heritage Group and Fred M. Fehsenfeld, Jr. disclaims beneficial ownership of all of the common and subordinated units owned by Calumet, Incorporated in excess of their respective pecuniary interests in such units.

(3)		Includes common and subordinated units that are owned by two grantor retained annuity trusts for which Janet K. Grube, the spouse of F. William Grube, serves as sole trustee. Janet K. Grube and her two children are the beneficiaries of such trusts. Also includes common and subordinated units owned by Janet K. Grube personally. F. William Grube has no voting or investment power over these units and disclaims beneficial ownership of all such units, and none of these units are shown as being beneficially owned by F. William Grube in the table above.

(4)		Includes common units that are owned by the spouse of Nicholas J. Rutigliano for which he disclaims beneficial ownership.

(5)		Includes common units that are owned by the spouse of William S. Fehsenfeld for which he disclaims beneficial ownership.

Equity Compensation Plan Information

The following table summarizes information about our equity compensation plans as of December 31, 2005:

Number of Securities

Remaining Available for

Number of Securities

Weighted-Average

Future Issuance Under

to be Issued Upon

Exercise Price

Equity Compensation

Exercise of Outstanding

of Outstanding

Plans (Excluding

Options, Warrants

Securities Reflected in

and Rights(1)

and Rights

Column(a))

(a)

(b)

(c)

Equity compensation plans approved by unitholders

—

Equity compensation plans not approved by unitholders

—

Total

—


(1)		The Long-Term Incentive Plan currently permits the grant of awards covering an aggregate of 783,960 common units. For more information on our Long-Term Incentive Plan, which did not require approval by our limited partners, refer to Item 11. “Executive Compensation — Long-Term Incentive Plan.”

For more information about our Long-Term Incentive Plan, which was adopted January 24, 2006 and became effective on January 31, 2006, refer to “Item 11. Executive and Director Compensation — Long-Term Incentive Plan.”


Item 13.	*Certain Relationships and Related Party Transactions*

Owners of our general partner and their affiliates, including the Fehsenfeld Investors, own 6,511,115 common units and 13,066,000 subordinated units representing an aggregate 74.9% limited partner interest in us. In addition, our general partner own a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments that have been and will be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Calumet Specialty Products Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage


The consideration received by our general partner and its affiliates for the contribution of the assets and liabilities to us		• 5,761,015 common units;

		• 13,066,000 subordinated units;

		• 2% general partner interest; and

		• the incentive distribution rights.

Operational Stage


Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions of 98% to the unitholders pro rata, including the affiliates of our general partner, as the holders of an aggregate 6,511,115 common units and 13,066,000 subordinated units, and 2% to our general partner.

		In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.

		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $1.0 million on its 2% general partner interest and the affiliates of our general partner would receive $33.9 million on their common and subordinated units.

Payments to our general partner and its affiliates		We will reimburse our general partner and its affiliates for all expenses incurred on our behalf.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the


		new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage


Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Omnibus Agreement

We entered into an omnibus agreement, dated January 31, 2006, with The Heritage Group and certain of its affiliates pursuant to which The Heritage Group and its controlled affiliates agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental United States (“restricted business”) for so long as The Heritage Group controls us. This restriction does not apply to:


	•	any business owned or operated by The Heritage Group or any of its affiliates as of January 31, 2006;

	•	the refining and marketing of asphalt and asphalt-related products and related product development activities;

	•	the refining and marketing of other products that do not produce “qualifying income” as defined in the Internal Revenue Code;

	•	the purchase and ownership of up to 9.9% of any class of securities of any entity engaged in any restricted business;

	•	any restricted business acquired or constructed that The Heritage Group or any of its affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of less than $5.0 million;

	•	any restricted business acquired or constructed that has a fair market value or construction cost, as applicable, of $5.0 million or more if we have been offered the opportunity to purchase it for fair market value or construction cost and we decline to do so with the concurrence of the conflicts committee of the board of directors of our general partner; and

	•	any business conducted by The Heritage Group with the approval of the conflicts committee of the board of directors of our general partner.

Administrative and Other Services

The Heritage Group has historically provided us with management, administrative and accounting services for which it receives an annual fee. The Heritage Group also provides us with strategic and financial advisory services from time to time. Payments for these services for 2005 were approximately $633,000. The Heritage Group will continue to provide certain of these services to us on substantially similar terms.

We participate in a self-insurance program for medical benefits with The Heritage Group and certain of its affiliates. In connection with this program, contributions are made to a voluntary employees’ benefit association (VEBA) trust. Contributions made by us to the VEBA in 2005 totaled approximately $3.2 million.

We participate in a self-insurance program for workers’ compensation with The Heritage Group and certain of its affiliates. In connection with this program, contributions are made to The Heritage Group. Contributions made by us to The Heritage Group in 2005 totaled approximately $294,000.

We participate in a self-insurance program for general liability with The Heritage Group and certain of its affiliates. In connection with this program, contributions are made to The Heritage Group. Contributions made by us to The Heritage Group in 2005 totaled approximately $590,000.

In the near term, we anticipate we will continue to participate in these plans.

Indemnification of Directors and Officers

Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.

Credit Facility with and Guarantees by The Heritage Group

The Heritage Group was previously a lender to us under a term loan. The credit agreement provided for up to $180 million in long-term borrowings which bore interest at various rates and was to have matured on June 30, 2007. The notes bore interest at the prime rate. In connection with our refinancing in December 2005, all outstanding borrowings under the existing credit agreement and the principal and interest on the notes were repaid, the credit agreement was terminated and the notes cancelled. In addition, we were a limited guarantor of a bank credit facility of The Heritage Group, one of its affiliates and an owner of our general partner. This guaranty was terminated in connection with our refinancing.

Concurrent Sale of Common Units

In connection with the completion of our initial public offering on January 31, 2006, we sold 750,100 common units to Fred M. Fehsenfeld Sr., the father of the chairman of our general partner, and Mac and Frank B. Fehsenfeld, the uncles of the chairman of our general partner at a per unit price of $19.995. On January 25, 2006, we entered into a common unit purchase agreement with those investors in connection with the sale of the 750,100 common units.

Directed Unit Program

In connection with our initial public offering, certain of our officers and directors, including Messrs. Moyes, Murray, Mills, Anderson, J. Smith, Carter, W. Fehsenfeld, Funk, Rutigliano and their affiliates each purchased common units with a combined value of approximately $1.8 million under our directed unit program. Please read the table listing all Beneficial Owners in Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

Transactions with Director

Nicholas J. Rutigliano, a member of the board of directors of our general partner, founded and is the president of Tobias Insurance Group, Inc., a commercial insurance brokerage business, that has historically placed a portion of our insurance underwriting requirements. The total premiums paid by us through Mr. Rutigliano’s firm for 2005 were approximately $784,000. It is anticipated that Mr. Rutigliano’s firm will continue to provide these services to us on substantially similar terms. We believe these premiums are comparable to the premiums we would pay for such insurance from a non-affiliated third party.

Crude Oil Purchases

We have historically purchased a small percentage of our crude oil supplies from Legacy Resources Co., L.P., an exploration and production company owned in part by The Heritage Group and our president and chief executive officer, F. William Grube. The total purchases made by us from Legacy Resources in 2005 were approximately $1.1 million. It is anticipated that we may continue to purchase crude oil from Legacy Resources at applicable market rates. We believe that the prices we pay Legacy Resources for crude oil are comparable to the prices we pay for crude oil from non-affiliated third parties.


Item 14.	*Principal Accountant Fees and Services*

The following table details the aggregate fees billed for professional services rendered by our independent auditor during 2005.


	Year Ended
	December 31,
	2005

Audit fees	$	3,550,000
Audit related fees		—
Tax fees		114,107
All other fees		—

Total	$	3,664,107

Expenditures classified as “Audit fees” above include those related to our annual audit, audits of our general partner and work performed in connection with our initial public offering. “Tax fees” are related to tax processing as well as the preparation ofForms K-1 for our unitholders.

The audit committee of our general partner’s board of directors has adopted an audit committee charter, which is available on our website atwww.calumetspecialty.com. The charter requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee. Since our Audit Committee was not established until January 2006, none of the services reported in the audit, tax and all other fees categories above were pre-approved by the audit committee.

PART IV


Item 15.	*Exhibits*

(a)(2) Financial Statement Schedules

All schedules are omitted because they are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.

(a)(3) Exhibits

The following documents are filed as exhibits to thisForm 10-K:


Exhibit
Number				Description

	3	.1	—	Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	3	.2	—	Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	3	.3	—	Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement onForm S-1 (File No.333-128880))


	3	.4	—	Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.1	—	Term Loan Credit Facility dated as of December 9, 2005, by among Calumet Lubricants Co., Limited Partnership, as Borrower, Calumet Shreveport, LLC, Calumet Shreveport Lubricants & Waxes, LLC and Calumet Shreveport Fuels, LLC, as Guarantors, and Bank of America, N.A., as Administrative Agent and Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))

100


Exhibit
Number				Description

	10	.2*	—	Calumet Specialty Products Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.3	—	Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006(File No. 000-51734))


	10	.4	—	Amendment No. 1 to Contribution, Conveyance and Assumption Agreement


	10	.5*	—	Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	10	.6	—	Omnibus Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.7	—	Crude Oil Supply Contract With Plains Marketing, L.P. (incorporated by reference to Exhibit 10.6 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	10	.8*	—	F. William Grube Employment Contract (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.9	—	Revolving Credit Facility dated as of December 9, 2005, by among Calumet Lubricants Co., Limited Partnership, as Borrower, Calumet Shreveport, LLC, Calumet Shreveport Lubricants & Waxes, LLC and Calumet Shreveport Fuels, LLC, as Guarantors, Bank of America, N.A., as Administrative Agent and Lender, and the other Lenders party thereto (incorporated by reference to Exhibit 10.8 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	21	.1	—	List of Subsidiaries of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 21.1 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	31	.1	—	Sarbanes-Oxley Section 302 certification of F. William Grube


	31	.2	—	Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II


	32	.1	—	Section 1350 certification of F. William Grube and R. Patrick Murray, II


*		Identifies management contract and compensatory plan arrangements.

101

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CALUMET SPECIALTY PRODUCTS
PARTNERS, L.P.


	By:	CALUMET GP, LLC its general partner

	By:	/s/ F. WILLIAM GRUBE

F. William Grube, President, Chief Executive Officer and Director of Calumet GP, LLC (Principal Executive Officer)

Date: March 20, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Name	Title	Date

/s/ F. WILLIAM GRUBE F. William Grube	President, Chief Executive Officer and Director of Calumet GP, LLC (Principal Executive Officer)	Date: March 20, 2006

/s/ ALLAN A. MOYES, III Allan A. Moyes, III	Executive Vice President of Calumet GP, LLC	Date: March 20, 2006

/s/ R. PATRICK MURRAY, II R. Patrick Murray, II	Vice President, Chief Financial Officer and Secretary of Calumet GP, LLC (Principal Accounting and Financial Officer)	Date: March 20, 2006

/s/ FRED M. FEHSENFELD, JR. Fred M. Fehsenfeld, Jr.	Director and Chairman of the Board of Calumet GP, LLC	Date: March 20, 2006

/s/ JAMES S. CARTER James S. Carter	Director of Calumet GP, LLC	Date: March 20, 2006

/s/ WILLIAM S. FEHSENFELD William S. Fehsenfeld	Director of Calumet GP, LLC	Date: March 20, 2006

/s/ ROBERT E. FUNK Robert E. Funk	Director of Calumet GP, LLC	Date: March 20, 2006

/s/ NICHOLAS J. RUTIGLIANO Nicholas J. Rutigliano	Director of Calumet GP, LLC	Date: March 20, 2006

/s/ MICHAEL L. SMITH Michael L. Smith	Director of Calumet GP, LLC	Date: March 20, 2006

102

Index to Exhibits


Exhibit
Number				Description

	3	.1	—	Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	3	.2	—	Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	3	.3	—	Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement onForm S-1 (File No.333-128880))


	3	.4	—	Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.1	—	Term Loan Credit Facility dated as of December 9, 2005, by among Calumet Lubricants Co., Limited Partnership, as Borrower, Calumet Shreveport, LLC, Calumet Shreveport Lubricants & Waxes, LLC and Calumet Shreveport Fuels, LLC, as Guarantors, and Bank of America, N.A., as Administrative Agent and Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	10	.2*	—	Calumet Specialty Products Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.3	—	Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006(File No. 000-51734))


	10	.4	—	Amendment No. 1 to Contribution, Conveyance and Assumption Agreement


	10	.5*	—	Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	10	.6	—	Omnibus Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.7	—	Crude Oil Supply Contract With Plains Marketing, L.P. (incorporated by reference to Exhibit 10.6 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	10	.8*	—	F. William Grube Employment Contract (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report onForm 8-K filed with the Commission on February 13, 2006 (File No. 000-51734))


	10	.9	—	Revolving Credit Facility dated as of December 9, 2005, by among Calumet Lubricants Co., Limited Partnership, as Borrower, Calumet Shreveport, LLC, Calumet Shreveport Lubricants & Waxes, LLC and Calumet Shreveport Fuels, LLC, as Guarantors, Bank of America, N.A., as Administrative Agent and Lender, and the other Lenders party thereto (incorporated by reference to Exhibit 10.8 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	21	.1	—	List of Subsidiaries of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 21.1 of Registrant’s Registration Statement onForm S-1 (FileNo. 333-128880))


	31	.1	—	Sarbanes-Oxley Section 302 certification of F. William Grube


	31	.2	—	Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II


	32	.1	—	Section 1350 certification of F. William Grube and R. Patrick Murray, II


*		Identifies management contract and compensatory plan arrangements.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

Calumet Specialty Products Partners (CLMT) 10-K2005 FY Annual report

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