Edgar Filing: Calumet Specialty Products Partners, L.P.

Form 10-K

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 year ended December 31, 2011

		OR

¨		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File number 000-51734

Calumet Specialty Products Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)


Delaware		37-1516132
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)

2780 Waterfront Pkwy E. Drive

Suite 200

Indianapolis, Indiana 46214

(317) 328-5660

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

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


Title of Each Class		Name of Each Exchange on Which Registered
Common units representing limited partner interests		The NASDAQ Stock Market

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

NONE.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ 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 ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer ¨	Accelerated filer þ	Non-accelerated filer ¨	Smaller reporting company ¨
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the common units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $440.7 million on June 30, 2011, based on $21.50 per unit, the closing price of the common units as reported on the NASDAQ Global Select Market on such date.

On February 27, 2012, there were 51,529,778 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

NONE.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

FORM 10-K — 2011 ANNUAL REPORT

Table of Contents


		Page
PART I
Items 1 and 2.	Business and Properties		3
Item 1A.	Risk Factors		26
Item 1B.	Unresolved Staff Comments		46
Item 3.	Legal Proceedings		46
Item 4.	Mine Safety Disclosures		47

PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		47
Item 6.	Selected Financial Data		50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		55
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		75
Item 8.	Financial Statements and Supplementary Data		80
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		136
Item 9A.	Controls and Procedures		136
Item 9B.	Other Information		137

PART III
Item 10.	Directors, Executive Officers of Our General Partner and Corporate Governance		137
Item 11.	Executive and Director Compensation		142
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		168
Item 13.	Certain Relationships and Related Transactions and Director Independence		171
Item 14.	Principal Accounting Fees and Services		175

PART IV
Item 15.	Exhibits		177

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Annual Report”) includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. The statements regarding (i) estimated capital expenditures as a result of the required audits or required operational changes included in our settlement with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental and regulatory liabilities, (ii) our anticipated levels of, use and effectiveness of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes, (iii) our plans, objectives, expectations and intentions with respect to the future operations of the Superior refinery and associated assets; and (iv) our ability to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, debt instrument covenants, contingencies and anticipated capital expenditures, as well as other matters discussed in this Annual Report that are not purely historical data, are forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, Item 1A “Risk Factors” of this Annual Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

References in this Annual Report to “Calumet Specialty Products Partners, L.P.,” “the Company,” “we,” “our,” “us” or like terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References to “Predecessor” in this Annual Report refer to Calumet Lubricants Co., Limited Partnership and its subsidiaries, the assets and liabilities of which were contributed to Calumet Specialty Products Partners, L.P. and its subsidiaries upon the completion of our initial public offering in 2006. References in this Annual Report to “our general partner” refer to Calumet GP, LLC, the general partner of Calumet Specialty Products Partners, L.P.

PART I

Items 1 and 2. Business and Properties

Overview

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We are headquartered in Indianapolis, Indiana and own plants primarily located in Louisiana, Wisconsin and Pennsylvania. We own and lease additional facilities, primarily related to production and distribution of specialty products, throughout the United States (“U.S.”). Our business is organized into two segments: specialty products and fuel products. In our specialty products segment, we process crude oil and other feedstocks into a wide variety of customized lubricating oils, white mineral oils, solvents, petrolatums, asphalt and waxes. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for basic industrial, consumer and automotive goods. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products including gasoline, diesel, jet fuel and heavy fuel oils. In connection with our production of specialty products and fuel products, we also produce asphalt and a limited number of other by-products. For the year ended December 31, 2011, approximately 57.7% of our sales and 94.4% of our gross profit were generated from our specialty products segment and approximately 42.3% of our sales and 5.6% of our gross profit were generated from our fuel products segment.

Our Primary Operating Assets

Our primary operating assets consist of:

•

Shreveport Refinery. Our refinery located in Shreveport, Louisiana (“Shreveport”) and acquired in 2001 produces specialty lubricating oils and waxes, as well as fuel products such as gasoline, diesel and jet fuel. The Shreveport refinery has aggregate crude oil throughput capacity of approximately 60,000 barrels per day (“bpd”).

•

Superior Refinery. Our refinery located in Superior, Wisconsin (“Superior”) and acquired on September 30, 2011, produces gasoline, diesel, asphalt, heavy fuel oils and specialty petroleum products. The Superior refinery has aggregate crude oil throughput capacity of approximately 45,000 bpd.

•

Cotton Valley Refinery. Our refinery located in Cotton Valley, Louisiana (“Cotton Valley”) and acquired in 1995 produces specialty solvents that are used principally in the manufacture of paints, cleaners, automotive products and drilling fluids. The Cotton Valley refinery has aggregate crude oil throughput capacity of approximately 13,500 bpd.

•

Princeton Refinery. Our refinery located in Princeton, Louisiana (“Princeton”) 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 bpd.

•

Karns City Facility. Our facility located in Karns City, Pennsylvania (“Karns City”) and acquired in 2008 produces white mineral oils, petrolatums, solvents, gelled hydrocarbons, cable fillers and natural petroleum sulfonates. The Karns City facility has aggregate feedstock throughput capacity of approximately 5,500 bpd.

•

Dickinson Facility. Our facility located in Dickinson, Texas (“Dickinson”) and acquired in 2008 produces white mineral oils, compressor lubricants and natural petroleum sulfonates. The Dickinson facility currently has aggregate feedstock throughput capacity of approximately 1,300 bpd.

•

Storage, Distribution and Logistics Assets. We own and operate terminals in Burnham, Illinois (“Burnham”), Rhinelander, Wisconsin (“Rhinelander”), Crookston, Minnesota (“Crookston”) and Proctor, Minnesota (“Duluth”) with aggregate storage capacities of approximately 150,000, 166,000, 156,000, and 200,000 barrels, respectively. These terminals, as well as additional owned and leased

facilities throughout the U.S., facilitate the distribution of products in the Upper Midwest and East Coast regions of the U.S. and Canada. We also use approximately 2,550 leased railcars to receive crude oil or distribute our products throughout the U.S. and Canada. In total, we have approximately 10.7 million barrels of aggregate storage capacity at our facilities and leased storage locations.

Business Strategies

Our management team is dedicated to improving our operations by executing the following strategies:

•

Concentrate on stable cash flows. We intend to continue to focus on operating assets and businesses that generate stable cash flows. Approximately 57.7% of our sales and 94.4% of our gross profit for 2011 were generated by the sale of specialty products, a segment of our business which is characterized by stable customer relationships due to our customers’ requirements for the highly specialized products that we provide. In addition, we manage our exposure to crude oil price fluctuations in this segment by passing on incremental feedstock costs to our specialty products customers and by maintaining from time to time a shorter-term crude oil hedging program. Also, in our fuel products segment, which accounted for 42.3% of our sales and 5.6% of our gross profit in 2011, we seek to mitigate our exposure to fuel products margin volatility by maintaining a longer-term fuel products hedging program. We believe the diversity of our operating assets, products, our broad customer base and our hedging activities help contribute to the stability of our cash flows.

•

Develop and expand our customer relationships. Due to the specialized nature of, and the long lead-time associated with, the development and production of many of our specialty products, our customers are incentivized to continue their relationships with us. We believe that our larger competitors do not work with customers as we do from product design to delivery for smaller volume specialty products like ours. We intend to continue to assist our existing customers in their efforts to expand their product offerings as well as marketing specialty product formulations to new customers. By striving to maintain our long-term relationships with our broad base of existing customers and by adding new customers, we seek to limit our dependence on any one portion of our customer base.

•

Enhance profitability of our existing assets. We continue to evaluate opportunities to improve our existing asset base to increase our throughput, profitability and cash flows. Following each of our asset acquisitions, we have undertaken projects designed to maximize the profitability of our acquired assets. We intend to further increase the profitability of our existing asset base through various measures which may include changing the product mix of our processing units, debottlenecking and expanding units as necessary to increase throughput, restarting idle assets and reducing costs by improving operations. For example, in May 2008 we completed an expansion project at our Shreveport refinery to increase its aggregate crude oil throughput capacity from 42,000 bpd to approximately 60,000 bpd. We also continue to focus on optimizing current operations through energy savings initiatives, product quality enhancements and product yield improvements. We intend to continue this approach with our existing assets, including our recently acquired Superior refinery.

•

Pursue strategic and complementary acquisitions. Since 1990, our management team has demonstrated the ability to identify opportunities to acquire assets and product lines where we can enhance operations and improve profitability. In the future, we intend to continue to consider strategic acquisitions of assets or agreements with third parties that offer the opportunity for operational efficiencies, the potential for increased utilization and expansion of facilities, or the expansion of product offerings in our specialty products segment. In addition, we may pursue selected acquisitions in new geographic or product areas to the extent we perceive similar opportunities. For example, on September 30, 2011, we completed the acquisition of the Superior refinery and associated operating assets and inventories, which we believe provides greater scale, geographic diversity and development potential to our refining business. Additionally, we completed the acquisition of TruSouth and the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) from Hercules Incorporated, a subsidiary of Ashland, Inc. in January 2012, each of which we believe provides greater diversity to our specialty products segment. See “—Recent Acquisitions” below for additional information regarding these acquisitions.

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 1,500 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 in our ability to produce numerous specialty products is our ability to ship products between our facilities for product upgrading in order to meet customer specifications.

•

We have strong relationships with a broad customer base. We have long-term relationships with many of our customers and we believe that we will continue to benefit from these relationships. Our customer base includes over 2,700 active accounts and we are continually seeking new customers. No single customer accounted for more than 10% of our consolidated sales in each of the three years ended December 31, 2011, 2010 and 2009.

•

Our facilities have advanced technology. Our facilities are equipped with advanced, flexible technology that allows us to produce high-grade specialty products and to produce fuel products that comply with low sulfur fuel regulations. For example, our Shreveport and Superior refineries have the capability to make ultra low sulfur diesel and gasoline that meets federally mandated low sulfur standards and the Mobile Source Air Toxic Rule II standards (“MSAT II standards”) set by the U.S. Environmental Protection Agency (“EPA”) requiring the reduction of benzene levels in gasoline effective January 1, 2011. Also, unlike larger refineries, which lack some of the equipment necessary to achieve the narrow distillation ranges associated with the production of specialty products, our operations are capable of producing a wide range of products tailored to our customers’ needs.

•

We have 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 has an average of over 25 years of industry experience. Our team’s extensive experience and contacts within the refining industry provide a strong foundation and focus for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing and enhancing the profitability of new assets.

Recent Acquisitions

Superior Acquisition

On September 30, 2011, we completed the acquisition of the Superior refinery and associated operating assets and inventories and related business of Murphy Oil Corporation (“Murphy Oil”) for aggregate consideration of approximately $413.2 million (the “Superior Acquisition”). The Superior Acquisition was financed by a combination of (i) net proceeds of $193.5 million from our September 2011 public offering of common units (including our general partner’s contribution and excluding the over-allotment option exercised), (ii) net proceeds of $180.3 million from our September 2011 private placement of 9³/8% senior notes due May 1, 2019 and (iii) borrowings under our revolving credit facility. We acquired the following assets (collectively, the “Superior Business”):

•

the Superior refinery, with crude oil throughput capacity of approximately 45,000 bpd, which produces gasoline, diesel, asphalt, heavy fuel oils and specialty petroleum products that are primarily marketed in the Upper Midwest region of the U.S. and in Canada;

•

a distribution network for fuel and asphalt products operated through various owned and leased terminals located in Wisconsin, Minnesota and Utah and associated inventories and logistics assets located at each of the terminals; and

•

Murphy Oil’s “SPUR” branded gasoline wholesale business and related assets.

We believe the Superior Acquisition provides greater scale, geographic diversity and development potential to our refining business, increasing our current total refining throughput capacity by 50% to 135,000 bpd.

Hercules Synthetic Lubricants Business

On January 3, 2012, we completed the acquisition of the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) from Hercules Incorporated, a subsidiary of Ashland, Inc., for aggregate consideration of approximately $19.6 million, excluding certain customary post-closing purchase price adjustments. The acquisition was financed with borrowings under our revolving credit facility and cash on hand. We also acquired a manufacturing facility located in Louisiana, Missouri.

TruSouth Oil

On January 6, 2012, we completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC, a specialty petroleum packaging and distribution company and related party, located in Shreveport, Louisiana (“TruSouth”) for aggregate consideration of approximately $25.5 million, which was financed with borrowings under our revolving credit facility. Please read Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — TruSouth Acquisition” for further discussion of our acquisition of TruSouth.

We believe these subsequent acquisitions provide greater diversity to our specialty products segment.

Partnership Structure and Management

Calumet Specialty Products Partners, L.P. is a Delaware limited partnership formed on September 27, 2005. Our general partner is Calumet GP, LLC, a Delaware limited liability company. As of February 27, 2012, we had 51,529,778 common units and 1,051,628 general partner units outstanding. Our general partner owns 2% of the Company and all incentive distribution rights and has sole responsibility for conducting our business and managing our operations. For more information about our general partner’s board of directors, executive officers and other management, please read Part III, Item 10 “Directors, Executive Officers of Our General Partner and Corporate Governance.”

Our Operating Assets and Contractual Arrangements

General

We own and operate refineries in northwest Louisiana, which consist of the Shreveport, Cotton Valley and Princeton refineries, and in Superior, Wisconsin. We also own and operate facilities in Karns City, Pennsylvania; Dickinson, Texas and terminals in Burnham, Illinois; Rhinelander, Wisconsin; Crookston and Proctor, Minnesota and lease and operate a terminal in Duluth, Minnesota. We own and lease additional facilities, primarily related to distribution of products, throughout the U.S. Additionally, we have contractual arrangements with LyondellBasell and other third parties which provide us additional volumes of finished products for our specialty products segment.

The following tables set forth information about our combined operations and sales of our principal products by segment. Facility production volume differs from sales volume due to changes in inventory and the sale of purchased fuel product blendstocks such as ethanol and biodiesel in our fuel products segment sales. The tables include volumes under the LyondellBasell Agreements commencing November 4, 2009 and the results of operations at our Superior refinery commencing October 1, 2011. Please see “— LyondellBasell Agreements” below for additional information on the LyondellBasell Agreements and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,
	2011		2010		2009
	(In bpd)
Total sales volume (1)		66,134		55,668		57,086
Total feedstock runs (2)		69,295		55,957		60,081
Facility production:
Specialty products:
Lubricating oils		14,427		13,697		11,681
Solvents		10,508		9,347		7,749
Waxes		1,269		1,220		1,049
Fuels		556		1,050		853
Asphalt and other by-products		10,090		6,907		7,574

Total		36,850		32,221		28,906

Fuel products:
Gasoline		13,409		8,754		9,892
Diesel		14,721		10,800		12,796
Jet fuel		4,520		5,004		6,709
Heavy fuel oils and other		1,409		535		489

Total		34,059		25,093		29,886

Total facility production (3)		70,909		57,314		58,792

(1)

Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, and sales of inventories. Total sales volume excludes the sale of purchased fuel product blendstocks such as ethanol and biodiesel as components of finished fuel products in our fuel products segment sales.

(2)	Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements.

(3)


	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Sales of specialty products:
Lubricating oils	$	947,798	$	759,701	$	500,938
Solvents		495,934		396,894		260,185
Waxes		143,111		124,964		97,658
Fuels (1)		3,432		5,507		8,951
Asphalt and other by-products (2)		217,351		121,806		103,488

Total		1,807,626		1,408,872		971,220

Sales of fuel products:
Gasoline		619,630		304,544		317,435
Diesel		513,334		330,756		372,359
Jet fuel		148,036		135,796		167,638
Heavy fuel oils and other (3)		46,297		10,784		17,948

Total		1,327,297		781,880		875,380

Consolidated sales	$	3,134,923	$	2,190,752	$	1,846,600

(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 Shreveport, Superior, Cotton Valley and Princeton refineries.

(3)	Represents heavy fuel oils and other products produced in connection with the production of fuels at the Shreveport and Superior refineries.

Please read Note 15 “Segments and Related Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of the Annual Report for additional financial information about each of our segments and the geographical areas in which we conduct business.

Shreveport Refinery

The Shreveport refinery, located on a 240-acre site in Shreveport, Louisiana, currently has aggregate crude oil throughput capacity of 60,000 bpd and processes paraffinic crude oil and associated feedstocks into fuel products, paraffinic lubricating oils, waxes, residuals and by-products.

The Shreveport refinery consists of 17 major processing units, approximately 3.3 million barrels of storage capacity in 130 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Shreveport refinery in 2001, we have expanded the refinery’s capabilities by adding additional processing and blending facilities, added a second reactor to the high pressure hydrotreater, resumed production of gasoline, diesel and other fuel products at the refinery and added both 18,000 bpd of crude oil throughput capacity and the capability to run up to 25,000 bpd of sour crude oil with an expansion project completed in May 2008. The following table sets forth historical information about production at our Shreveport refinery.


	Shreveport Refinery
	Year Ended December 31,
	2011		2010		2009
	(In bpd)
Crude oil throughput capacity		60,000		60,000		60,000
Total feedstock runs (1) (2)		39,910		36,409		43,639
Total refinery production (2) (3)		39,910		36,395		43,467

(1)	Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Shreveport refinery. Total feedstock runs do not include certain interplant feedstocks supplied by our Cotton

Valley refinery. The increase in feedstock runs in 2011 as compared to 2010 is due primarily to the decision to increase crude oil run rates in 2011 because of favorable economics of running additional barrels and the failure of an environmental operating unit in the first quarter of 2010 which impacted run rates in the first and second quarter of 2010. The decrease in feedstock runs in 2010 as compared to 2009 is due primarily to our decision to reduce crude oil run rates at our facilities during the entire first quarter of 2010 because of the poor economics of running additional barrels, the failure of an environmental operating unit during the first quarter of 2010 and scheduled turnarounds completed in the second and fourth quarters of 2010 related to various operating units at our Shreveport refinery.

(2)

Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. The increase in total refinery production is due primarily to the decision to increase crude oil run rates in 2011 as discussed in Note 1 above.

(3)	Total refinery production includes certain interplant feedstock supplied to our Cotton Valley refinery and Karns City facility.

The Shreveport refinery has a flexible operational configuration and operating personnel that facilitate development of new product opportunities. Product mix may fluctuate from one period to the next to capture market opportunities. The refinery has an idle residual fluid catalytic cracking unit, alkylation unit, vacuum tower and a number of idle towers that can be utilized for future project needs. Certain idle towers were utilized as a part of the Shreveport refinery expansion project completed in 2008.

The Shreveport refinery currently makes jet fuel and ultra low sulfur diesel and all of its gasoline production currently meets MSAT II standards. To the extent we exceed the minimum requirements of the MSAT II Standards, we have the option to sell renewable fuel credits, also known as RINs credits and have the option to purchase RINs credits if we operate the refinery in a manner that does not meet these minimum requirements.

The Shreveport refinery receives crude oil via tank truck, railcar and common carrier pipeline systems that are operated by subsidiaries of Plains All American Pipeline, L.P. (“Plains”) and Exxon Mobil Corporation (“ExxonMobil”) and are connected to the Shreveport refinery’s facilities. The Plains pipeline system delivers local supplies of crude oil and condensates from north Louisiana and east Texas. The ExxonMobil pipeline system delivers domestic crude oil supplies from south Louisiana and foreign crude oil supplies from the Louisiana Offshore Oil Port (“LOOP”) or other crude oil terminals. Crude oil is purchased from various suppliers, including local producers who deliver crude oil to the Shreveport refinery via tank truck. From September 2009 to May 2011, a portion of our Shreveport refinery’s crude oil requirements were purchased through Legacy Resources Co., L.P. (“Legacy Resources”), a related party. After May 31, 2011, we purchased the crude oil supply for the Shreveport refinery previously supplied by Legacy Resources directly from third-party suppliers under month-to-month evergreen supply contracts and on the spot market. See Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — Crude Oil Purchases” for additional information regarding our crude oil purchases from Legacy Resources.

The Shreveport refinery also has direct pipeline access to the Enterprise Products Partners L.P. pipeline (“TEPPCO pipeline”), on which it can ship all grades of gasoline, diesel and jet fuel. Further, the refinery has direct access to the Red River Terminal facility, which provides the refinery with barge access, via the Red River, to major feedstock and petroleum products logistics networks on the Mississippi River and Gulf Coast inland waterway system. The Shreveport refinery also ships its finished products throughout the country through both truck and railcar service.

Superior Refinery

The Superior refinery is located on a 245-acre site, with an additional 430 acres owned around the existing refinery. The Superior refinery currently has aggregate crude oil throughput capacity of 45,000 bpd and is currently processing light and heavy crude oil from the Bakken shale oil formation in North Dakota and Canada into fuel products, asphalt and specialty petroleum products.

The Superior refinery consists of 14 major processing units including hydrotreating, catalytic reforming, fluid catalytic cracking and alkylation units with approximately 3.2 million barrels of storage capacity in 76 tanks and related loading and unloading facilities and utilities. The following table sets forth historical information about our production at our Superior refinery since its acquisition on September 30, 2011.


	Superior Refinery
	Three Months Ended December 31, 2011
	(In bpd)
Crude oil throughput capacity		45,000
Total feedstock runs (1) (2)		35,335
Total refinery production (2)		35,335

(1)	Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Superior refinery from October 1, 2011 through December 31, 2011.

(2)

Total refinery production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks from October 1, 2011 through December 31, 2011. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.

The Superior refinery has a flexible operational configuration and operating personnel that facilitate development of new product opportunities. Product mix may fluctuate from one period to the next to capture market opportunities. Currently the Superior refinery produces gasoline, diesel, asphalt, heavy fuel oils and specialty petroleum products. The Superior refinery is compliant with federal regulations for ultra low sulfur diesel and low sulfur gasoline production. To the extent we exceed the minimum requirements of the MSAT II Standards, we have the option to sell renewable fuel credits, also known as RINs credits and have the option to purchase RINs credits if we operate the refinery in a manner that does not meet these minimum requirements.

Finished fuel products produced at the Superior refinery are transported through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through the Superior refinery and its own terminal located in Duluth, Minnesota. The Superior wholesale fuel business also sells gasoline wholesale to SPUR branded gas stations located throughout the Upper Midwest, which are owned and operated by independent franchisees. The Superior refinery ships finished fuel products by railcar and truck. Asphalt products produced at the Superior refinery are transported by truck through its owned terminals in Rhinelander, Wisconsin and Crookston, Minnesota and through other leased terminals in the U.S.

Finished fuel products sales are primarily made through spot agreements and short-term contracts. Asphalt production is primarily sold through spot agreements and short-term contracts with asphalt customers primarily located in and around the Upper Midwest (including Minnesota, Wisconsin and Michigan), North Dakota, South Dakota and Utah.

The Superior refinery receives crude oil by pipeline through the Enbridge Pipeline System (“Enbridge”) and is adjacent to one of Enbridge’s first crude oil holding facilities after crossing the Canadian border into the U.S. The refinery receives approximately 75% of its daily crude oil requirements under a crude oil purchase agreement (the “BP Purchase Agreement”) with BP Products North America Inc. (“BP”). In addition, the refinery receives up to 10,000 bpd of crude oil under a crude oil purchase agreement with Murphy Oil (“Murphy

Crude Oil Supply Agreement”). For more information about the BP Purchase Agreement and the Murphy Crude Oil Supply Agreement, please read the information provided under Note 3 “Superior Acquisition” in Part II, Item 8 “Financial Statements and Supplementary Data” of the Annual Report.

Cotton Valley Refinery

The Cotton Valley refinery, located on a 77-acre site in Cotton Valley, Louisiana, has aggregate crude oil throughput capacity of 13,500 bpd, hydrotreating capacity of 6,200 bpd and processes crude oil into solvents, fuel feedstocks and residual fuel oil. The residual fuel oil is an important feedstock for the production of specialty products at our Shreveport refinery. We believe the Cotton Valley refinery produces the most complete, single-facility line of paraffinic solvents in the U.S.

The Cotton Valley refinery consists of three major processing units that include a crude unit, a hydrotreater and a fractionation train, approximately 625,000 barrels of storage capacity in 74 storage tanks and related loading and unloading facilities and utilities. The Cotton Valley refinery also has a utility fractionator for batch processing of narrow distillation range specialty solvents. Since our acquisition of the Cotton Valley refinery in 1995, we have expanded the refinery’s capabilities by installing a hydrotreater that removes aromatics, increased the crude unit processing capability to 13,500 bpd and reconfigured the refinery’s fractionation train to improve product quality, enhance flexibility and lower utility costs. The following table sets forth historical information about production at our Cotton Valley refinery.


	Cotton Valley Refinery
	Year Ended December 31,
	2011		2010		2009
	(In bpd)
Crude oil throughput capacity		13,500		13,500		13,500
Total feedstock runs (1) (2)		5,806		5,510		5,466
Total refinery production (2) (3)		7,951		7,229		6,455

(1)	Total feedstock runs do not include certain interplant solvent feedstocks supplied by our Shreveport refinery.

(2)

Total refinery production represents the barrels per day of specialty products yielded from processing crude oil and other feedstocks. The difference between total refinery production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.

(3)	Total refinery production includes certain interplant feedstocks supplied to our Shreveport refinery.

The Cotton Valley refinery 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 finished product inventory requirements.

The Cotton Valley refinery receives crude oil via truck and through a pipeline system operated by a subsidiary of Plains. The Cotton Valley refinery’s feedstock is primarily low sulfur, paraffinic crude oil originating from north Louisiana and is purchased from various marketers and gatherers. In addition, the Cotton Valley refinery receives interplant feedstocks for solvent production from the Shreveport refinery. The Cotton Valley refinery ships finished products by both truck and railcar service.

Princeton Refinery

The Princeton refinery, located on a 208-acre site in Princeton, Louisiana, has aggregate crude oil throughput capacity of 10,000 bpd and processes naphthenic crude oil into lubricating oils, asphalt and feedstock for the Shreveport refinery for further processing into ultra low sulfur diesel. The asphalt produced may be processed or blended for coating and roofing product applications at the Princeton refinery or transported to the Shreveport refinery for processing into bright stock.

The Princeton refinery consists of seven major processing units, approximately 650,000 barrels of storage capacity in 200 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Princeton refinery in 1990, we have debottlenecked the crude unit to increase production capacity to 10,000 bpd, increased the hydrotreater’s capacity to 7,000 bpd and upgraded the refinery’s fractionation unit, which has enabled us to produce higher value specialty products. The following table sets forth historical information about production at our Princeton refinery.


	Princeton Refinery
	Year Ended December 31,
	2011		2010		2009
	(In bpd)
Crude oil throughput capacity		10,000		10,000		10,000
Total feedstock runs (1)		6,844		6,096		6,076
Total refinery production (1)		6,895		6,138		5,999

(1)

The Princeton refinery has a hydrotreater and significant fractionation capability enabling the refining of high quality naphthenic lubricating oils at numerous distillation ranges. The Princeton refinery’s processing capabilities consist of atmospheric and vacuum distillation, hydrotreating, asphalt oxidation processing and clay/acid treating. In addition, we have the necessary tankage and technology to process our asphalt into higher value product applications such as coatings and road paving.

The Princeton refinery receives crude oil via tank truck, railcar and pipeline. Its crude oil supply primarily originates from east Texas and north Louisiana and was purchased through Legacy Resources, a related party, for the period of May 2008 to May 2011. After May 31, 2011, we purchased the crude oil supply for the Princeton refinery directly from third-party suppliers under month-to-month evergreen supply contracts and on the spot market. See Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — Crude Oil Purchases” for additional information regarding our crude oil purchases from Legacy Resources. The Princeton refinery ships its finished products throughout the country by both truck and railcar service.

Karns City Facility

The Karns City facility, located on a 225-acre site in Karns City, Pennsylvania, currently has aggregate base oil throughput capacity of 5,500 bpd and is currently processing white mineral oils, solvents, petrolatums, gelled hydrocarbons, cable fillers and natural petroleum sulfonates. The Karns City facility’s processing capability includes hydrotreating, fractionation, acid treating, filtering, blending and packaging, approximately 817,000 barrels of storage capacity in 250 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks by railcar and truck under supply agreements with various suppliers, the most significant of which is a long-term supply agreement with ConocoPhillips. Please read “— Crude Oil and Feedstock Supply” below for further discussion of the long-term supply agreement with ConocoPhillips.

Dickinson Facility

The Dickinson facility, located on a 28-acre site in Dickinson, Texas, currently has aggregate base oil throughput capacity of 1,300 bpd and is currently processing white mineral oils, compressor lubricants and natural petroleum sulfonates. The Dickinson facility’s processing capability includes acid treating, filtering and blending, approximately 183,000 barrels of storage capacity in 186 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks by railcar and truck under supply agreements with various suppliers, the most significant of which is a long-term supply agreement with ConocoPhillips. Please read “— Crude Oil and Feedstock Supply” below for further discussion of the long-term supply agreement with ConocoPhillips.

The following table sets forth the combined historical information about production at our Karns City and Dickinson facilities.


	Combined Karns City and Dickinson Facilities
	Year Ended December 31,
	2011		2010		2009
	(in bpd)
Feedstock throughput capacity (1)		6,800		6,800		6,800
Total feedstock runs (2)		4,502		5,051		4,595
Total production (3)		4,482		5,041		4,590

(1)	Includes Karns City and Dickinson facilities only.

(2)	Includes feedstock runs at our Karns City and Dickinson facilities as well as throughput at certain third-party facilities pursuant to supply and/or processing agreements and includes certain interplant feedstocks supplied from our Shreveport refinery.

(3)

Total production represents the barrels per day of specialty products yielded from processing feedstocks at our Karns City and Dickinson facilities and certain third-party facilities pursuant to supply and/or processing agreements. The difference between total production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and the production of finished products.

LyondellBasell Agreements

In November 2009, we entered into agreements (the “LyondellBasell Agreements”) with Houston Refining LP, a wholly owned subsidiary of LyondellBasell (“Houston Refining”) to form a long-term specialty products affiliation under which Houston Refining provides us finished products for our specialty products segment. The initial term of the LyondellBasell Agreements expires on October 31, 2014 after which it is automatically extended for additional one-year terms until either party terminates with 24 months notice. Under the terms of the LyondellBasell Agreements, (i) we are required to purchase at least a minimum volume of 3,100 bpd of naphthenic lubricating oils produced at Houston Refining’s Houston, Texas refinery, and we have a right of first refusal to purchase any additional naphthenic lubricating oils produced at the refinery, and (ii) Houston Refining is required to process a minimum of approximately 800 bpd of white mineral oil for us at its Houston, Texas refinery, which supplements the white mineral oil production at our Karns City and Dickinson facilities. Our annual purchase commitment under these agreements is approximately $190.5 million. LyondellBasell has also granted us rights to use certain registered trademarks and tradenames, including Tufflo, Duoprime, Duotreat, Crystex, Ideal and Aquamarine.

The following table sets forth the combined historical information about production under the LyondellBasell Agreements.


	LyondellBasell Agreements
	Year Ended December 31,
	2011		2010		2009
	(in bpd)
Feedstock throughput capacity (1)		4,500		4,500		4,500
Total production under the LyondellBasell Agreements (2)		3,321		2,876		1,994

(1)	Estimated total capacity of the naphthenic lubricating oil and white oil hydrotreating units at Houston Refining’s Houston, Texas refinery.

(2)

For 2009, represents the period from November 4, 2009 through December 31, 2009. Total production in 2011, 2010 and 2009 did not meet anticipated levels, as Houston Refining’s Houston, Texas refinery experienced downtime due to various turnarounds and operational issues and, thus, we could not purchase the minimum as defined in the agreement.

Terminals

Our terminals are complementary to our refineries and play a key role in moving our products to end-user markets by providing services including distribution, blending to achieve specified products and storage and inventory management. We operate the following terminals:

Burnham Terminal: We own and operate a terminal located on an 11-acre site, in Burnham, Illinois. The Burnham terminal receives specialty products from certain of our refineries and distributes them by truck to our customers in the Upper Midwest and East Coast regions of the U.S. and in Canada. The terminal includes a tank farm with 67 tanks with aggregate storage capacity of approximately 150,000 barrels as well as blending equipment.

Rhinelander Terminal: We own and operate a terminal located on an 18-acre site, in Rhinelander, Wisconsin. The Rhinelander terminal receives asphalt by truck from the Superior refinery and distributes the product by truck. Asphalt is sold to customers in the Upper Midwest regions of the U.S. The terminal includes a tank farm with four tanks with aggregate storage capacity of approximately 166,000 barrels.

Crookston Terminal: We own and operate a terminal located on a 19-acre site in Crookston, Minnesota. The Crookston terminal receives asphalt by truck from the Superior refinery and distributes by truck. Asphalt is sold to customers in the Upper Midwest regions of the U.S. The terminal includes a tank farm with three tanks with aggregate storage capacity of approximately 156,000 barrels.

Duluth Terminal: We own and operate a terminal located on a 49-acre site in Proctor, Minnesota. The Duluth terminal is supplied by the Magellan pipeline and receives finished fuel products by truck and includes seven tanks with aggregate storage capacity of approximately 200,000. Fuel products from this terminal are distributed by truck to customers in Minnesota and northern Wisconsin.

In addition to the above terminals, we own and lease additional facilities, primarily related to distribution of finished products, throughout the U.S.

Other Logistics Assets

We also use approximately 2,550 railcars leased from various lessors. This fleet of railcars enables us to receive crude oil and distribute various specialty products throughout the U.S. and Canada to and from each of our facilities.

Our Crude Oil and Feedstock Supply

We purchase crude oil and other feedstocks from major oil companies, as well as from various crude oil gatherers and marketers in east Texas, north Louisiana, North Dakota and Canada. The Shreveport refinery also receives crude oil through the ExxonMobil pipeline system originating in St. James, Louisiana, providing the refinery with access to domestic crude oils and foreign crude oils through the LOOP or other terminal locations. The Superior refinery receives crude oil though the Enbridge Pipeline System. The Superior refinery is adjacent to the first U.S. destination point for the Enbridge Pipeline System after the U.S.-Canadian border, providing reliable access to high quality crude oils from the Bakken shale oil formation in North Dakota and from western Canada.

In 2011, subsidiaries of Plains supplied us with approximately 49.7% of our total crude oil supplies under term contracts and month-to-month evergreen crude oil supply contracts and 4.5% of our total crude oil purchases in 2011 were from Legacy Resources, which supplied crude oil to our Princeton and Shreveport refineries. Commencing November 1, 2011, BP began supplying the Superior refinery with approximately 75% of its daily crude oil requirements. Total crude oil requirements for the Superior refinery are estimated to be between 35,000 and 45,000 bpd. In addition, the Superior refinery receives up to 10,000 bpd of crude oil under the Murphy Crude Oil Supply Agreement. Each of our refineries is dependent on one or more of these key suppliers and the loss of any of these suppliers would adversely affect our financial results to the extent we were

unable to find another supplier of this substantial amount of crude oil. For more information about the BP Purchase Agreement and the Murphy Crude Oil Supply Agreement, please read the information provided under Note 3 “Superior Acquisition” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

We do not maintain long-term contracts with most of our suppliers. For example, our contracts with Plains are currently month-to-month, terminable upon 90 days notice, and our contract with BP has an initial term of seven months ending April 30, 2012, will automatically renew for successive one-year terms unless terminated by either party upon 90 days’ notice prior to the end of any renewal term. Since terminating crude oil supply agreements with Legacy Resources effective May 31, 2011, we have one remaining crude oil supply agreement with Legacy under which we are not currently purchasing any crude oil; rather we have purchased the crude oil supply for the Princeton and Shreveport refineries directly from third-party suppliers under month-to-month evergreen supply contracts and on the spot market. Refer to Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — Crude Oil Purchases” for further information on our related party crude oil purchases. We also purchase foreign crude oil when its spot market price is attractive relative to the price of crude oil from domestic sources. We believe that adequate supplies of crude oil will continue to be available to us.

Our cost to acquire crude oil and feedstocks and the prices for which we ultimately can sell refined products depend on a number of factors beyond our control, including regional and global supply of and demand for crude oil and other feedstocks and specialty and fuel products. These in turn are dependent upon, among other things, the availability of imports, overall economic conditions, 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 crude oil and feedstock prices to our specialty products customers, although the increase in selling prices for specialty products typically lags the rising cost of crude oil. From time to time, we use a hedging program to manage a portion of this commodity price risk. Please read Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk — Crude Oil Price Volatility and Hedging Policy” for a discussion of our crude oil hedging program for our specialty products segment.

We have various long-term supply agreements with ConocoPhillips, with remaining terms ranging from one to six years, with some agreements operating under the option to continue on a month-to-month basis thereafter, for feedstocks that are key to the operations of our Karns City and Dickinson facilities. In addition, certain products of our refineries can be used as feedstocks by these facilities. We believe that adequate supplies of feedstocks are available for these facilities.

Our Products, Markets and Customers

Products

We produce a full line of specialty products, including lubricating oils, solvents and waxes, as well as a variety of fuel products. Our customers purchase these products primarily as raw material components for basic industrial, consumer and automotive goods. The following table depicts the diversity of end-use applications for the products we produce:

Representative Sample of End Use Applications by Product¹


Lubricating Oils 20%	Solvents 15%	Waxes 2%	Asphalt & Other 15%	Fuels & Fuel Related 48%

• Hydraulic oils • Passenger car motor oils • Railroad engine oils • Cutting oils • Compressor oils • Rubber process oils • Industrial lubricants • Gear oils • Grease • Automatic transmission fluid • Animal feed dedusting • Baby oils • Bakery pan oils • Catalyst carriers • Gelatin capsule lubricants • Sunscreen	• Waterless hand cleaners • Alkyd resin diluents • Automotive products • Calibration fluids • Camping fuel • Charcoal lighter fluids • Chemical processing • Drilling fluids • Printing inks	• Paraffin waxes • FDA compliant products • Candles • Adhesives • Crayons • Floor care • PVC • Paint strippers • Skin & hair care • Timber treatment • Waterproofing • Pharmaceuticals • Cosmetics	• Roofing • Paving	• Gasoline • Diesel • Jet fuel • Fluid catalytic cracking feedstock • Asphalt vacuum residuals • Mixed butanes • Heavy fuel oils

⁽¹⁾	Based on the percentage of actual total production for the year ended December 31, 2011 and includes the results of operations at our Superior refinery commencing October 1, 2011. Except for the listed fuel products, we do not produce any of these end-use products.

We have an experienced marketing department with average industry tenure of approximately 20 years. Our salespeople regularly visit customers and our marketing department works closely with both the laboratories at our refineries and our technical services 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 U.S., 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 metalworking fluids, belts, hoses, sealing systems, batteries, hot melt adhesives, pressure sensitive tapes, electrical transformers, refrigeration compressors and drilling fluids;

•

consumer goods such as candles, petroleum jelly, creams, tonics, lotions, coating on paper cups, chewing gum base, automotive aftermarket car-care products (fuel injection cleaners, tire shines and polishes), lamp oils, charcoal lighter fluids, camping fuel and various aerosol products; and

•

automotive goods such as motor oils, greases, transmission fluid and tires.

We have the capability to ship our specialty products worldwide. In the U.S. and Canada, we ship our specialty products via railcars, trucks and barges. In 2011, approximately 37.9% of our specialty products sales were shipped in our fleet of approximately 2,550 leased railcars, approximately 59.7% of our specialty products sales were shipped in trucks owned and operated by several different third-party carriers and the remaining 2.4% were shipped via water transportation. For shipments outside of North America, which accounted for less than 10% of our consolidated sales in 2011, we ship railcars and trucks to several ports where the product is loaded on vessels for shipment to customers abroad.

Fuel Products. The fuel products market represents a large portion of the overall petroleum refining industry in the United States. Of the nearly 150 refineries currently in operation in the U.S., a large number of the refineries are fuel products producers and only a few compete with us in our local markets.

Fuel products produced at our Shreveport refinery can be sold locally or to the Midwest region of the U.S. through the TEPPCO pipeline. Local sales are made from the TEPPCO terminal in Bossier City, Louisiana, which is located approximately 15 miles from the Shreveport refinery, as well as from our own Shreveport refinery terminal.

During 2011, we sold gasoline, diesel and jet fuel from the Shreveport refinery into the Louisiana, Texas and Arkansas markets, and any excess volumes to marketers further up the TEPPCO pipeline. Should the appropriate market conditions arise, we have the capability to redirect and sell additional volumes into the Louisiana, Texas and Arkansas markets rather than transport them to the Midwest region via the TEPPCO pipeline.

The Shreveport refinery has the capacity to produce about 9,000 bpd of commercial jet fuel that can be marketed to the Barksdale Air Force Base in Bossier City, Louisiana, sold as Jet-A locally or via the TEPPCO pipeline, or occasionally transferred to the Cotton Valley refinery to be processed further as a feedstock to produce solvents. We have a sales contract with the U.S. Department of Defense covering the Barksdale Air Force Base for approximately 2,400 bpd of jet fuel. This contract is effective until April 2012 and is bid annually.

Additionally, we produce a number of fuel-related products including fluid catalytic cracking (“FCC”) feedstock, vacuum residuals and mixed butanes. FCC feedstock is sold to other refiners as a feedstock for their FCC units to make fuel products. Vacuum residuals are blended or processed further to make specialty asphalt products. Volumes of vacuum residuals which we cannot process are sold locally into the fuel oil market or sold via railcar to other refiners. Mixed butanes are primarily available in the summer months and are primarily sold to local marketers. If the mixed butanes are not sold, they are blended into our gasoline production.

Fuel products produced at our Superior refinery can be sold locally and in the Upper Midwest region of the U.S. and in Canada. The Superior wholesale business transports fuel products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through its own leased or owned product terminals located in Superior, Wisconsin and Duluth, Minnesota. The Superior wholesale business also sells gasoline wholesale to SPUR branded gas stations throughout the Upper Midwest, which are owned and operated by independent franchisees.

Customers

Specialty Products. We have a diverse customer base for our specialty products, with approximately 2,700 active accounts. Most of our customers are long-term customers who use our products in specialty applications

which require six months to two years to gain approval for use in their products. No single customer of our specialty products segment accounted for more than 10% of our consolidated sales in each of the three years ended December 31, 2011, 2010 and 2009.

Fuel Products. We have a diverse customer base for our fuel products, with approximately 160 active accounts. We are able to sell the majority of the fuel products we produce at the Shreveport refinery to the local markets of Arkansas, Louisiana and east Texas. We also have the ability to ship additional fuel products from the Shreveport refinery to the Midwest region through the TEPPCO pipeline should the need arise. Additionally, we are able to sell the majority of the fuel products we produce at the Superior refinery to local markets in Minnesota and Wisconsin. We also have the ability to ship additional fuel products from the Superior refinery to the Upper Midwest region and in Canada through the Magellan pipeline. No single customer of our fuel products segment represented 10% or greater of consolidated sales in each of the three years ended December 31, 2011, 2010 and 2009.

Competition

Competition in our markets is from a combination of large, integrated petroleum companies, independent refiners and wax production companies. Many of our competitors are substantially larger than us and are engaged on a national or international basis in many segments of the petroleum products business, including exploration and production, refining, transportation and marketing. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We distinguish our competitors according to the products that they produce. Set forth below is a description of our significant competitors according to product category.

Naphthenic Lubricating Oils. Our primary competitor in producing naphthenic lubricating oils is Ergon Refining, Inc. We also compete with Cross Oil Refining and Marketing, Inc. and San Joaquin Refining Co., Inc.

Paraffinic Lubricating Oils. Our primary competitors in producing paraffinic lubricating oils include ExxonMobil, Motiva Enterprises, LLC, ConocoPhillips, Petro-Canada, Holly Corporation and Sonneborn Refined Products.

Paraffin Waxes. Our primary competitors in producing paraffin waxes include ExxonMobil and The International Group Inc.

Solvents. Our primary competitors in producing solvents include Citgo Petroleum Corporation, Exxon Chemical and ConocoPhillips.

Fuel Products and By-Products. Our primary competitors in producing fuel products in the local markets in which we operate include Delek Refining, Ltd., Lion Oil Company, Flint Hills Resources, LP and Northern Tier Energy, Inc.

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 and Occupational Health and Safety Matters

We operate crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose numerous obligations that are applicable to our operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which we may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the

application of specific health and safety criteria addressing worker protection and imposing substantial liabilities on us for pollution resulting from our operations. Certain of these 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 or 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”) initiated enforcement actions in prior years for the following alleged violations (the “Alleged LDEQ Violations”): (i) a May 2001 notification received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations, as identified in the course of our Leak Detection and Repair program, and also for failure to submit various reports related to the facility’s air emissions; (ii) a December 2002 notification received by the Cotton Valley refinery from the LDEQ regarding alleged violations for excess emissions, as identified in the LDEQ’s file review of the Cotton Valley refinery; (iii) a December 2004 notification received by the Cotton Valley refinery from the LDEQ regarding alleged violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency; and (iv) an August 2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations, as identified by LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emission levels.

On December 23, 2010, we entered into a settlement agreement with the LDEQ regarding (i) our voluntary participation in the LDEQ’s “Small Refinery and Single Site Refinery Initiative”, with respect to its Louisiana refineries, and (ii) the Alleged LDEQ Violations described above. The LDEQ’s “Small Refinery and Single Site Refinery Initiative” is patterned after the U.S. Environmental Protection Agency’s (“EPA”) “National Petroleum Refinery Initiative,” which is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. The agreement, voluntarily entered into by us, requires us to make a $1.0 million payment to the LDEQ, complete beneficial environmental programs and implement emissions reduction projects at our Shreveport, Cotton Valley and Princeton refineries. As of December 31, 2011, we have incurred approximately $4.0 million in expenditures and we estimate additional expenditures of approximately $7.0 million to $11.0 million of capital expenditures and expenditures related to additional personnel and environmental studies through the end of 2015 as a result of the implementation of these requirements. This agreement also fully settles the Alleged LDEQ Violations and stipulates that no further civil penalties over alleged past violations at the Cotton Valley or Princeton refineries will be pursued by the LDEQ. The capital investments required as a result of settlement of the Alleged LDEQ Violations are expected to include projects at one or more of our Louisiana refineries resulting in (i) nitrogen oxide and sulfur dioxide emission reductions from heaters and boilers and the application of New Source Performance Standards for sulfur recovery plants and flaring devices, (ii) control of incidents related to acid gas flaring, tail gas and hydrocarbon flaring, (iii) electrical reliability improvements to reduce flaring, (iv) flare refurbishment, (v) enhancement of the Benzene Waste National Emissions Standards for Hazardous Air Pollutants programs and the Leak Detection and Repair programs, and (vi) Title V audits and targeted audits of certain regulatory compliance programs. During negotiations with the LDEQ, we voluntarily initiated projects for certain of these requirements prior to our settlement with the LDEQ, and we currently anticipate completion of these projects over the next four years. These capital investment requirements will be incorporated into our annual capital expenditures budget and we do not expect any additional capital expenditures as a result of the required audits or required operational changes included in the settlement to have a material adverse effect on our financial results or operations. For additional information regarding the impact on our capital expenditures, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures.” The terms of this settlement agreement were deemed final and effective on January 31, 2012 upon concurrence of the Louisiana Attorney General.

Also, in connection with the Superior Acquisition, we became a party to an existing consent decree (“Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to our Superior refinery. Under the consent decree, we will have to complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the facility to the EPA and WDNR, and we currently estimate costs of approximately $4.1 million to make known equipment upgrades and conduct other discrete tasks in compliance with the Consent Decree. Failure to perform required tasks under the Consent Decree could result in the imposition of stipulated penalties, which could be significant. In addition, we may have to pursue certain additional environmental and safety-related projects at the Superior refinery including, but not limited to: (i) installing process equipment pursuant to applicable EPA fuel content regulations; (ii) purchasing emission credits on an interim basis until such time as any process equipment that may be required under the EPA fuel content regulations is installed and operational; (iii) performing monitoring and remediation of historical contamination at the facility; (iv) upgrading treatment equipment or possibly pursuing other remedies, as necessary, to satisfy new effluent discharge limits under a Clean Water Act permit renewal that is pending; and (v) pursuing various voluntary programs at the Superior refinery, including removing asbestos-containing materials or enhancing process safety or other maintenance practices. Completion of these additional projects would result in us incurring additional costs, which could be substantial. During 2011, we incurred approximately $2.3 million in costs related to installing process equipment pursuant to the fuel content regulations. We currently estimate costs for performing monitoring and remediation of historical contamination at the Superior refinery to be approximately $0.2 million per year.

The 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 Emissions

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. 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 U.S. states exhibiting lesser air quality problems. Similarly, the EPA promulgated regulations that limit the sulfur content of highway diesel beginning

in 2006 from its former level of 500 parts per million (“ppm”) to 15 ppm (the “ultra low sulfur standard”). The Shreveport and Superior refineries have implemented the sulfur standard with respect to produced gasoline and produces diesel meeting the ultra low sulfur standard. To the extent we exceed the minimum requirements of the MSAT II standards, we have the option to sell renewable fuel credits, also known as RINs credits and have the option to purchase RINs credits if we operate a refinery in a manner that does not meet these minimum requirements.

Pursuant to the Energy Act of 2005 and 2007, the EPA has issued Renewable Fuels Standards II (“RFS II”) that implement mandates to blend renewable fuels into the petroleum fuels produced at our refineries. Under the RFS II, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. In addition, we are required to meet the MSAT II regulations to reduce the benzene content of motor gasoline produced at our facilities. We have completed capital projects at our Shreveport and Superior refineries to comply with these fuel quality requirements.

Climate Change

In response to findings by the EPA in December 2009 that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires construction and operating permit reviews for GHG emissions from certain large stationary sources. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. Moreover, on December 23, 2010, EPA entered a settlement agreement with environmental groups requiring the agency to propose by December 15, 2011 GHG New Source Performance Standards for refineries and to finalize these rules by November 15, 2012. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis. These EPA policies and rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.

In addition, from time to time Congress has considered legislation to reduce emissions of GHG, and almost one-half of the states have already taken legal measures to reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHG or otherwise limits emissions of GHG from our equipment and operations could require us to incur costs to reduce emissions of GHG associated with our operations or could adversely affect demand for the refined petroleum products that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

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, as amended (“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 laws. 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. These 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. We incurred approximately $0.3 million and $0.5 million in 2011 and 2010, respectively, of such capital expenditures at our Cotton Valley refinery.

Water Discharges

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 oil 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 and similar state laws.

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.

Occupational Health and Safety

We are subject to various laws and regulations relating occupational health and safety, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws. These laws and 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, contractors, state and local government authorities and customers. We maintain safety and training programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. We have implemented an internal program of inspection designed to monitor and enforce compliance with worker safety requirements as well as a quality system that meets the requirements of the ISO-9001-2008 Standard. The integrity of our ISO-9001-2008 Standard certification is maintained through surveillance audits by our registrar at regular intervals designed to ensure adherence to the standards. Our compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.

We have completed studies to assess the adequacy of our process safety management practices at our Shreveport refinery with respect to certain consensus codes and standards. As of December 31, 2011, we have incurred approximately $4.1 million of capital expenditures and expect to incur between $1.0 million and $4.0 million of capital expenditures during 2012 and 2013 to address OSHA compliance issues identified in these studies. We expect these capital expenditures will enhance our equipment such that the equipment maintains compliance with applicable consensus codes and standards.

In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under OSHA’s National Emphasis Program. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to us as a result of our Cotton Valley inspection, which included a proposed penalty amount of $0.2 million. We have contested the Cotton Valley Citation and associated penalties and are currently in negotiations with OSHA to reach a settlement allowing an extended abatement period for a new refinery flare system study and for completion of facility site modifications, including relocation and hardening of structures. Notwithstanding the Cotton Valley Citation, we believe our total operations are in substantial compliance with OSHA and similar state laws.

Other Environmental and Maintenance 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.

In addition, we are indemnified by Murphy Oil for specified environmental liabilities including: (i) certain obligations arising out of the Consent Decree (including payment of a civil penalty required under the Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or discharged by Murphy Oil. We are also indemnified by Murphy Oil for two years following the Superior Acquisition for liabilities arising from breaches of certain environmental representations and warranties made by Murphy Oil, subject to a maximum liability of $22.0 million, for which we are required to contribute up to the first $6.6 million.

We perform preventive and normal maintenance on all of our refining and logistics assets and make repairs and replacements when necessary or appropriate. We also conduct inspections of these assets as required by law or regulation.

Insurance

Our operations are subject to certain hazards of operations, including fire, explosion and weather-related perils. We maintain insurance policies, including business interruption insurance for each of our facilities, with 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.

During the second quarter of 2011, we reached a final settlement of an insurance claim related to the failure of an environmental operating unit at our Shreveport refinery in 2010, resulting in a gain attributed to insurance recoveries of $8.7 million recorded for the year ended December 31, 2011. This claim related to both property damage and business interruption.

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 due to this seasonality.

Properties

We own and lease the properties listed below. The properties we own are pledged as collateral under our Collateral Trust Agreement as discussed in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities.” All properties are suitable for their intended purpose, are being efficiently utilized, and are believed to provide adequate capacity to meet demand for the next several years.


Property	Business Segment	Acres	Owned / Leased	Location
Shreveport refinery	Fuels and Specialty	240	Owned	Shreveport, Louisiana
Superior refinery and terminal	Fuels and Specialty	675	Owned	Superior, Wisconsin
Princeton refinery	Specialty	208	Owned	Princeton, Louisiana
Cotton Valley refinery	Specialty	77	Owned	Cotton Valley, Louisiana
Burnham terminal	Specialty	11	Owned	Burnham, Illinois
Karns City facility	Specialty	225	Owned	Karns City, Pennsylvania
Dickinson facility	Specialty	28	Owned	Dickinson, Texas
Rhinelander asphalt terminal	Specialty	18	Owned	Rhinelander, Wisconsin
Crookston asphalt terminal	Specialty	19	Owned	Crookston, Minnesota
Missouri facility	Specialty	22	Owned	Louisiana, Missouri
TruSouth facility	Specialty	10	Leased	Shreveport, Louisiana
Duluth terminal	Fuels	49	Owned	Proctor, Minnesota
Duluth marine terminal	Fuels	3	Leased	Duluth, Minnesota

In addition to the items listed above, we lease or own a number of storage tanks, pressure stations, railcars, equipment, land and precious metals.

Office Facilities

In addition to our refineries and terminals discussed above, we occupy approximately 32,800 square feet of office space in Indianapolis, Indiana and approximately 1,600 square feet of office space in El Dorado, Arkansas, both of which are under leases. 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 February 27, 2012, our general partner employs approximately 920 people who provide direct support to our operations. Of these employees, approximately 480 are covered by collective bargaining agreements. Employees at the Superior, Cotton Valley, Princeton and Dickinson facilities are covered by separate collective bargaining agreements with the International Union of Operating Engineers. The Superior and Princeton refineries’ collective bargaining agreements expire on July 1, 2012 and October 31, 2014, respectively. The Cotton Valley refinery’s and Dickinson facility’s collective bargaining agreements will both expire on March 31, 2013. Employees at the Shreveport refinery are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union which expires on April 30, 2013. The Karns City facility employees are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber Manufacturing, Energy, Allied Industrial and Service Workers International Union that will expire on January 31, 2015. None of the employees at the TruSouth or Missouri facilities or at the, Burnham, Rhinelander, Crookston or Duluth terminals 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 Parkway East Drive, Suite 200, Indianapolis, Indiana 46214 and our telephone number is (317) 328-5660. Our website is located at http://www.calumetspecialty.com.

We make the following information available free of charge on our website:

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Annual Report on Form 10-K;

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Quarterly Reports on Form 10-Q;

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Current Reports on Form 8-K;

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

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Charters for the Audit, Compensation and Conflicts Committees; and

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Code of Business Conduct and Ethics.

Our Securities and Exchange Commission (“SEC”) filings are available on our website as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. The above information is available to anyone who requests it and is free of charge either in print from our website or upon request by contacting investor relations using the contact information listed above.

Information on our website is not incorporated into this Annual Report or our other securities filings and is not a part of them.

Item 1A.

Risk Factors

Risks Relating 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:

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overall demand for specialty hydrocarbon products, fuel and other refined products;

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the level of foreign and domestic production of crude oil and refined products;

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our ability to produce fuel and specialty products that meet our customers’ unique and precise specifications;

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the marketing of alternative and competing products;

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the extent of government regulation;

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results of our hedging activities; and

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overall economic and local market conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

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the level of capital expenditures we make, including those for acquisitions, if any;

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our debt service requirements;

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fluctuations in our working capital needs;

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our ability to borrow funds and access capital markets;

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restrictions on distributions and on our ability to make working capital borrowings for distributions contained in our debt instruments; and

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the amount of cash reserves established by our general partner for the proper conduct of our business.

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 and for payments of our debt obligations.

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our specialty products prices and fuel products prices and the prices for crude oil and other feedstocks. The cost to acquire our feedstocks and the price at which we can ultimately sell our refined products depend upon numerous factors beyond our control.

A widely used benchmark in the fuel products industry to measure market values and margins is the “Gulf Coast 3/2/1 crack spread,” which represents the approximate gross margin resulting from refining crude oil, assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of heating oil. The Gulf Coast 3/2/1 crack spread ranged from a high of $39.60 per barrel to a low of $12.14 per barrel during 2011 and averaged $25.41 per barrel during 2011 compared to an average of $9.90 in 2010 and $8.68 in 2009.

Our actual refining margins vary from the Gulf Coast 3/2/1 crack spread due to the actual crude oil used and products produced, transportation costs, regional differences, and the timing of the purchase of the feedstock and sale of the refined products, but we use the Gulf Coast 3/2/1 crack spread as an indicator of the volatility and general levels of refining margins.

The prices at which we sell specialty products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our specialty products segment margins will fall unless we are able to pass along these price increases to our customers. Increases in selling prices for specialty products typically lag the rising cost of crude oil and may be difficult to implement when crude oil costs increase dramatically over a short period of time. For example, in the first six months of 2008, excluding the effects of hedges, we experienced a 31.3% increase in the cost of crude oil per barrel as compared to an 18.3% increase in the average sales price per barrel of our specialty products. It is possible we may not be able to pass on all or any portion of increased crude oil costs to our customers. In addition, we are not able to completely eliminate our commodity risk through our hedging activities.

Because refining margins are volatile, unitholders should not assume that our current margins will be sustained. If our refining margins fall, it will adversely affect the amount of cash we will have available for distribution to our unitholders.

Our hedging activities may not be effective in reducing the volatility of our cash flows and may reduce our earnings, profitability and cash flows.

We are exposed to fluctuations in the price of crude oil, fuel products, natural gas and interest rates. From time to time, we utilize derivative financial instruments related to the future price of crude oil, natural gas and fuel products with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices. We utilize derivative instruments related to interest rates for future periods with the intent of reducing volatility in our cash flows due to fluctuations in interest rates. We are not able to enter into derivative financial instruments to reduce the volatility of the prices of the specialty products we sell as there is no established derivative market for such products.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. The derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual crude oil prices, natural gas prices or fuel products prices that we incur or realize in our operations. For example, all of the crude oil derivatives in our hedge portfolio are based on the market price of NYMEX WTI and the fuel products derivatives are all based on U.S. Gulf Coast market prices. In recent periods, the spread between NYMEX WTI and other crude oil indices (specifically Light Louisiana Sweet (“LLS”) and Brent, on which a portion of our crude oil purchases are priced) has widened, which has reduced the effectiveness of certain crude oil hedges. Accordingly, our commodity price risk management policy may not protect us from significant and sustained increases in crude oil or natural gas prices or decreases in fuel products prices. Conversely, our policy may limit our ability to realize cash flows from crude oil and natural gas price decreases.

We have a policy to enter into derivative transactions related to only a portion of the volume of our expected purchase and sales requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion of our expected purchase and sales requirements. For example, during 2010 we entered into monthly crude oil collars and swaps to hedge up to approximately 11,000 bpd of crude oil purchases related to our specialty products segment, which had average total daily production for 2010 of approximately 32,000 bpd. During 2011, we had significantly reduced the volume and duration of our crude oil collars and derivative instruments and hedged approximately 3,100 bpd of crude oil purchases through March 31, 2011. Thus, we could be exposed to significant crude oil cost increases on a portion of our purchases. Please read Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk.”

Our actual future purchase and sales requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we

will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which may result in a substantial diminution of our liquidity. As a result, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligations under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Our financing arrangements contain operating and financial provisions that restrict our business and financing activities.

The operating and financial restrictions and covenants in our financing arrangements, including our revolving credit facility, indentures governing the 2019 Notes and master derivative contracts do currently restrict, and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities, including restrictions on our ability to, among other things:

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sell assets, including equity interests in our subsidiaries;

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pay distributions or redeem or repurchase our units or repurchase our subordinated debt;

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incur or guarantee additional indebtedness or issue preferred units;

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create or incur certain liens;

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make certain acquisitions and investments;

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redeem or repay other debt or make other restricted payments;

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enter into transactions with affiliates;

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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

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create unrestricted subsidiaries;

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enter into sale and leaseback transactions;

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enter into a merger, consolidation or transfer or sale of assets, including equity interests in our subsidiaries; and

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engage in certain business activities.

In addition, our revolving credit facility contains covenants regarding collateral maintenance and insurance maintenance and a springing financial covenant that provides that under certain circumstances we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0.

Our ability to comply with the covenants and restrictions contained in our financing arrangements may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with, the covenants, ratios or tests in our financing arrangements or any future indebtedness could result in an event of default under these financing arrangements, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In the event of any default on our indebtedness, among other things, our debt holders and lenders could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable.

If our existing indebtedness were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are secured by substantially all of our accounts receivable, inventory and certain related assets and our obligations under our master derivative contracts, including in respect of physical delivery arrangements pursuant thereto, are secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property and certain other non-working capital assets, and if we are unable to repay our indebtedness under the revolving credit facility or master derivative contracts, the lenders or derivative counterparties could seek to foreclose on these assets. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information regarding our long-term debt.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

We had approximately $600.8 million of outstanding indebtedness as of December 31, 2011 and availability for borrowings of $340.8 million under our senior secured revolving credit facility. We continue to have the ability to incur additional debt, including the ability to borrow up to an aggregate principal amount of $850.0 million at any time outstanding, subject to borrowing base limitations, under our senior secured revolving credit facility. Our level of indebtedness could have important consequences to us, including the following:

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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;

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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;

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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 payments of our debt obligations, including the 2019 Notes; and

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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 to our unitholders, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to accomplish any of these remedies on satisfactory terms, or at all. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information regarding our indebtedness.

Decreases in the price of crude oil may lead to a reduction in the borrowing base under our revolving credit facility and our ability to issue letters of credit or the requirement that we post substantial amounts of cash collateral for derivative instruments, which could adversely affect our liquidity, financial condition and our ability to distribute cash to our unitholders.

We rely on borrowings and letters of credit under our revolving credit agreement to purchase crude oil for our refineries, lease certain precious metals for use in our refinery operations and enter into cash flow hedges of crude oil and natural gas purchases and fuel products sales. We also rely on our ability to issue letters of credit to enter into certain hedging arrangements in an effort to reduce our exposure to adverse fluctuations in the prices of

crude oil, natural gas and crack spreads. The borrowing base under our revolving credit facility is determined weekly or monthly depending upon availability levels or the existence of a default or event of default. Reductions in the value of our inventories as a result of lower crude oil prices could result in a reduction in our borrowing base, which would reduce the amount of financial resources available to meet our capital requirements. If, under certain circumstances, our available capacity under our revolving credit facility falls below certain threshold amounts, or a default or event of default exists, then our cash balances in a dominion account established with the administrative agent will be applied on a daily basis to our outstanding obligations under our revolving credit facility. In addition, decreases in the price of crude oil may require us to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our derivative instruments. If, due to our financial condition or other reasons, the borrowing base under our revolving credit facility decreases, we are limited in our ability to issue letters of credit or we are required to post substantial amounts of cash collateral to our hedging counterparties, our liquidity, financial condition and our ability to distribute cash to our unitholders could be materially and adversely affected. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information.

We depend on certain key crude oil and other feedstock suppliers for a significant portion of our supply of crude oil and other feedstocks, and the loss of any of these key suppliers or a material decrease in the supply of crude oil and other feedstocks generally available to our refineries could materially reduce our ability to make distributions to unitholders.

We purchase crude oil and other feedstocks from major oil companies as well as from various crude oil gatherers and marketers in east Texas, north Louisiana, North Dakota and Canada. In 2011, subsidiaries of Plains supplied us with approximately 49.7% of our total crude oil supplies under term contracts and month-to-month evergreen crude oil supply contracts and 4.5% of our total crude oil purchases in 2011 were from Legacy Resources, an affiliate of our general partner, to supply crude oil to our Princeton and Shreveport refineries. Commencing November 1, 2011, BP began supplying the Superior, Wisconsin refinery with approximately 75% of its daily crude oil requirements. Total crude oil requirements for the Superior refinery are estimated to be between 35,000 and 45,000 bpd. In addition, the Superior refinery receives up to 10,000 bpd of crude oil under the Murphy Crude Oil Supply Agreement. Each of our refineries is dependent on one or more of these suppliers and the loss of any of these suppliers would adversely affect our financial results to the extent we were unable to find another supplier of this substantial amount of crude oil. We do not maintain long-term contracts with most of our suppliers. For example, our contracts with Plains are currently month-to-month and terminable upon 90 days’ notice and our contract with BP has an initial term of seven months ending April 30, 2012, will automatically renew for successive one-year terms unless terminated by either party upon 90 days’ notice.

Since terminating our crude oil supply agreements with Legacy Resources, effective May 31, 2011, we have purchased all the crude oil supply for the Princeton refinery and Shreveport refinery directly from third-party suppliers, under month-to-month evergreen supply contracts and on the spot market. These evergreen contracts are generally terminable upon 30 days notice and purchases on the spot market may expose us to changes in commodity prices. For additional discussion regarding our crude oil and feedstock supply, please read Items 1 and 2 “Business and Properties — Our Crude Oil and Feedstock Supply.”

To the extent that our suppliers reduce the volumes of crude oil and other feedstocks that they supply us as a result of declining production or competition or otherwise, our revenues, net income and cash available for distribution to unitholders and payments of our debt obligations would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks on comparable terms from other suppliers, which may not be possible in areas where the supplier that reduces its volumes is the primary supplier in the area. 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. A material

decrease in either the crude oil production from or the drilling activity in the fields that supply our refineries, as a result of depressed commodity prices, natural production declines, governmental moratoriums on drilling or production activities, the availability and the cost of capital or otherwise, could result in a decline in the volume of crude oil we refine.

We are dependent on certain third-party pipelines for transportation of crude oil and refined products, and if these pipelines become unavailable to us, our revenues and cash available for distributions to our unitholders and payment of our debt obligations could decline.

Our Shreveport refinery is interconnected to pipelines that supply most of its crude oil and ship a portion of its refined fuel products to customers, such as pipelines operated by subsidiaries of Enterprise Products Partners L.P. and ExxonMobil. Our Superior refinery receives crude oil though the Enbridge pipeline system and the Superior wholesale business transports products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. In addition, any of these third-party pipelines could become unavailable to transport crude oil or our refined fuel products because of acts of God, accidents, government regulation, terrorism or other events. For example, our refinery run rates were affected by an approximately three-week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period. If any of these third-party pipelines become unavailable to transport crude oil or our refined fuel products because of acts of God, accidents, government regulation, terrorism or other events, our revenues, net income and cash available for distributions to our unitholders and payments of our debt obligations could decline.

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 for natural gas as reported on the New York Mercantile Exchange (“NYMEX”) ranged between $2.99 and $4.85 per million British thermal unit, or MMBtu, in 2011 and between $3.29 and $6.01 per MMBtu in 2010. 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 19.6% and 21.6% of our total operating expenses included in cost of sales for the years ended December 31, 2011 and 2010, respectively. If our natural gas costs rise, it will adversely affect the amount of cash we will have available for distribution to our unitholders.

Our refineries, terminals and related facility operations face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.

Our crude oil and specialty hydrocarbon refineries, terminals and related facility operations are subject to certain operating hazards, and our cash flow from those operations could decline if any of our facilities experiences a major accident, explosion or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. For example, on February 5, 2010, our Shreveport refinery experienced an explosion that caused us to shut down one of this refinery’s environmental operating units until August 2010 when it was replaced with a newly constructed unit, resulting in modified operations during the interim period, including lower throughput rates at certain times during this period. These operating hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in significant curtailment or suspension of our related operations.

Although we maintain insurance policies, including personal and property damage and business interruption insurance for each of our facilities 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 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 significant interruption of operations. Our business interruption insurance will not apply unless a business interruption exceeds 90 days. 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. In addition, we are not fully insured against all risks incident to our business because certain risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures. For example, we are not insured for environmental accidents at all of our facilities. If we were to incur a significant liability for which we were not fully insured, it could diminish our ability to make distributions to our unitholders.

Our business subjects us to the inherent risk of incurring significant environmental costs and liabilities in the operation of our refineries, terminals and related facilities.

There is inherent risk of incurring significant environmental costs and liabilities in the operation of our crude oil and specialty hydrocarbon refineries, terminals, and related facilities due to our handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to our operations, and as a result of historical operations and waste disposal practices of prior owners of our facilities. We currently own or operate properties that for many years have been used for industrial activities, including refining or terminal storage operations, sometimes by third parties over whom we had no control with respect to their operations or waste disposal activities. Petroleum hydrocarbons or wastes have been released on, under or from 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. 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. 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. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition, and results of operations.

We are subject to compliance with stringent environmental and occupational health and safety laws and regulations that may expose us to substantial costs and liabilities.

Our crude oil and specialty hydrocarbon refining, terminal and related facility operations are subject to stringent and complex federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose numerous obligations that are applicable to our operations, including the obligation to obtain permits to conduct regulated activities, the incurrence of significant capital expenditures for air pollution control equipment or otherwise limit or prevent releases of pollutants from our refineries, terminal, and related facilities, the expenditure of significant monies in the application of specific health and safety criteria addressing worker protection, the requirement to maintain information about hazardous materials used or produced in our operations and to provide this information to employees, state and local government authorities, and local residents and the incurrence of substantial costs and liabilities for pollution resulting from our operations or from those of prior owners of our facilities. Numerous governmental authorities, such as the EPA, OSHA, and state agencies, such as the LDEQ and WDNR, 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 these 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. On occasion, we receive notices of violation, enforcement proceedings and regulatory inquiries from governmental agencies alleging non-compliance with applicable environmental and occupational health and safety laws and regulations. Please read Items 1 and 2 “Business and Properties — Environmental and Occupational Health and Safety Matters” for additional information regarding our communications with the LDEQ and OSHA.

Downtime for maintenance at our refineries and facilities will reduce our revenues and cash available for distributions to our unitholders and payments of our debt obligations.

Our refineries and facilities consist of many processing units, a number of which have been in operation for a long time. One or more of the units may require additional unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for each unit every one to five years. Scheduled and unscheduled maintenance reduce our revenues and increase our operating expenses during the period of time that our processing units are not operating and could reduce our ability to make distributions to our unitholders.

If we do not successfully execute our growth through acquisitions, our future growth and ability to increase distributions to our unitholders 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 consummate acquisitions on favorable terms, (3) unable to obtain financing for these acquisitions on economically acceptable terms, or (4) outbid by competitors, then our future growth and ability to increase distributions to our unitholders will be limited. Furthermore, any acquisition, including our recent acquisition of the Superior Business, involves potential risks, including, among other things:

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performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;

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a significant increase in our indebtedness and working capital requirements;

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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;

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the incurrence of substantial seen or unforeseen environmental and other liabilities arising out of the acquired businesses or assets;

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the diversion of management’s attention from other business concerns;

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customer or key employee losses at the acquired businesses; and

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significant changes in our capitalization and results of operations.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

Our asset reconfiguration and enhancement initiatives may not result in revenue or cash flow increases, may be subject to significant cost overruns and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our business, operating results, cash flows and financial condition.

Historically we have grown our business in part through the reconfiguration and enhancement of our existing refinery assets. As a specific example, we completed an expansion project at our Shreveport refinery to increase throughput capacity and crude oil processing flexibility in May 2008. This expansion project and the

construction of other additions or modifications to our existing refineries have and will continue to involve numerous regulatory, environmental, political, legal, labor and economic uncertainties beyond our control, which could cause delays in construction or require the expenditure of significant amounts of capital, which we may finance with additional indebtedness or by issuing additional equity securities. Our forecasted internal rates of return on such projects are also based on our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, available alternative supply and customer demand. For example, the total cost of the Shreveport refinery expansion project completed in 2008 was approximately $375.0 million and was significantly over budget due primarily to increased construction labor costs. Future reconfiguration and enhancement projects may not be completed at the budgeted cost, on schedule, or at all due to the risks described above which could significantly affect our cash flows and financial condition.

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 and payments of our debt obligations could be reduced.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.

Distributions to unitholders and payments of our debt obligations 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 could reduce their demand for our specialty products. Our specialty products customers are primarily in the industrial goods, consumer goods and automotive goods industries and we are therefore susceptible to overall economic conditions, which may change 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 and payments of our debt obligations.

Distributions to unitholders and payments of our debt obligations 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 and payments of our debt obligations. Factors that could lead to a decrease in market demand include:

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

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

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

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

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competitor actions; and

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availability of raw materials.

We depend on unionized labor for the operation of our facilities. Any work stoppages or labor disturbances at these facilities could disrupt our business.

Substantially all of our operating personnel at our Princeton, Cotton Valley, Shreveport, Superior, Karns City and Dickinson facilities are employed under collective bargaining agreements that expire in October 2014, March 2013, April 2013, July 2012, January 2015 and March 2013, respectively. Our inability to renegotiate these agreements as they expire, any work stoppages or other labor disturbances at these facilities could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. In addition, employees who are not currently represented by labor unions may seek union representation in the future, and any renegotiation of current collective bargaining agreements may result in terms that are less favorable to us.

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 operating results for our fuel products segment and the asphalt we produce and sell are seasonal and generally lower in the first and fourth quarters of the year.

The operating results for the fuel products segment and the selling prices of asphalt products we produce can be seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters due to the seasonality of road construction. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months. Our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year as a result of this seasonality.

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 primarily on sales generated from products processed at the facilities we own. Furthermore, the majority of our assets and operations are located in northwest Louisiana and northwest Wisconsin. 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 and feedstocks and/or decreased demand for refined petroleum products, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets in more diverse locations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and a decreased demand for our refining services.

Based on findings by the EPA in December 2009 that emissions of carbon dioxide, methane and other greenhouse gases, or “GHG,” present an endangerment to public health and the environment, the EPA has adopted regulations restricting emissions of GHG under existing provisions of the Clean Air Act including one that limits emissions of GHG from motor vehicles and another that requires construction and operating permit reviews for GHG emissions from certain large stationary sources. The EPA has also adopted rules requiring the annual monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, including refineries. In addition Congress has from time to time considered legislation to reduce emissions of GHG, and almost one-half of the states have already taken legal measures to reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHG or otherwise limits emissions of GHG from our equipment and operations could require us to incur increased operating costs and could adversely affect demand for the refined petroleum products we produce.

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 and payments of our debt obligations.

The recent adoption of financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), which requires the Commodity Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. The Act may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities, although the application of those provisions to us is uncertain at this time. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative instruments (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative instruments, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. An increase in the cost of derivatives contracts would affect our results of operations and cash flow available for distribution to our unitholders and payments of our debt obligations. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make distributions to our unitholders and payments of our debt obligations. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower

commodity prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.

We depend on key personnel for the success of our business and the loss of those persons could adversely affect our business and our ability to make distributions to our unitholders.

The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available. Except with respect to Mr. Grube, neither we, our general partner nor any affiliate thereof has entered into an employment agreement with any member of our senior management team or other key personnel. Furthermore, we do not maintain any key-man life insurance.

An increase in interest rates will cause our debt service obligations to increase.

Borrowings under our revolving credit facility bear interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of December 31, 2011, there were no borrowings outstanding under our revolving credit facility. The interest rate is subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) or prime rate, as applicable. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow available for distribution to our unitholders. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

A change of control could result in us facing substantial repayment obligations under our revolving credit agreement, our 2019 Notes and our Collateral Trust Agreement.

Certain events relating to a change of control of our general partner, our partnership and our operating subsidiaries would constitute an event of default under our revolving credit agreement and the indentures governing our 2019 Notes. In addition, an event of default under our revolving credit agreement would constitute an event of default under the Collateral Trust Agreement that secures our obligations under our master derivatives contracts and the BP Purchase Agreement. As a result, upon a change of control event, we may be required immediately to repay the outstanding principal, any accrued interest on and any other amounts owed by us under our revolving credit facility and the 2019 Notes and the outstanding payment obligations under our master derivatives contracts and the BP Purchase Agreement. The source of funds for these repayments would be our available cash or cash generated from other sources and there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness and other payment obligations in full. In addition, our obligations under our revolving credit facility are secured by substantially all of our accounts receivable, inventory and certain related assets and our obligations under our master derivatives contracts and the BP Purchase Agreement are secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property and certain other non-working capital assets. If we are unable to repay our indebtedness under the revolving credit facility, the payment obligations under our master derivative contracts or the payment obligations under the BP Purchase Agreement or obtain waivers of such defaults, then the lenders under our revolving credit facility, the derivative counterparties under our master derivative contracts and BP would have the right to foreclose on those assets, which would have a material adverse effect on us. There is no restriction in our partnership agreement on the ability of our general partner to enter into a transaction which would trigger the change of control provisions of our revolving credit facility agreement or the indentures governing our 2019 Notes.

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 derivative instruments. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we

may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could reduce our ability to make distributions to our unitholders and payments of our debt obligations.

Risks Inherent in an Investment in Us

The families of our chairman, chief executive officer and vice chairman, The Heritage Group and certain of their affiliates own a 37.6% limited partner interest in us and own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to other unitholders’ detriment.

The families of our chairman, chief executive officer and vice chairman, the Heritage Group, and certain of their affiliates own a 37.6% limited partner interest in us. In addition, The Heritage Group and the families of our chairman and chief executive officer and vice chairman 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:

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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;

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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 Delaware law;

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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;

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

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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 available for distribution to our unitholders and payments of our debt obligations;

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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 incentive distribution rights; and

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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 incentive distributions.

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

Pursuant to the omnibus agreement we entered into in connection with our initial public offering, The Heritage Group and its controlled affiliates have agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental United States for so long as it controls us. This restriction does not apply to certain assets and businesses which are more fully described under Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — Omnibus Agreement.”

Although Mr. Grube is prohibited from competing with us pursuant to the terms of his employment agreement, the owners of our general partner, other than The Heritage Group, are not prohibited from competing with us.

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:

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Permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment of our partnership agreement;

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Provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

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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

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Provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.

In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our general partner or its board of directors, and have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

The unitholders are unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding units voting together as a single class is required to remove the general partner. At February 27, 2012, the owners of our general partner and certain of their affiliates own 37.6% of our common units.

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 and payments of our debt obligations could be reduced.

We may issue additional common units without unitholder approval, which would dilute our current unitholders’ existing ownership interests.

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. 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;

•

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.

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.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets and our ability to distribute cash to our unitholders and make payments of our debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the equity interests in our subsidiaries. As a result, our ability to distribute cash to our unitholders and payments of debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our revolving credit facility and applicable state laws and other laws and regulations. If we are unable to obtain the funds necessary to distribute cash to our unitholders or make payments of debt obligations, we may be required to adopt one or more alternatives, such as a refinancing of our indebtedness or incurring borrowings under our revolving credit facility. We cannot assure unitholders that we would be able to refinance our indebtedness or that the terms on which we could refinance our indebtedness would be favorable.

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to unitholders and payments of our debt obligations.

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 and payments of our debt obligations. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence.”

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the issued and outstanding common units, our general partner will have the right, but not the obligation, which right it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units to our general partner, its affiliates or us at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. At February 27, 2012, our general partner and its affiliates own approximately 37.6% of the common units.

Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership

have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as if they were a general partner if:

•

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•

unitholders’ right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

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

Our common units have a low trading volume compared to other units representing limited partner interests.

Our common units are traded publicly on the NASDAQ Global Select Market under the symbol “CLMT.” However, our common units have a low average daily trading volume compared to many other units representing limited partner interests quoted on the NASDAQ Global Select Market. The price of our common units may continue to be volatile.

The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

•

our quarterly distributions;

•

our quarterly or annual earnings or those of other companies in our industry;

•

changes in commodity prices or refining margins;

•

loss of a large customer;

•

announcements by us or our competitors of significant contracts or acquisitions;

•

changes in accounting standards, policies, guidance, interpretations or principles;

•

general economic conditions;

•

the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

•

future sales of our common units; and

•

the other factors described in Item 1A “Risk Factors” of this Annual Report.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation for U.S. federal income tax purposes or we become subject to additional amounts of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to common unitholders.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for U.S. federal income tax purposes unless it satisfies a “qualifying income” exception.

Failing to meet the qualifying income requirement or a change in current law may cause us to be treated as a corporation for federal income tax purposes. If we were subject to federal income tax as a corporation, our cash available to pay distributions would be reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, then our cash available for distribution would be substantially reduced.

Future changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce our cash available for distribution to our unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, then quarterly distributions may be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with 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, the costs of any contest with the IRS will be borne indirectly by our unitholders 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 are treated as partners in us for U.S. federal income tax purposes we allocate a share of our taxable income to our unitholders which could be different in amount than the cash we distribute, and our unitholders may be required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us.

Tax gain or loss on disposition of common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount they realized and their tax basis in those common units. Because distributions in excess of their allocable shares of our total net taxable income result in a reduction in their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to our unitholders if they sell their units at a price greater than their tax basis in those common units, even if the price they receive is equal to their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if unitholders sell their units they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments in our common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as “IRAs”), and non-U.S. persons raise issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. These positions may result in an understatement of deductions and an overstatement of income to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units may be entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not allocate any subsequent holder of a unit any such amortization deduction. This approach may understate deductions available to those unitholders who own those units and may result in those unitholders reporting that they have a higher tax basis in their units than would be the case if the IRS strictly applied Treasury Regulations relating to these depreciation or amortization adjustments. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than would be the case if the IRS strictly applied those Treasury Regulations.

The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Section 743(b). If so, because the specific unitholders to which this issue relates cannot be identified, the IRS may assert adjustments to all unitholders selling units within the period under audit. A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder’s sale of common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. Consequently, a successful IRS challenge could have a negative impact on the value of our common units.

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 customers 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 obligated to pay corporate income taxes, which reduce the corporation’s 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 were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

We prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who purchase units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who purchase our units based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

If a unitholder loans units to a “short seller” to cover a short sale of units, they may be considered as having disposed of the loaned units, and may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from such disposition. During the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by a unitholder and any cash distributions received as to those units may be fully taxable as ordinary income. To assure unitholder status as a partner and avoid the risk of gain recognition from a loan to a short seller unitholders are urged to modify any applicable brokerage account agreements to prohibit brokers from borrowing their units.

We have adopted certain valuation methodologies for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange within a twelve-month period of 50% or more of the total interests in our capital and profits. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one calendar year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has constructively terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs.

Unitholders may be subject to state, local and non-U.S. taxes and return filing requirements.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, non-U.S. 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 unitholders will likely be required to file tax returns and pay taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We do business in 38 states. The states we operate in, with the exception of Texas and Florida, currently impose 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 required U.S. federal, state, local and non-U.S. tax returns.

The risks described in this Annual Report are not the only risks facing the Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Item 1B.

Unresolved Staff Comments

None.

Item 3.

Legal Proceedings

We are not a party to, and our property is not the subject of, any pending legal proceedings other than ordinary routine litigation incidental to our business. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. Please see Items 1 and 2 “Business and Properties — Environmental and Occupational Health and Safety Matters” for a description of our current

regulatory matters related to the environment, health and safety. Additionally, the information provided under Note 6 “Commitments and Contingencies” in Part II, Item 8 “Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements” is incorporated herein by reference.

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

Item 5.

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

Market Information

Our common units are quoted and traded on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “CLMT.” The following table shows the low and high sales prices per common unit, as reported by NASDAQ, for the periods indicated. Cash distributions presented below represent amounts declared subsequent to each respective quarter end based on the results of that quarter. For all periods, identical cash distributions per unit were paid among all outstanding common and subordinated units. All subordinated units converted to common units on February 16, 2011.


	Low		High		Cash Distribution per Unit (1)
2010:
First quarter	$	17.75	$	21.31	$	0.455
Second quarter	$	14.00	$	23.93	$	0.455
Third quarter	$	16.20	$	19.89	$	0.46
Fourth quarter	$	19.39	$	22.23	$	0.47
2011:
First quarter	$	19.81	$	24.95	$	0.475
Second quarter	$	20.00	$	23.75	$	0.495
Third quarter	$	16.05	$	23.95	$	0.50
Fourth quarter	$	15.99	$	20.17	$	0.53

(1)

We also paid cash distributions to our general partner with respect to its 2% general partner interest and, to the extent distributions exceeded $0.495 per unit, its incentive distribution rights, as described below in “Cash Distribution Policy — General Partner Interest and Incentive Distribution Rights.”

As of February 27, 2012, there were approximately 26 unitholders of record of our common units. The actual number of unitholders is greater than the number of holders of record. As of February 27, 2012, there were 51,529,778 common units outstanding. The number of common units outstanding on this date includes 13,066,000 common units that converted from subordinated units on February 16, 2011. The last reported sale price of our common units by NASDAQ on February 27, 2012 was $23.94.

Cash Distribution Policy

General. Within 45 days after the end of each quarter, we distribute our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date.

Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of the quarter:

•

less the amount of cash reserves established by our general partner to:

•

provide for the proper conduct of our business;

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.

•

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Intent to Distribute the Minimum Quarterly Distribution. We distribute to the holders of common units on a quarterly basis at least the minimum quarterly distribution of $0.45 per unit, or $1.80 in aggregate 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 exists, under our debt instruments, including our credit agreement and the indentures governing our 2019 Notes. 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 debt instruments that restrict our ability to make distributions. On February 14, 2012, we paid a quarterly cash distribution of $0.53 per unit on all outstanding units totaling approximately $28.2 million for the quarter ended December 31, 2011 to all unitholders of record as of the close of business on February 3, 2012.

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 1,051,628 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 in our partnership agreement) in excess of $0.495 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. Our general partner did not earn incentive distribution rights during the year ended December 31, 2010. Our general partner earned incentive distribution rights of approximately $0.3 million during the year ended December 31, 2011.

Conversion of Subordinated Units. In February 2011, we satisfied the last of the earnings and distribution tests contained in our partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution paid on February 14, 2011. Two days following this quarterly distribution to unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.

Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:


	Total Quarterly Distribution Target Amount Per Common Unit	Marginal Percentage Interest in Distributions
		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	%

Equity Compensation Plans

The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this Item 5 is incorporated by reference into Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” of this Annual Report.

Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

Item 6.

Selected Financial Data

The following table shows selected historical consolidated financial and operating data of the Company. The selected historical consolidated financial data as of and after December 31, 2008 and December 31, 2011, includes the operations acquired as part of the acquisitions of Penreco and the Superior Acquisition from their dates of acquisition, January 3, 2008 and September 30, 2011, respectively.

The following table includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income and net cash provided by 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 the information should be read together with, and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in Item 8 “Financial Statements and Supplementary Data” except for operating data, such as sales volume, feedstock runs and facility production. The following table also should be read together with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,
	2011			2010			2009			2008			2007
	(In thousands, except unit, per unit and operating data)
Summary of Operations Data:
Sales	$	3,134,923		$	2,190,752		$	1,846,600		$	2,488,994		$	1,637,848
Cost of sales		2,860,793			1,992,003			1,673,498			2,235,111			1,456,492

Gross profit		274,130			198,749			173,102			253,883			181,356

Operating costs and expenses:
Selling, general and administrative		50,836			35,224			32,570			34,267			19,614
Transportation		94,187			85,471			67,967			84,702			54,026
Taxes other than income taxes		5,661			4,601			3,839			4,598			3,662
Insurance recoveries		(8,698	)		—			—			—			—
Other		6,852			1,963			1,366			1,576			2,854

Operating income		125,292			71,490			67,360			128,740			101,200

Other income (expense):
Interest expense		(48,747	)		(30,497	)		(33,573	)		(33,938	)		(4,717	)
Interest income		263			70			170			388			1,944
Debt extinguishment costs		(15,130	)		—			—			(898	)		(352	)
Realized gain (loss) on derivative instruments		(7,909	)		(7,704	)		8,342			(58,833	)		(12,484	)
Unrealized gain (loss) on derivative instruments		(10,383	)		(15,843	)		23,736			3,454			(1,297	)
Gain on sale of mineral rights		—			—			—			5,770			—
Other		579			(217	)		(4,099	)		11			(919	)

Total other expense		(81,327	)		(54,191	)		(5,424	)		(84,046	)		(17,825	)

Income before income taxes		43,965			17,299			61,936			44,694			83,375
Income tax expense		929			598			151			257			501

Net income	$	43,036		$	16,701		$	61,785		$	44,437		$	82,874


	Year Ended December 31,
	2011			2010			2009			2008			2007
	(In thousands, except unit, per unit and operating data)
Weighted average limited partner units outstanding:
Basic		42,599,000			35,334,720			32,372,000			32,232,000			29,744,000
Diluted		42,644,000			35,351,020			32,372,000			32,232,000			29,746,000
Limited partners’ interest basic and diluted net income per unit	$	0.98		$	0.46		$	1.87		$	1.35		$	2.61
Cash distributions declared per limited partner unit	$	2.00		$	1.84		$	1.81		$	1.98		$	2.43
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	842,101		$	612,433		$	629,275		$	659,684		$	442,882
Total assets		1,732,058			1,016,672			1,031,856			1,081,062			678,857
Accounts payable		313,326			174,715			109,976			93,855			167,977
Long-term debt		587,090			369,275			401,058			465,091			39,891
Total partners’ capital		728,900			398,279			485,347			473,212			399,644
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	63,778		$	134,143		$	100,854		$	130,341		$	167,546
Investing activities		(460,424	)		(34,759	)		(22,714	)		(480,461	)		(260,875	)
Financing activities		396,673			(99,396	)		(78,139	)		350,133			12,409
Other Financial Data:
EBITDA	$	170,851		$	108,083		$	157,244		$	135,396		$	102,601
Adjusted EBITDA		211,020			138,462			151,117			126,534			109,399
Distributable Cash Flow		127,158			76,202			98,667			78,153			90,039
Operating Data (bpd):
Total sales volume (1)		66,134			55,668			57,086			56,232			47,663
Total feedstock runs (2)		69,295			55,957			60,081			56,243			48,354
Total facility production (3)		70,909			57,314			58,792			55,330			47,736

(1)

(2)	Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our facilities and certain third-party facilities pursuant to supply and/or processing agreements.

(3)

Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, including such agreements with LyondellBasell. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.

Non-GAAP Financial Measures

We include in this Annual Report the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow, and provide reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income and net cash provided by operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.

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

•

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

•

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

•

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

•

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

We believe that these non-GAAP measures are useful to analysts and investors as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully trend and analyze the performance of our core cash operations.

We define EBITDA for any period as net income (loss) plus interest expense (including debt issuance and extinguishment costs), income taxes and depreciation and amortization.

We define Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.

We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement capital expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash interest expense) and income tax expense. Distributable Cash Flow is used by us and our investors to analyze our ability to pay distributions.

The definitions of Adjusted EBITDA and Distributable Cash Flow that are presented in this Annual Report have been updated to reflect the calculation of “Consolidated Cash Flow” contained in the indentures governing our 2019 Notes (as defined in this Annual Report). We are required to report Consolidated Cash Flow to the holders of our 2019 Notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these measures are used by them to determine our compliance with certain covenants governing those debt instruments. Adjusted EBITDA and Distributable Cash Flow that are presented in this Annual Report for prior periods have been updated to reflect the use of the new calculations. Please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional details regarding the covenants governing our debt instruments.

EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income (loss), operating income (loss), net cash provided by (used in) operating activities or any other measure of financial performance presented in accordance with GAAP. In evaluating our performance as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the limitations of these measurements. EBITDA, Adjusted EBITDA and Distributable Cash Flow do not reflect our obligations

for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only three of the measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the same manner. The following tables present a reconciliation of both net income to EBITDA, Adjusted EBITDA and Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.


	Year Ended December 31,
	2011		2010		2009			2008			2007
	(In thousands)
Reconciliation of Net income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income	$	43,036	$	16,701	$	61,785		$	44,437		$	82,874
Add:
Interest expense		48,747		30,497		33,573			33,938			4,717
Debt extinguishment costs		15,130		—		—			898			352
Depreciation and amortization		63,009		60,287		61,735			55,866			14,157
Income tax expense		929		598		151			257			501

EBITDA	$	170,851	$	108,083	$	157,244		$	135,396		$	102,601

Add:
Unrealized (gain) loss on derivatives	$	10,383	$	15,843	$	(23,736	)	$	(3,454	)	$	1,297
Realized gain (loss) on derivatives, not included in net income		10,996		2,990		9,278			(8,055	)		2,190
Amortization of turnaround costs		11,384		10,006		7,256			2,468			3,190
Non-cash equity based compensation and other non-cash items		7,406		1,540		1,075			179			121

Adjusted EBITDA	$	211,020	$	138,462	$	151,117		$	126,534		$	109,399

Less:
Replacement capital expenditures (1)		23,862		24,345		15,508			6,304			12,175
Cash interest expense (2)		45,019		26,633		29,901			30,543			4,289
Turnaround costs		14,052		10,684		6,890			11,277			2,395
Income tax expense		929		598		151			257			501

Distributable Cash Flow	$	127,158	$	76,202	$	98,667		$	78,153		$	90,039

(1)	Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs.

(2)	Represents consolidated interest expense less non-cash interest expense.


	Year Ended December 31,
	2011			2010			2009			2008			2007
	(In thousands)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by operating activities:
Distributable Cash Flow	$	127,158		$	76,202		$	98,667		$	78,153		$	90,039
Add:
Replacement capital expenditures (1)		23,862			24,345			15,508			6,304			12,175
Cash interest expense (2)		45,019			26,633			29,901			30,543			4,289
Turnaround costs		14,052			10,684			6,890			11,277			2,395
Income tax expense		929			598			151			257			501

Adjusted EBITDA	$	211,020		$	138,462		$	151,117		$	126,534		$	109,399

Less:
Unrealized (gain) loss on derivative instruments	$	10,383		$	15,843		$	(23,736	)	$	(3,454	)	$	1,297
Realized gain (loss) on derivatives, not included in net income		10,996			2,990			9,278			(8,055	)		2,190
Amortization of turnaround costs		11,384			10,006			7,256			2,468			3,190
Non-cash equity based compensation and other non-cash items		7,406			1,540			1,075			179			121

EBITDA	$	170,851		$	108,083		$	157,244		$	135,396		$	102,601

Add:
Unrealized (gain) loss on derivative instruments		10,383			15,843			(23,736	)		(3,454	)		1,297
Cash interest expense (2)		(45,019	)		(26,633	)		(29,901	)		(30,543	)		(4,289	)
Non-cash equity based compensation		4,895			1,540			1,075			179			121
Amortization of turnaround costs		11,384			10,006			7,256			2,468			3,190
Income tax expense		(929	)		(598	)		(151	)		(257	)		(501	)
Provision for doubtful accounts		380			74			(916	)		1,448			41
Debt extinguishment costs		(729	)		—			—			—			—
Changes in assets and liabilities:
Accounts receivable		(54,484	)		(35,267	)		(12,296	)		45,042			(15,038	)
Inventories		(167,028	)		(9,860	)		(18,726	)		55,532			3,321
Other current assets		(425	)		4,669			(2,848	)		1,834			(4,121	)
Turnaround costs		(14,052	)		(10,684	)		(6,890	)		(11,277	)		(2,395	)
Derivative activity		11,742			2,990			8,531			41,757			2,121
Other noncurrent assets		(426	)		(2,006	)		1			1,066			(4,115	)
Accounts payable		138,611			64,739			15,951			(103,136	)		89,225
Other liabilities		(2,073	)		11,275			392			(1,284	)		(4,149	)
Other, including changes in noncurrent liabilities		697			(28	)		5,868			(4,430	)		237

Net cash provided by operating activities	$	63,778		$	134,143		$	100,854		$	130,341		$	167,546

(1)	Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs.

(2)	Represents consolidated interest expense less non-cash interest expense.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The historical consolidated financial statements included in this Annual Report reflect all of the assets, liabilities and results of operations of the Company. The following discussion analyzes the financial condition and results of operations of the Company for the years ended December 31, 2011, 2010, and 2009. Unitholders should read the following discussion and analysis of the financial condition and results of operations of the Company in conjunction with the historical consolidated financial statements and notes of the Company included elsewhere in this Annual Report.

Overview

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We are headquartered in Indianapolis, Indiana and own plants primarily located in Louisiana, Wisconsin and Pennsylvania. We own and lease additional facilities, primarily related to production and distribution of specialty products, throughout the U.S. Our business is organized into two segments: specialty products and fuel products. In our specialty products segment, we process crude oil and other feedstocks into a wide variety of customized lubricating oils, white mineral oils, solvents, petrolatums, asphalt and waxes. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for basic industrial, consumer and automotive goods. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products, including gasoline, diesel, jet fuel and heavy fuel oils. In connection with our production of specialty products and fuel products, we also produce asphalt and a limited number of other by-products. In 2011, approximately 94.4% of our gross profit was generated from our specialty products segment and approximately 5.6% of our gross profit was generated from our fuel products segment.

2011 Update

For the years ended December 31, 2011 and 2010, 46.8% and 53.0%, respectively, of our sales volume and 94.4% and 94.3%, respectively, of our gross profit was generated from our specialty products segment while, for the same periods, 53.2% and 47.0%, respectively, of our sales volume and approximately 5.6% and 5.7%, respectively, of our gross profit was generated from our fuel products segment.

We continued to see strength in product demand in our specialty products segment in 2011. We noted a 4.9% increase in barrels of specialty products sold, including the impact of incremental sales in the fourth quarter of 2011 from the Superior Acquisition, which closed on September 30, 2011. Our specialty products segment generated a gross profit margin of 14.3% in 2011, as compared to a gross profit margin of 13.3% in 2010, as specialty products sales pricing kept pace with fluctuations in crude oil prices.

Higher sales and production volume in our fuel products segment during 2011 allowed us to take advantage of higher market crack spreads. We noted a 34.4% increase in barrels of fuel products sold in 2011 compared to 2010 including the impact of incremental sales from the Superior Acquisition. The fuel products segment generated a gross profit margin of 1.2% in 2011 compared to 1.4% in 2010 despite the recognition of realized derivative losses of $103.3 million during 2011 compared to the recognition of realized derivative gains of $14.0 million in 2010 due to the strength of current market crack spreads compared to our hedged crack spreads. Throughout 2011, we entered into additional crack spread hedges due to the strength in forward markets, adding 11.0 million barrels of crack spreads for calendar years 2012 through 2014 at an average of $23.88 per barrel, a $10.78 per barrel increase over our average hedged crack spread in 2011.

Our 2011 total facility production increased by 8.9% year over year, excluding the impact of the Superior Acquisition, due primarily to our decision to increase production run rates at our facilities overall to take advantage of strengthened fuel products crack spreads and continued strength in demand for specialty products in a favorable margin environment.

We were very active in the capital markets in 2011 in order to complete a refinancing of our debt and to fund the $413.2 million Superior Acquisition, our largest acquisition to date. As further described below, we completed public offerings of common units in February 2011 and September 2011 which generated net proceeds of $294.7 million and completed private placement offerings in April 2011 and September 2011 for a total of $600.0 million in senior unsecured notes due 2019, which generated net proceeds of $569.3 million. We used a portion of the proceeds from our April 2011 senior unsecured notes offering to fully repay our senior secured first lien term loan. We also amended and restated our revolving credit facility in June 2011 to expand borrowing capacity from $375.0 million to $550.0 million, subject to borrowing base limitations, and exercised in full an expansion option in September 2011 to increase the maximum availability under the revolving credit facility to $850.0 million in conjunction with Superior Acquisition.

We generated $63.8 million in cash flow from operations during 2011. We paid distributions of $82.7 million to our unitholders in 2011, an increase of $17.0 million over 2010. We plan to continue focusing our efforts on generating positive cash flows from operations which we expect will be used to (i) improve our liquidity position, (ii) pay quarterly distributions to our unitholders, (iii) service our debt obligations and (iv) provide funding for general partnership purposes.

Superior Acquisition

•

Murphy Oil’s “SPUR” branded gasoline wholesale franchise business.

Please see Part I, Items 1 and 2 “Business and Properties — Our Operating Assets and Contractual Arrangements — Superior Refinery” for additional information.

Key Performance Measures

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

Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our control. We monitor these risks and enter into financial derivatives designed to mitigate the impact of

commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. As of December 31, 2011, we have hedged refining margins, or crack spreads, on approximately 16.5 million barrels of fuel products through December 2014 at an average refining margin of $20.26 per barrel with average refining margins ranging from a low of $17.46 per barrel in 2012 to a high of $25.01 per barrel in 2014. Please refer to Note 8 under Item 8 “Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk — Existing Commodity Derivative Instruments” and “— Interest Rate Risk and Existing Interest Rate Derivative Instruments” and “— Commodity Price Risk” for detailed information regarding our derivative instruments and our commodity price and interest rate risks.

Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:

•

sales volumes;

•

production yields; and

•

specialty products and fuel products gross profit.

Sales volumes. We view the volumes of specialty products and fuel products sold as an important measure of our ability to effectively utilize our refining assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.

Production yields. In order to maximize our gross profit and minimize lower margin by-products, we seek the optimal product mix for each barrel of crude oil we refine, which we refer to as production yield.

Specialty products and fuel products gross profit. Specialty products and fuel products gross profit are important measures of our ability to maximize the profitability of our specialty products and fuel products segments. We define specialty products and fuel products gross profit as sales less the cost of crude oil and other feedstocks and other production-related expenses, the most significant portion of which includes labor, plant fuel, utilities, contract services, maintenance, depreciation and processing materials. We use specialty products and fuel products gross profit as indicators of our ability to manage our business during periods of crude oil and natural gas price fluctuations, as the prices of our specialty products and fuel products generally do not change immediately with changes in the price of crude oil and natural gas. The increase in selling prices typically lags behind the rising costs of crude oil feedstocks for specialty products. Other than plant fuel, production-related expenses generally remain stable across broad ranges of throughput volumes, but can fluctuate depending on maintenance activities performed during a specific period.

Our fuel products segment gross profit may differ from a standard U.S. Gulf Coast and Group 3 2/1/1 or 3/2/1 market crack spread due to many factors, including derivative activities to hedge both our fuel products segment revenues and the cost of crude oil reflected in gross profit, our fuel products mix as shown in our production table being different than the ratios used to calculate such market crack spreads, the allocation of by-product (primarily asphalt) losses to the fuel products segment, operating costs including fixed costs and actual crude oil costs differing from market indices and our local market pricing differentials for fuel products in the Shreveport, Louisiana and Superior, Wisconsin vicinities as compared to U.S. Gulf Coast and Group 3 postings, respectively.

In addition to the foregoing measures, we also monitor our selling, general and administrative expenditures, substantially all of which are incurred through our general partner.

Results of Operations

The following table sets forth information about our combined operations. Facility production volume differs from sales volume due to changes in inventories and the sale of purchased fuel product blendstocks such as ethanol and biodiesel in our fuel products segment. The table includes volumes under the LyondellBasell Agreements commencing November 4, 2009 and the results of operations at our Superior refinery commencing October 1, 2011. Please see Part I, Items 1 and 2 “Business and Properties — Our Operating Assets and Contractual Arrangements — LyondellBasell Agreements” for additional information on the LyondellBasell Agreements.


	Year Ended December 31,
	2011		2010		2009
	(In bpd)
Total sales volume (1)		66,134		55,668		57,086
Total feedstock runs (2)		69,295		55,957		60,081
Facility production: (3)
Specialty products:
Lubricating oils		14,427		13,697		11,681
Solvents		10,508		9,347		7,749
Waxes		1,269		1,220		1,049
Fuels		556		1,050		853
Asphalt and other by-products		10,090		6,907		7,574

Total specialty products		36,850		32,221		28,906

Fuel products:
Gasoline		13,409		8,754		9,892
Diesel		14,721		10,800		12,796
Jet fuel		4,520		5,004		6,709
Heavy fuel oils and other		1,409		535		489

Total fuel products		34,059		25,093		29,886

Total facility production (3)		70,909		57,314		58,792

(1)

Total sales volume includes sales from the production at our facilities and, certain third-party facilities pursuant to supply and/or processing agreements, and sales of inventories. Total sales volume excludes the sale of purchased fuel product blendstocks such as ethanol and biodiesel as components of finished fuel products in our fuel products segment sales. The increase in total sales volume in 2011 compared to 2010 is due primarily to incremental sales of fuel products subsequent to the Superior Acquisition on September 30, 2011, as well as our decision to increase crude oil run rates at our facilities overall during 2011 because of the favorable economics of running additional barrels.

(2)

Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. The increase in total feedstock runs in 2011 compared to 2010 is due primarily to incremental feedstock runs from the acquisition of the Superior refinery on September 30, 2011, our decision to increase feedstock run rates at our facilities overall during 2011 because of the favorable economics of running additional barrels and the failure of an environmental operating unit at our Shreveport refinery during the first quarter of 2010 which impacted run rates in 2010, partially offset by the impact of the approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during the period.

The decrease in total feedstock runs in 2010 compared to 2009 is due primarily to our decision to reduce feedstock run rates at our Shreveport refinery during the entire first quarter of 2010 because of the poor economics of running additional barrels, the failure of an environmental operating unit during at our Shreveport refinery the first quarter of 2010 and scheduled turnarounds completed in the second and fourth

quarters of 2010 related to various operating units at our Shreveport refinery. These decreases were partially offset by higher feedstock runs at our Cotton Valley refinery throughout 2010 and the addition of volumes for a full year under the LyondellBasell Agreements.

(3)

Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements, including the LyondellBasell Agreements. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss. The increase in total facility production in 2011 over 2010 is due primarily to increased feedstock runs from the acquisition of the Superior refinery on September 30, 2011 and increased feedstock runs at our facilities overall, as discussed above in footnote 2 of this table.

The increase in the production of specialty products in 2010 as compared to 2009 is primarily the result of the addition of volumes under the LyondellBasell Agreements and higher feedstock runs at our Cotton Valley refinery. The reduction in production of fuel products in 2010 compared to 2009 is due primarily to reduced feedstock runs at our Shreveport refinery as discussed in footnote 2 of this table.

The following table reflects our consolidated results of operations and includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income and net cash provided by operating activities, our most directly comparable financial performance and liquidity measures calculated in accordance with GAAP, please read “— Non-GAAP Financial Measures.”


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Sales	$	3,134,923		$	2,190,752		$	1,846,600
Cost of sales		2,860,793			1,992,003			1,673,498

Gross profit		274,130			198,749			173,102

Operating costs and expenses:
Selling, general and administrative		50,836			35,224			32,570
Transportation		94,187			85,471			67,967
Taxes other than income taxes		5,661			4,601			3,839
Insurance recoveries		(8,698	)		—			—
Other		6,852			1,963			1,366

Operating income		125,292			71,490			67,360

Other income (expense):
Interest expense		(48,747	)		(30,497	)		(33,573	)
Debt extinguishment costs		(15,130	)		—			—
Realized gain (loss) on derivative instruments		(7,909	)		(7,704	)		8,342
Unrealized gain (loss) on derivative instruments		(10,383	)		(15,843	)		23,736
Other		842			(147	)		(3,929	)

Total other expense		(81,327	)		(54,191	)		(5,424	)

Income before income taxes		43,965			17,299			61,936
Income tax expense		929			598			151

Net income	$	43,036		$	16,701		$	61,785

EBITDA	$	170,851		$	108,083		$	157,244

Adjusted EBITDA	$	211,020		$	138,462		$	151,117

Distributable Cash Flow	$	127,158		$	76,202		$	98,667

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Sales. Sales increased $944.2 million, or 43.1%, to $3,134.9 million in 2011 from $2,190.8 million in 2010. The results of operations related to the Superior Acquisition have been included in the both segments since the date of acquisition, September 30, 2011. Sales for each of our principal product categories in these periods were as follows:


	Year Ended December 31,
	2011		2010		% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	947,798	$	759,701		24.8	%
Solvents		495,934		396,894		25.0	%
Waxes		143,111		124,964		14.5	%
Fuels (1)		3,432		5,507		(37.7	)%
Asphalt and by-products (2)		217,351		121,806		78.4	%

Total specialty products	$	1,807,626	$	1,408,872		28.3	%

Total specialty products sales volume (in barrels)		11,296,000		10,766,000		4.9	%
Average specialty products sales price per barrel	$	160.02	$	130.86		22.3	%
Fuel products:
Gasoline	$	619,630	$	304,544		103.5	%
Diesel		513,334		330,756		55.2	%
Jet fuel		148,036		135,796		9.0	%
Heavy fuel oils and other (3)		46,297		10,784		329.3	%

Total fuel products	$	1,327,297	$	781,880		69.8	%

Total fuel products sales volume (in barrels)		12,843,000		9,553,000		34.4	%
Average fuel products sales price per barrel (excluding hedging activities)	$	119.84	$	88.93		34.8	%
Total sales	$	3,134,923	$	2,190,752		43.1	%

Total sales volume (in barrels)		24,139,000		20,319,000		18.8	%

(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 Shreveport, Superior, Princeton and Cotton Valley refineries.

(3)	Represents heavy fuel oils and other products produced in connection with the production of fuels at the Shreveport and Superior refineries.

Specialty products segment sales for 2011 increased $398.8 million, or 28.3%, primarily as a result of an increase in the average selling price per barrel of $29.16, or 22.3%. Sales volume increased 4.9% over 2010 due primarily to incremental asphalt sales volume associated with the Superior Acquisition, which closed on September 30, 2011. Excluding incremental asphalt sales volume associated with the Superior Acquisition, our specialty products segment sales volume remained consistent with 2010. The increase in the specialty products average selling price per barrel is due primarily to a 26.1% increase in the average cost of crude oil per barrel for 2011 as compared to 2010.

Fuel products segment sales for 2011 increased $545.4 million, or 69.8%, due primarily to a 34.4% increase in sales volume (due primarily to the incremental fuel products sales volume from the Superior Acquisition) and an increase in the average selling price per barrel (excluding the impact of realized hedging losses reflected in sales) of $30.91, or 34.8%, as compared to a 25.8% increase in the average price of crude oil per barrel. Excluding incremental sales volume associated with the Superior Acquisition, our fuels products sales volume

increased 7.5% due to increased gasoline and diesel sales driven by market conditions and increased run rates at the Shreveport refinery over 2010. The average selling price per barrel increased for all fuel products, with diesel and jet fuel average selling prices experiencing significant increases driven by improved market pricing. Adversely impacting fuel products segment sales was a $144.1 million increase in realized derivative losses on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for discussion of the net impact of our crude oil and fuel products derivative instruments designated as cash flow hedges.

Gross Profit. Gross profit increased $75.4 million, or 37.9%, to $274.1 million in 2011 from $198.7 million in 2010. Gross profit for our specialty and fuel products segments was as follows:


	Year Ended December 31,
	2011			2010			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products	$	258,648		$	187,416			38.0	%
Percentage of sales		14.3	%		13.3	%
Specialty products gross profit per barrel	$	22.90		$	17.41			31.5	%
Fuel products	$	15,482		$	11,333			36.6	%
Percentage of sales		1.2	%		1.4	%
Fuel products gross profit per barrel	$	1.21		$	1.19			1.7	%
Total gross profit	$	274,130		$	198,749			37.9	%
Percentage of sales		8.7	%		9.1	%

The increase in specialty products segment gross profit of $71.2 million year over year was due primarily to a 22.3% increase in the average selling price per barrel, partially offset by a 26.1% increase in the average cost of crude oil per barrel and higher operating costs, primarily repairs and maintenance.

The increase in fuel products segment gross profit of $4.1 million year over year was due primarily to a 34.4% increase in sales volume as a result of the Superior Acquisition and a 34.8% increase in the average selling price per barrel (excluding the impact of realized hedging losses reflected in sales), partially offset by a 25.8% increase in the average cost of crude oil per barrel, increased realized losses on derivatives of $117.3 million in our fuel products hedging program and higher operating costs, primarily repairs and maintenance. Additionally, by-products production increased in 2011 compared to 2010 due primarily to an increase in run rates at the Shreveport refinery.

Selling, general and administrative. Selling, general and administrative expenses increased $15.6 million, or 44.3%, to $50.8 million in 2011 from $35.2 million in 2010. This increase is due primarily to increased accrued incentive compensation costs of $7.0 million in 2011 compared to 2010, $2.7 million of acquisition costs related to the Superior Acquisition with no comparable costs in 2010, increased overall salaries and wages of $1.8 million and increased advertising costs of $1.3 million.

Transportation. Transportation expenses increased $8.7 million, or 10.2%, to $94.2 million in 2011 from $85.5 million in 2010. This increase is due primarily to increased truck and rail freight rates, incremental transportation expenses related to the Superior Acquisition and increased rail demurrage costs.

Insurance recoveries. Insurance recoveries were $8.7 million for year ended December 31, 2011. This gain was related to a claim settled in the second quarter of 2011 with insurers related to the failure of an environmental operating unit at the Shreveport refinery in 2010.

Interest expense. Interest expense increased $18.3 million, or 59.8%, to $48.7 million in 2011 from $30.5 million in 2010. This increase was due primarily to higher interest rates associated with the 2019 Notes as compared to the prior term loan that was repaid in full and extinguished in connection with the issuance of the 2019 Notes, as well as additional outstanding long-term debt to partially fund the Superior Acquisition.

Debt extinguishment costs. Debt extinguishment costs were $15.1 million in 2011 with no such costs in 2010. The debt extinguishment costs were related to the extinguishment of the prior term loan in April 2011 with proceeds from the issuance of the 2019 Notes issued in April 2011. Please read Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information.

Realized gain (loss) on derivative instruments. Realized loss on derivative instruments increased $0.2 million to $7.9 million in 2011 from $7.7 million in 2010. This change was due primarily to increased prior year gains of $4.0 million on crack spread derivatives not designated as hedges that were executed to economically lock in gains on a portion of our fuel products segment’s derivative hedging activity and losses of $1.3 million on interest rate swap contracts that were previously designated as cash flow hedges partially offset by reduced losses of approximately $6.7 million in our specialty products segment related to crude oil derivatives not designated as hedges in 2011.

Unrealized gain (loss) on derivative instruments. Unrealized loss on derivative instruments decreased $5.5 million to $10.4 million in 2011 from $15.8 million in 2010. The decreased loss is due primarily to a decrease in hedge ineffectiveness of $6.9 million during 2011.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Sales. Sales increased $344.2 million, or 18.6%, to $2,190.8 million in 2010 from $1,846.6 million in 2009. Sales for each of our principal product categories in these periods were as follows:


	Year Ended December 31,
	2010		2009		% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	759,701	$	500,938		51.7	%
Solvents		396,894		260,185		52.5	%
Waxes		124,964		97,658		28.0	%
Fuels (1)		5,507		8,951		(38.5	)%
Asphalt and by-products (2)		121,806		103,488		17.7	%

Total specialty products	$	1,408,872	$	971,220		45.1	%

Total specialty products sales volume (in barrels)		10,766,000		9,370,000		14.9	%
Average specialty products sales price per barrel	$	130.86	$	103.65		26.3	%
Fuel products:
Gasoline	$	304,544	$	317,435		(4.1	)%
Diesel		330,756		372,359		(11.2	)%
Jet fuel		135,796		167,638		(19.0	)%
By-products (3)		10,784		17,948		(39.9	)%

Total fuel products	$	781,880	$	875,380		(10.7	)%

Total fuel products sales volume (in barrels)		9,553,000		11,466,000		(16.7	)%
Average fuel products sales price per barrel (excluding derivative impacts)	$	88.93	$	69.84		27.3	%
Total sales	$	2,190,752	$	1,846,600		18.6	%

Total sales volume (in barrels)		20,319,000		20,836,000		(2.5	)%

(1)	Represents fuels produced in connection with the production of specialty products at the Princeton and Cotton Valley refineries.

(2)	Represents asphalt and other by-products produced in connection with the production of specialty products at the Princeton, Cotton Valley and Shreveport refineries.

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

Specialty products segment sales in 2010 increased $437.7 million, or 45.1%, due primarily to an increase in the average selling price per barrel of $27.21, or 26.3%, and a 14.9% increase in sales volume, from approximately 9.4 million barrels in 2009 to 10.8 million barrels in 2010. Specialty products average selling prices per barrel increased in all product categories driven by improving overall demand and in response to an increase of 31.8% in the average cost of crude oil per barrel in 2010 compared to 2009. The increased sales volume is due primarily to improving overall specialty products demand as a result of improved economic conditions and the addition of sales volume under the LyondellBasell Agreements in 2010, partially offset by decreased production due primarily to our decision to reduce crude oil run rates at our Shreveport refinery during the entire first quarter of 2010 because of the poor economics of running additional barrels, the failure of an environmental operating unit during the first quarter of 2010 and scheduled turnarounds completed in the second quarter related to various operating units at our Shreveport refinery.

Fuel products segment sales in 2010 decreased $93.5 million, or 10.7%, due primarily to a 16.7% decrease in sales volumes, from approximately 11.5 million barrels in 2009 to 9.6 million barrels in 2010, due primarily to our decision to reduce crude oil run rates at our facilities during the entire first quarter of 2010 because of the poor economics of running additional barrels, the failure of an environmental operating unit during the first quarter of 2010 and scheduled turnarounds completed in the second and fourth quarters related to various operating units at our Shreveport refinery. Partially offsetting this decrease in sales volume was an increase in the average selling price per barrel of $19.09, or 27.3%, as compared to a 32.3% increase in the average cost of crude oil per barrel. Increases in sales prices lagged crude oil cost increases due to local market conditions. Also contributing to the overall decrease in sales was a $142.2 million decrease in derivative gains on our fuel products cash flow hedges recorded in sales. Please read “Gross Profit” below for the net impact of our crude oil and fuel products derivative instruments designated as hedges.

Gross Profit. Gross profit increased $25.6 million, or 14.8%, to $198.7 million in 2010 from $173.1 million in 2009. Gross profit for our specialty and fuel products segments was as follows:


	Year Ended December 31,
	2010			2009			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products	$	187,416		$	141,577			32.4	%
Percentage of sales		13.3	%		14.6	%
Specialty products gross profit per barrel	$	17.41		$	15.11			15.2	%
Fuel products	$	11,333		$	31,525			(64.1	)%
Percentage of sales		1.4	%		3.6	%
Fuel products gross profit per barrel	$	1.19		$	2.75			(56.7	)%
Total gross profit	$	198,749		$	173,102			14.8	%
Percentage of sales		9.1	%		9.4	%

The increase in specialty products segment gross profit is due primarily to the 14.9% increase in sales volume. Also improving our gross profit was an increase of $10.9 million in 2010 compared to 2009 from the liquidation of lower cost inventory layers. Further, the increase in the average selling price per barrel of $27.21 exceeded the increase in the average cost of crude oil per barrel. Partially offsetting these increases were higher operating costs per barrel sold at our Shreveport refinery due to lower production levels in 2010 compared to 2009.

The decrease in fuel products segment gross profit is due primarily to reduced sales volume of 16.7%, increased crude oil costs per barrel of 32.3% compared to the 27.3% increase in the average sales price per barrel, a $15.6 million reduction in gains from the liquidation of lower cost inventory layers, higher operating costs per barrel at our Shreveport refinery due to lower production levels and decreased derivative gains of $4.6 million from our crack spread cash flow hedges.

Selling, general and administrative. Selling, general and administrative expenses increased $2.7 million, or 8.1%, to $35.2 million in 2010 from $32.6 million in 2009. This increase is due primarily to lower bad debt expense in 2009 resulting from the recovery of $0.9 million account receivable and the write off of the remaining costs related to the proposed offering for sale of senior unsecured notes in July 2010 which we opted not to complete.

Transportation. Transportation expenses increased $17.5 million, or 25.8%, to $85.5 million in 2010 from $68.0 million in 2009. This increase is due primarily to increased sales volumes of lubricating oils, solvents and waxes.

Interest expense. Interest expense decreased $3.1 million, or 9.2%, to $30.5 million in 2010 from $33.6 million in 2009. This decrease is due primarily to lower interest rates and lower balances being carried on our revolver and term loan during the 2010 as compared to 2009. Revolver borrowings were reduced due to reductions in working capital as we improved payment terms with certain suppliers.

Realized gain (loss) on derivative instruments. Realized gain (loss) on derivative instruments decreased $16.0 million to a loss of $7.7 million in 2010 from an $8.3 million gain in 2009. This decrease is due primarily to reduced derivative gains of $13.6 million in 2010 on settlements of our crack spread derivatives used to economically lock in gains on a portion of our fuel products segment derivative hedging activity. Also contributing to this decrease was higher loss ineffectiveness on settled fuel products derivatives designated as cash flow hedges of $9.2 million. Partially offsetting these items were decreased realized losses in 2010 on crude oil derivatives in our specialty products segment due to the significant decline in crude oil prices late in 2008 (which resulted in larger realized losses early in 2009), whereas crude oil prices were relatively stable in 2010 as well as significantly less volume of these derivative contracts settled in 2010.

Unrealized gain (loss) on derivative instruments. Unrealized gain (loss) on derivative instruments decreased $39.6 million, to a $15.8 million loss in 2010 from a $23.7 million gain in 2009. This increased loss is due primarily to decreased gains of $11.4 million on the derivatives used to economically hedge our specialty products crude oil purchases and increased losses of $7.8 million on our crack spread derivatives used to economically lock in gains on a portion of our fuel products segment derivative hedging activity with minimal related activity in 2010. This decrease was also due to lower gain ineffectiveness in 2010 as compared to 2009.

Liquidity and Capital Resources

Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings, proceeds from notes offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions to our limited partners and general partner and debt service. We expect that our principal uses of cash in the future will be for distributions to our limited partners and general partner, debt service, replacement and environmental capital expenditures, capital expenditures related to internal growth projects and acquisitions. We expect to fund future capital expenditures with current cash flow from operations and borrowings under our revolving credit facility. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and borrowing availability under our revolving credit facility and may require us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.

Cash Flows from Operating, Investing and Financing Activities

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity to meet our financial commitments, debt service obligations and anticipated capital expenditures. However, we are subject to business and operational risks that could materially adversely affect our cash flows. A material decrease in our cash flow from operations including a significant, sudden decrease in crude oil prices would likely produce a corollary material adverse effect on our borrowing capacity under our revolving credit facility

and potentially our ability to comply with the covenants under our debt instruments and other financing arrangements. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which would be funded by borrowings under our revolving credit facility.

The following table summarizes our primary sources and uses of cash in each of the most recent three years:


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Net cash provided by operating activities	$	63,778		$	134,143		$	100,854
Net cash used in investing activities	$	(460,424	)	$	(34,759	)	$	(22,714	)
Net cash provided by (used in) financing activities	$	396,673		$	(99,396	)	$	(78,139	)

Operating Activities. Operating activities provided $63.8 million in cash during 2011 compared to $134.1 million during 2010. The decrease in cash provided by operating activities is due primarily to increased net working capital requirements of $89.0 million, primarily from increases in crude oil inventory levels as a result of terminating certain just-in-time inventory supply arrangements with Legacy Resources, a related party, effective May 31, 2011, increased run rates at our Shreveport refinery and higher commodity prices in general partially offset by a reduction in working capital requirements for the Superior Acquisition since the date of closing on September 30, 2011. Partially offsetting the increase in net working capital requirements was increased net income of $26.3 million.

Operating activities provided $134.1 million in cash during 2010 compared to $100.9 million during 2009. The increase in cash provided by operating activities is due primarily to reduced working capital needs in 2010 providing $25.4 million in cash compared to 2009 working capital changes using $14.7 million. This improvement is due primarily to improved payment terms with suppliers, offset by increases in both accounts receivable and inventories from higher crude oil prices.

Investing Activities. Cash used in investing activities increased to $460.4 million in 2011 compared to $34.8 million in 2010. The increase is due primarily to the Superior Acquisition which closed on September 30, 2011 for $413.2 million, which included $183.6 million for purchased inventories, with no similar acquisition activities in the prior year.

Cash used in investing activities increased to $34.8 million in 2010 compared to $22.7 million in 2009 due primarily to increased capital expenditures in 2010 compared to 2009.

Financing Activities. Financing activities provided cash of $396.7 million during 2011 compared to using cash of $99.4 million during 2010. The change is due primarily to the net proceeds from the February 2011 and September 2011 public offerings of common units of $294.7 million and proceeds from the 2019 Notes offerings of $586.0 million, net of discount, in the second and third quarters of 2011, partially offset by $27.7 million of debt issuance costs, the $367.4 million repayment of the senior secured first lien term loan and $17.0 million of increased distributions to our unitholders.

Cash used in financing activities was $99.4 million during 2010 compared to $78.1 million during 2009. This increased use of cash is due primarily to proceeds received from our December 2009 public offering of common units of approximately $52.3 million, including $1.1 million of contributions received from our general partner, with only $0.8 million of proceeds received in early 2010 from the exercise of the underwriter’s overallotment option from our December 2009 public offering of common units in addition to increased distributions of $6.5 million in 2010 as compared to 2009 due to higher amounts of outstanding units and an increase in our distribution per unit. Partially offsetting these increases is decreased net repayments of revolver borrowings of $33.6 million in 2010 as compared to 2009.

On January 3, 2012, we completed the acquisition of the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) from Hercules Incorporated, a subsidiary of Ashland, Inc. for aggregate consideration of approximately $19.6 million, excluding certain customary post-closing purchase price adjustments. The acquisition was financed with borrowings under our revolving credit facility and cash on hand. We also acquired a manufacturing facility located in Louisiana, Missouri.

On January 23, 2012, we declared a quarterly cash distribution of $0.53 per unit on all outstanding units, or approximately $28.2 million in aggregate, for the quarter ended December 31, 2011. The distribution was paid on February 14, 2012 to unitholders of record as of the close of business on February 3, 2012. This quarterly distribution of $0.53 per unit equates to approximately $2.12 per unit, or approximately $112.8 million in aggregate on an annualized basis.

Capital Expenditures

Our capital expenditure requirements consist of capital improvement expenditures, replacement capital expenditures and environmental capital expenditures. Capital improvement expenditures include expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs. Replacement capital expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.

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


	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Capital improvement expenditures	$	25,616	$	10,656	$	8,013
Replacement capital expenditures		13,397		14,700		12,149
Environmental capital expenditures		10,465		9,645		3,359

Total	$	49,478	$	35,001	$	23,521

We anticipate that future capital expenditure requirements will be provided primarily through cash from operations and available borrowings under our revolving credit facility. Our capital improvement expenditures have increased in 2011 compared to 2010 due to various minor capital improvement projects to reduce energy costs, improve finished product quality and improve finished product yields as well as capital projects at the Superior refinery, which we acquired on September 30, 2011. In 2009 and 2010, we limited our overall capital expenditures to required environmental expenditures, necessary replacement capital expenditures to maintain our facilities and minor capital improvement projects to reduce energy costs, improve finished product quality and improve finished product yields.

We estimate our replacement and environmental capital expenditures will be approximately $8.0 million per quarter in 2012. These estimated amounts for 2012 include a portion of the remaining $7.0 million to $11.0 million in environmental projects to be spent over the next four years as required by our settlement with

the LDEQ under the “Small Refinery and Single Site Refining Initiative”. Please read Part I, Items 1 and 2 “Business and Properties — Environmental and Occupational Health and Safety Matters — Air Emissions” for additional information.

Additionally, we anticipate future turnaround spending requirements will be approximately $17.0 million in 2012 and $34.0 million in 2013. We expect these expenditures will be funded primarily through cash flow from operations.

Debt and Credit Facilities

As of December 31, 2011, our primary debt and credit instruments consist of:

•

an $850.0 million senior secured revolving credit facility, subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $680.0 million, which is the greater of (i) $400.0 million and (ii) 80% of revolver commitments in effect; and

•

$600.0 million of 9³/8% senior notes due 2019.

As of December 31, 2011, we believe we were in compliance with all covenants under the debt instruments in place at December 31, 2011 and have adequate liquidity to conduct our business.

Amended and Restated Senior Secured Revolving Credit Facility

On June 24, 2011, we entered into an amended and restated senior secured revolving credit facility (the “revolving credit facility”), which increased the maximum availability of credit under the revolving credit facility from $375.0 million to $550.0 million, subject to borrowing base limitations, and included a $300.0 million incremental uncommitted expansion option. On September 30, 2011, in conjunction with the Superior Acquisition, we fully exercised the $300.0 million expansion option to increase the maximum availability of credit under the revolving credit facility from $550.0 million to $850.0 million, subject to borrowing base limitations. The lenders under our revolving credit facility, which matures in June 2016, have a first priority lien on our cash, accounts receivable, inventory and certain other personal property.

Our revolving credit facility contains various covenants that limit, among other things, our ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; and enter into a merger, consolidation or sale of assets. The revolving credit facility generally permits us to make cash distributions to our unitholders as long as immediately after giving effect to such a cash distribution we have availability under the revolving credit facility at least equal to the greater of (i) 15% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) without giving effect to the LC Reserve (as defined in the credit agreement) and (b) the revolving credit facility commitments then in effect and (ii) $45.0 million. Further, the revolving credit facility contains one springing financial covenant which provides that only if our availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $46.4 million, (as increased, upon the effectiveness of the increase in the maximum availability under our revolving credit facility, by the same percentage as the percentage increase in our revolving credit agreement commitments), we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0.

Borrowings under the revolving credit facility are limited to a borrowing base that is determined based on advance rates of percentages of Eligible Accounts Receivable and Eligible Inventory (as defined in the revolving credit agreement). As such, the borrowing base can fluctuate based on changes in selling prices of our products and our current material costs, primarily the cost of crude oil. On December 31, 2011, we had availability on our

revolving credit facility of $340.8 million, based on a $570.8 million borrowing base, $230.0 million in outstanding standby letters of credit and no outstanding borrowings. The borrowing base cannot exceed the revolving credit facility commitments then in effect. The lender group under our revolving credit facility is comprised of a syndicate of thirteen lenders with total commitments of $850.0 million.

The revolving credit facility, which is our primary source of liquidity for cash needs in excess of cash generated from operations, currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of December 31, 2011, this margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin can fluctuate quarterly based on our average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter as follows:


Quarterly Average Availability Percentage	Margin on Base Rate Revolving Loans			Margin on LIBOR Revolving Loans
³ 66%		1.00	%		2.25	%
³ 33% and < 66%		1.25	%		2.50	%
< 33%		1.50	%		2.75	%

In addition to paying interest on outstanding borrowings under the revolving credit facility, we are required to pay a commitment fee to the lenders under the revolving credit facility in respect of the unutilized commitments thereunder at a rate equal to 0.375% to 0.50% per annum depending on the average daily available unused borrowing capacity. We also pay a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.

If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other rights and remedies. An event of default includes, among other things, the nonpayment of principal, interest, fees or other amounts; failure of any representation or warranty to be true and correct when made or confirmed; failure to perform or observe covenants in the revolving credit facility or other loan documents, subject, in limited circumstances, to certain grace periods; cross-defaults in other indebtedness if the effect of such default is to cause, or permit the holders of such indebtedness to cause, the acceleration of such indebtedness under any material agreement; bankruptcy or insolvency events; monetary judgment defaults; asserted invalidity of the loan documentation; and a change of control over us.

Amounts outstanding under our revolving credit facility fluctuate materially during each quarter due to normal changes in working capital, payments of quarterly distributions to unitholders and debt service costs. Specifically, the amount borrowed under our revolving credit facility is typically at its highest level after we pay for the majority of our crude oil supplies on the 20th day of every month per standard industry terms. The maximum revolving credit facility borrowings during the fourth quarter of 2011 were $164.6 million. Nonetheless, our availability on our revolving credit facility during the peak borrowing days of a quarter has been ample to support our operations and service upcoming requirements. During the quarter ended December 31, 2011, availability for additional borrowings under our revolving credit facility was approximately $162.5 million at its lowest point. We believe that we will continue to have sufficient cash flow from operations and borrowing availability under our revolving credit facility to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, debt instrument covenants, contingencies and anticipated capital expenditures.

9³/8% Senior Notes

On April 21, 2011, in connection with the restructuring of the majority of our outstanding long-term debt, we issued and sold $400.0 million in aggregate principal amount of 9³/8% of senior notes due May 1, 2019 (the “2019 Notes issued in April 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at par. The 2019 Notes issued in April 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S

under the Securities Act. We received proceeds of $389.0 million net of underwriters’ fees and expenses, which we used to repay in full borrowings outstanding under our prior term loan, as well as all accrued interest and fees, and for general partnership purposes.

On September 19, 2011, in connection with the Superior Acquisition, we issued and sold $200.0 million in aggregate principal amount of 9³/8% of senior notes due May 1, 2019 (the “2019 Notes issued in September 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at a discounted price of 93 percent of par. The 2019 Notes issued in September 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. We received proceeds of $180.3 million net of discount, underwriters’ fees and expenses, which we used to fund a portion of the purchase price of the Superior Acquisition. Because the terms of the 2019 Notes issued in September 2011 are substantially identical to the terms of the 2019 Notes issued in April 2011, in this Annual Report we collectively refer to the 2019 Notes issued in April 2011 and the 2019 Notes issued in September 2011 as the “2019 Notes.”

Interest on the 2019 Notes is paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are jointly and severally guaranteed on a senior unsecured basis by all of our current operating subsidiaries and certain of our future operating subsidiaries.

At any time prior to May 1, 2014, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.

On and after May 1, 2015, we may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:


Year	Percentage
2015		104.688	%
2016		102.344	%
2017 and at any time thereafter		100.000	%

Prior to May 1, 2015, we may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indentures governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

The indentures governing the 2019 Notes contain covenants that, among other things, restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase our common units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indentures governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.

Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that we repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.

In connection with the 2019 Notes offering on April 21, 2011, our then current senior secured revolving credit facility was amended on April 15, 2011 to, among other things, (i) permit the issuance of the 2019 Notes issued in April 2011; (ii) upon consummation of the issuance of the 2019 Notes issued in April 2011 and the termination of the senior secured first lien credit facility, release the revolving credit facility lenders’ second priority lien on the collateral securing the senior secured first lien credit facility and (iii) change the interest rate pricing on the revolving credit facility.

Registration of 2019 Notes

In connection with the issuances and sales of the 2019 Notes, we entered into registration rights agreements with the initial purchasers of the 2019 Notes obligating us to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2019 Notes could offer to exchange the 2019 Notes for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. On December 16, 2011, we filed exchange offer registration statements for the 2019 Notes with the SEC, which were declared effective on January 3, 2012. The exchange offers were completed on February 2, 2012, thereby fulfilling all of the requirements of the 2019 Notes registration rights agreements.

Termination of Senior Secured First Lien Credit Facility

On April 21, 2011, we used approximately $369.5 million of the net proceeds from the issuance and sale of the 2019 Notes issued in April 2011 to repay in full our prior term loan, as well as accrued interest and fees, and terminated the entire senior secured first lien credit facility, including the term loan and a $50.0 million prefunded letter of credit to support crack spread hedging. We did not incur any material early termination penalties in connection with our termination of the senior secured first lien credit facility. Further, in the second quarter of 2011 we recorded approximately $15.1 million of debt extinguishment charges related to the write off of the unamortized debt issuance costs and the unamortized discount associated with the prior term loan.

Amendments to Master Derivative Contracts

In connection with the termination of the term loan facility and the amendment of revolving credit facility, on April 21, 2011, we entered into amendments to certain of our master derivatives contracts to provide new credit support arrangements to secure our payment obligations under these contracts following the termination of the prior term loan facility and the amendment and restatement of our revolving credit facility (“Amendments”). Under the new credit support arrangements, our payment obligations under all of our master derivatives contracts for commodity hedging generally are secured by a first priority lien on our and our subsidiaries’ real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). We also issued to one counterparty a $25.0 million standby letter of credit under the revolving credit facility to replace a prefunded $50.0 million letter of credit previously issued under the prior term loan facility. In the event that such counterparty’s exposure to us exceeds $200.0 million, we will be required to post additional collateral support in the form of either cash or letters of credit with the party to enter into additional crack spread hedges. We had no additional letters of credit or cash margin posted with any hedging counterparty as of December 31, 2011. Our master derivatives contracts and Collateral Trust Agreement (as defined below) continue to impose a number of covenant limitations on our operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements. For financial reporting purposes, we do not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to us upon settlement of the related derivative instrument liability.

The fair value of our derivatives decreased by approximately $101.0 million subsequent to December 31, 2011 to a net liability of approximately $86.0 million. All credit support thresholds with our hedging counterparties are at levels such that it would take a substantial increase in fuel products crack spreads to require significant additional collateral to be posted. As a result, we do not expect further increases in fuel products crack spreads to significantly impact our liquidity.

Collateral Trust Agreement

In connection with the Amendments, on April 21, 2011, we entered into a collateral sharing agreement (the “Collateral Trust Agreement”) with each of the secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties which governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by us to the secured hedging counterparties under their respective master derivatives contracts. Subject to certain conditions set forth in the Collateral Trust Agreement, we have the ability to add secured hedging counterparties thereto.

In connection with the closing of the Superior Acquisition, on September 30, 2011, we entered into an amendment (the “CTA Amendment”) to the Collateral Trust Agreement with each of the secured hedging counterparties and the administrative agent. The CTA Amendment modified the Collateral Trust Agreement so as to limit to $100.0 million the extent to which forward purchase contracts for physical commodities would be covered by, and secured under, the Collateral Trust Agreement. The CTA Amendment also eliminated the credit rating requirement with respect to forward purchase contract counterparties on physical commodities.

Equity Transactions

In February 2011, we satisfied the last of the earnings and distributions tests contained in our partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution on February 14, 2011. Two days following this quarterly distribution to our unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.

On February 24, 2011, we completed a public offering of our common units in which we sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by us from this offering (net of underwriting discounts, commissions and expenses but before our general partner’s capital contribution) were $92.3 million and were used to repay borrowings under our revolving credit facility. Underwriting discounts totaled $3.9 million. Our general partner contributed $2.0 million to retain its 2% general partner interest.

On September 8, 2011, we completed a public offering of our common units in which we sold 11,000,000 common units to the underwriters of the offering at a price of $18.00 per common unit. The proceeds received by us from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $189.5 million and were used to fund a portion of the purchase price of the Superior Acquisition. Underwriting discounts totaled $7.9 million. Our general partner contributed $4.0 million to retain its 2% general partner interest.

On October 13, 2011, the underwriters of our September 8, 2011 public offering elected to exercise a portion of their overallotment option. As a result, we sold an additional 750,000 common units to the underwriters at the offering price of $18.00 per unit, less the underwriting discount. The proceeds received by us from this offering (net of underwriting discounts, commissions and expenses but before our general partner’s capital contribution) were $12.9 million and were used to repay borrowings under our revolving credit facility. Underwriting discounts totaled $0.5 million. Our general partner contributed $0.3 million to retain its 2% general partner interest.

Seasonality Impacts on Liquidity

Asphalt demand is typically 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. This seasonality causes significant changes to our working capital requirements, which causes significant changes in borrowings under our revolving credit facility and our liquidity during such periods.

Contractual Obligations and Commercial Commitments

A summary of our total contractual cash obligations as of December 31, 2011 at current maturities is as follows:


			Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	(In thousands)
Operating Activities:
Interest on long-term debt at contractual rates (1)	$	436,443	$	65,389	$	121,000	$	118,804	$	131,250
Operating lease obligations (2)		82,611		21,416		32,250		14,909		14,036
Letters of credit (3)		230,040		230,040		—		—		—
Purchase commitments (4)		1,669,823		1,255,492		414,331		—		—
Pension obligations		25,134		3,634		8,500		6,900		6,100
Employment agreements (5)		1,652		413		1,239		—		—
Financing Activities:
Capital lease obligations		786		551		235		—		—
Long-term debt obligations, excluding capital lease obligations		600,000		—		—		—		600,000

Total obligations	$	3,046,489	$	1,576,935	$	577,555	$	140,613	$	751,386

(1)	Interest on long-term debt at contractual rates and maturities relates primarily to our 2019 Notes and revolving credit facility.

(2)	We have various operating leases primarily for the use of land, storage tanks, compressor stations, railcars, equipment, precious metals and office facilities that extend through June 2026.

(3)	Letters of credit primarily supporting crude oil purchases, precious metals leasing and hedging activities.

(4)	Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil and other feedstocks and finished products for resale from various suppliers based on current market prices at the time of delivery.

(5)	Annual compensation under the employment agreement of F. William Grube, chief executive officer and vice chairman of the board of our general partner.

In connection with the closing of the acquisition of Penreco on January 3, 2008, we entered into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, ConocoPhillips is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, we expect to purchase $74.0 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of December 31, 2011. This amount is not included in the table above. If the Base Volume is not supplied at any point during the first five years of the ten-year term, a penalty for each gallon of shortfall must be paid to us as liquidated damages.

Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Our discussion and analysis of results of operations and financial condition are based upon our consolidated financial statements for the years ended December 31, 2011, 2010 and 2009. These consolidated financial statements have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in those financial statements. On an ongoing basis, we evaluate estimates and base our estimates on historical experience and assumptions believed to be reasonable under the circumstances. Those estimates form the basis for our judgments that affect the amounts reported in the financial statements. Actual results could differ from our estimates under different assumptions or conditions. Our significant accounting policies, which may be affected by our estimates and assumptions, are more fully described in Note 2 to our consolidated financial statements in Item 8 “Financial Statements and Supplementary Data”. 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.


Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
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 the our normal billing and credit terms, all of the our obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms. We maintain an allowance for doubtful accounts for estimated losses in the collection of accounts receivable.	Our revenue recognition accounting methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the amount and timing of uncollectible accounts. We make estimates regarding the future ability of our customers to make required payments based on historical credit experience, the age of the accounts receivable balance, credit quality of our customers, current economic conditions and expected future trends that affect the customers’ ability to pay.	We have not made any material changes in the accounting methodology we use to measure doubtful accounts during the past three fiscal years. We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions we use to measure doubtful accounts. However, if actual results are not consistent with our estimates or assumptions, we may be exposed to losses or gains that could be material. A 10% change in our allowance for doubtful accounts at December 31, 2011 would have affected net income by approximately $0.1 million for the year ended December 31, 2011.
Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Inventories

The cost of inventories is determined using the last-in, first-out (LIFO) method and valued at the lower of cost or market. Inventoriable costs include crude oil and other feedstocks, labor and refining overhead costs.	Judgment is required in determining the market value of inventory, as the geographic location impacts market prices, and quoted market prices may not be available for the particular location of our inventory. 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. We review our inventory balances quarterly for excess inventory levels or obsolete inventory and write down, if necessary, the inventory to net realizable value.	We have not made any material changes in the accounting methodology we use to establish our markdown or inventory loss adjustments during the past three fiscal years. The replacement cost of our inventory, based on current market values, would have been $87.6 million and $55.9 million higher at December 31, 2011 and 2010, respectively. We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions we use to calculate our inventory. If commodity prices were to decrease by 10% below our December 31, 2011 inventory values, our net income would have negatively impacted by approximately $58.5 million.


Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Fair Value of Financial Instruments

In accordance with ASC 815-10, Derivatives and Hedging, we recognize all derivative instruments as either assets or liabilities at fair value on the consolidated balance sheets. Our derivative instruments, consisting of derivative assets of $58.5 million and derivative liabilities of $43.6 million as of December 31, 2011, are valued at Level 3 fair value measurement under ASC 820-10, Fair Value Measurements and Disclosures, depending upon the degree by which inputs are observable. We recorded realized and unrealized losses on derivative instruments of $7.9 million and $10.4 million, respectively, on our derivative instruments for the year ended December 31, 2011. The increase in the fair market value of our outstanding derivative instruments from a net liability of $32.8 million as of December 31, 2010 to a net asset of $14.9 million as of December 31, 2011 was due primarily to decreases in the forward market values of fuel products margins, or crack spreads, relative to our hedged products margins and settlement of derivatives in 2011 that resulted in realized losses. The decrease in the fair market value of our outstanding derivative instruments from a net asset of $26.1 million as of December 31, 2009 to a net liability of $32.8 million as of December 31, 2010 was due primarily to increases in the forward market values of cracks spreads relative to our hedged crack spreads and settlement of derivatives in 2010 that resulted in realized gains. In addition, we measure our investments associated with our non-contributory defined benefit plans (“Pension Plan”) on a recurring basis. As of December 31, 2011 our investments associated with our Pension Plan primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded and (iii) a commingled fund. The mutual funds are publically traded and market prices are readily available, thus these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of the shares held by the Pension Plan at year end. Approximately 61.8% of our derivative and pension assets and 100.0% of our derivative liabilities measured at fair value are classified as Level 3 in the fair value hierarchy as of December 31, 2011.	We utilize third party valuations and published market data to determine the fair value of these derivatives and thus do not directly rely on market indices. We perform an independent verification of the third party valuation statements to validate inputs for reasonableness and complete a comparison of implied crack spread mark-to-market valuations among our counterparties. Our derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of our derivative instruments are with counterparties that have long-term credit ratings of at least Baa1 and A- by Moody’s and S&P, respectively. To estimate the fair values of our derivative instruments, we use the market approach. Under this approach, the fair values of our derivative instruments for crude oil, gasoline, diesel, jet fuel, natural gas and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, we obtain this data through surveying our counterparties and performing various analytical tests to validate the data. In situations where we obtain inputs via quotes from our counterparties, we verify the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. We also include an adjustment for non-performance risk in the recognized measure of fair value of all of our derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When we are in a net asset position, we use our counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. We use our own peer group’s estimated CDS when we are in a net liability position. As a result of applying the applicable CDS, at December 31, 2011 our asset was reduced by approximately $1.3 million and our liability was reduced by approximately $0.2 million. As a result of applying the applicable CDS, at December 31, 2010, our net liability was reduced by approximately $0.7 million. Based on the use of various unobservable	We have not made any material changes in the accounting methodology we use to establish our pension or derivative estimates during the past three fiscal years. We have consistently applied these valuation techniques in all periods presented and believes we obtained the most accurate information available for the types of derivative instruments we hold. We believe that the fair values of our derivative instruments may diverge materially from the amounts currently recorded to fair value at settlement due to the volatility of commodity prices. Holding all other variables constant, we expect a $1 increase in the applicable commodity prices would change our recorded mark-to-market valuation by the following amounts based upon the volumes hedged as of December 31, 2011:
			In millions
		Crude oil swaps	$	16.5
		Diesel swaps	$	(5.3	)
		Jet fuel swaps	$	(6.9	)
		Gasoline swaps	$	(4.3	)
		Total	$	—
		A 100 basis point increase or decrease in the expected rate of return on pension assets reduces or increases the annual pension expense by approximately $0.2 million. A 100 basis point increase in the discount rate decreases the annual pension and other post retirement benefit expense by an aggregate of approximately $0.3 million. A 100 basis point decrease in the discount rate increases the annual pension and other post retirement benefit expense by an aggregate of approximately $0.3 million. Impacts due to assumption changes on the pension plan and post retirement benefit plan could be positive or negative depending on the direction of the change in rates. See Note 13 to our consolidated financial statements included in Item 8 “Financial Statements and Supplementary Data” for key assumptions and other information regarding our pension and post retirement benefit plans.

Description

Judgments and Uncertainties

Effect if Actual Results Differ
from Assumptions

inputs, principally non-performance risk and unobservable inputs in forward years for gasoline, jet fuel, diesel and natural gas, we have categorized these derivative instruments as Level 3.

Our weighted-average expected rate of return on pension assets was 6.50% at the end of 2011. The weighted-average discount rate was 4.59% for pension benefit obligations and 4.62% for other post retirement benefit obligations as of December 31, 2011. Changes in pension and other postretirement benefit expense and the recognized obligations may occur in the future as a result of a number of factors, including changes to any of these assumptions.

Recent Accounting Pronouncements

For a summary of recently issued and adopted accounting standards applicable to us, see Note 2 to our consolidated financial statements included in Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Consistent with prior years, both our profitability and our cash flows are affected by volatility in prevailing crude oil, gasoline, diesel, jet fuel and natural gas prices. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with the cost of crude oil and natural gas and sales prices of our fuel products.

Crude Oil Price Volatility and Hedging Policy

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 $11.3 million and our fuel product segment cost of sales by $12.8 million based on our sales volumes for 2011 and would change our specialty product segment cost of sales by $10.8 million and our fuel product segment cost of sales by $9.6 million based on our sales volumes for 2010.

Because we typically do not set prices for our specialty products in advance of our crude oil purchases, we can generally take into account the cost of crude oil in setting specialty products prices. However, as evidenced during the prior three years when crude oil prices ranged from a low of approximately $34 per barrel to a high of approximately $114 per barrel, we are not always able to adjust our selling prices as quickly as increases in the price of crude oil. Due to this lack of correlation between our specialty products selling prices and crude oil in periods of high volatility from time to time, we further manage our exposure to fluctuations in crude oil prices in our specialty products segment through the use of derivative instruments, which can include both swaps and options, generally executed in the over-the-counter (OTC) market. Our policy is generally to enter into crude oil derivative contracts from time to time that mitigate our exposure to price risk associated with crude oil purchases related to our specialty products production (for up to 70% of expected purchases). While our policy generally requires that these derivative instruments be short term in nature and expire within three to nine months from execution, we may execute derivative contracts for up to two years forward, if a change in the price risks

supports lengthening our position. We had no crude oil swaps or options outstanding in our specialty products segment as of December 31, 2011. Our fuel products sales are based on market prices at the time of sale. Accordingly, in conjunction with our fuel products hedging policy discussed below, we enter into crude oil swap contracts related to our fuel products segment for a period no greater than five years forward and for no more than 75% of our crude oil purchases used in fuels production.

Natural Gas Price Volatility and Hedging Policy

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 $4.9 million and $4.0 million based on our results for the years ended December 31, 2011 and 2010, respectively.

We enter into derivative contracts to manage our exposure to natural gas prices. Our policy is generally to enter into natural gas derivative contracts to hedge no more than 75% of our anticipated natural gas requirement for a period no longer than three years forward.

Fuel Products Selling Price Volatility and Hedging Policy

We are exposed to significant fluctuations in the prices of gasoline, diesel and jet fuel. Given the historical volatility of gasoline, diesel and jet fuel prices, this exposure can significantly impact sales and gross profit. Holding all other variables constant, and excluding the impact of our current hedges, we expect that a $1 change in the per barrel selling prices of gasoline, diesel and jet fuel would change our fuel products segment sales by $12.8 million and $9.6 million based on our results for the years ended December 31, 2011 and 2010, respectively.

In order to manage our exposure to changes in gasoline, diesel and jet fuel selling prices, our policy is generally to enter into derivative contracts to hedge our fuel products sales for a period no longer than five years forward and for no more than 75% of forecasted fuel products sales on average for each fiscal year, which is consistent with our crude oil purchase hedging policy for our fuel products segment discussed above. We believe this policy lessens the volatility of our cash flows. As of December 31, 2011, we estimate we were approximately 55% hedged for the forward 12 month period and approximately 39% hedged for the forward 24 month period for such fuel product sales. We are currently hedging for calendar years 2012, 2013 and 2014, with no derivative instruments currently outstanding for calendar years 2015 or 2016.

The unrealized gain or loss on derivatives at a given point in time is not necessarily indicative of the results realized when such contracts mature. The increase in the fair market value of our outstanding derivative instruments from a net liability of $32.8 million as of December 31, 2010 to a net asset of $14.9 million as of December 31, 2011 was due primarily to decreases in the forward market values of fuel products margins, or crack spreads, relative to our hedged products margins and settlement of derivatives in 2011 that resulted in realized losses. The decrease in the fair market value of our outstanding derivative instruments from a net asset of $26.1 million as of December 31, 2009 to a net liability of $32.8 million as of December 31, 2010 was due primarily to increases in the forward market values of cracks spreads relative to our hedged crack spreads and settlement of derivatives in 2010 that resulted in realized gains. Please read Note 2 — Summary of Significant Accounting Policies — Derivatives in the notes to our consolidated financial statements under Item 8 “Financial Statements and Supplementary Data” for a discussion of the accounting treatment for the various types of derivative transactions, and a further discussion of our hedging policies.

Pension Assets Volatility and Investment Policy

Our Pension Plan assets are also subject to volatility that can be caused by fluctuation in general economic conditions. Plan assets are invested by the Plan’s fiduciaries, which direct investments according to specific

policies. Our income statement is currently shielded from volatility in plan assets due to the way accounting standards are applied for pension plans, although favorable or unfavorable investment performance over the long term will impact our pension expense if it deviates from our assumption related to the future rate of return. Please read Note 13 — “Employee Benefit Plans” in the notes to our consolidated financial statements under Item 8 “Financial Statements and Supplementary Data” for a further discussion of our investment policies.

Interest Rate Risk and Existing Interest Rate Derivative Instruments

Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates, which is consistent with prior years. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates. Historically, our policy has been to enter into interest rate swap agreements to hedge up to 75% of its interest rate risk related to variable rate debt. With the issuances of the 2019 Notes, which constitute fixed rate debt, we do not expect to enter into additional hedges (beyond those listed below) to fix our interest rates. The following table summarizes our outstanding interest rate swaps as of December 31, 2011.


Interest Rate Swap Contract	Effective Date	Maturity Date	Notional Amount	Swap Contract	Weighted Average Fixed Rate
2006 Swap (1)	June 9, 2006	December 10, 2012	$40,056	3 Month LIBOR	5.44%
2006 Swap (1)	December 10, 2007	December 10, 2012	40,056	3 Month LIBOR plus 1.98% spread	5.44%
2010 Swap (2)	February 15, 2011	February 15, 2012	100,000	3 Month LIBOR	2.03%

(1)

Due to the repayment of $19,000 of the outstanding balance of our then existing term loan facility in August 2007 and subsequent refinancing of the remaining term loan balance, this interest rate swap contract was not designated as a cash flow hedge of the future payment of interest. The entire change in the fair value of this interest rate swap was recorded to unrealized loss on derivative instruments in the consolidated statements of operations. In the first quarter of 2008, we fixed our unrealized loss on this interest rate swap derivative instrument by entering into an offsetting interest rate swap expiring December 2012, which is not designated as a cash flow hedge. The notional amount is based upon a fixed schedule set forth in the confirmation, and the amount disclosed is notional amount as of December 31, 2011.

(2)

Due to the repayment of the variable rate prior term loan in April 2011 with proceeds from the 2019 Notes issued in April 2011, this interest rate swap was discontinued as a cash flow hedge for the future payment of interest. As a result we reclassified approximately $0.5 million into unrealized loss and recognized $1.3 million of realized loss on derivative instruments for the year ended December 31, 2011 in the consolidated statements of operations.

We are exposed to market risk from fluctuations in interest rates only on borrowings under our revolving credit facility. We have an $850.0 million revolving credit facility as of December 31, 2011, with borrowings bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had no borrowings outstanding under this facility as of December 31, 2011.

We had a $375.0 million revolving credit facility as of December 31, 2010, with borrowings bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had borrowings of $10.8 million outstanding under this facility as of December 31, 2010, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin.

Existing Commodity Derivative Instruments

We are also subject to the risk that the crude oil and fuel products derivatives we use to hedge against fuel products crack spread volatility do not provide adequate protection against volatility. All of the crude oil derivatives in our hedge portfolio are based on the market price of NYMEX WTI and the fuel products derivatives are all based on U.S. Gulf Coast market prices. In recent periods, the spread between NYMEX WTI and other crude oil indices (specifically LLS and Brent on which a portion of our crude oil purchases are based) has widened, which has led to more of our crude oil hedges not being as effective. To the extent the spread between NYMEX WTI and the other crude oil indices stays at current levels or continues to widen, our hedges could continue to become less effective and not provide adequate protection against crude oil price volatility.

Fuel Products Segment

As a result of our fuel products hedging activity, we recorded a loss of $211.8 million and a gain of $108.4 million, to sales and cost of sales, respectively, in the consolidated statements of operations for 2011. As of December 31, 2011 we had not provided any cash margin in credit support to our hedging counterparties.

The following tables provide a summary of our derivative instruments related to our fuel products segment as of December 31, 2011, which we disclose in Note 8 under Item 8 “Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements,” all of which are designated as cash flow hedges:


Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased		BPD		Average Swap ($/Bbl)
First Quarter 2012		2,866,500		31,500	$	85.34
Second Quarter 2012		2,775,500		30,500		84.83
Third Quarter 2012		2,852,000		31,000		84.83
Fourth Quarter 2012		2,622,000		28,500		86.73
Calendar Year 2013		4,420,000		12,110		97.93
Calendar Year 2014		1,000,000		2,740		90.55

Totals		16,536,000
Average price					$	89.07

Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2012		546,000		6,000	$	118.07
Second Quarter 2012		819,000		9,000		110.09
Third Quarter 2012		1,150,000		12,500		105.48
Fourth Quarter 2012		966,000		10,500		110.11
Calendar Year 2013		1,831,000		5,016		123.20

Totals		5,312,000
Average price					$	114.44

Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2012		1,274,000		14,000	$	97.97
Second Quarter 2012		1,046,500		11,500		98.47
Third Quarter 2012		782,000		8,500		99.78
Fourth Quarter 2012		736,000		8,000		104.79
Calendar Year 2013		2,044,000		5,600		125.13
Calendar Year 2014		1,000,000		2,740		115.56

Totals		6,882,500
Average price					$	109.60

Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2012		1,046,500		11,500	$	100.72
Second Quarter 2012		910,000		10,000		102.48
Third Quarter 2012		920,000		10,000		102.48
Fourth Quarter 2012		920,000		10,000		102.48
Calendar Year 2013		545,000		1,493		107.11

Totals		4,341,500
Average price					$	102.63

The following table provides a summary of these derivatives and implied crack spreads for the crude oil, diesel, jet fuel and gasoline swaps disclosed above, all of which are designated as cash flow hedges.


Swap Contracts by Expiration Dates	Barrels Sold		BPD		Implied Crack Spread ($/Bbl)
First Quarter 2012		2,866,500		31,500	$	17.46
Second Quarter 2012		2,775,500		30,500		18.39
Third Quarter 2012		2,852,000		31,000		18.12
Fourth Quarter 2012		2,622,000		28,500		19.20
Calendar Year 2013		4,420,000		12,110		24.18
Calendar Year 2014		1,000,000		2,740		25.01

Totals		16,536,000
Average price					$	20.26

Specialty Products Segment

At December 31, 2011, we had no derivative positions outstanding related to crude oil purchases in our specialty products segment.

The following table provides a summary of our natural gas derivatives related to natural gas purchases in our specialty products segment as of December 31, 2011, which we disclose in Note 8 under Item 8 “Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements,” none of which were designated as cash flow hedges.


Natural Gas Swap Contracts by Expiration Dates	MMBtu		$/MMBtu
First Quarter 2012		1,200,000	$	3.90
Second Quarter 2012		1,200,000		3.93
Third Quarter 2012		1,200,000		4.03
Fourth Quarter 2012		600,000		4.08

Totals		4,200,000
Average price			$	3.97

Item 8.

Financial Statements and Supplementary Data

Management’s Report on Internal Control Over Financial Reporting

The management of Calumet Specialty Products Partners, L.P. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Calumet Superior, LLC, which is included in the Company’s 2011 consolidated financial statements and constituted $456,027,000 of the Company’s total assets as of December 31, 2011 and $341,152,000 of the Company’s sales for the year then ended. Management also did not perform an evaluation of the internal control over financial reporting of Calumet Superior, LLC.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, based on criteria for effective internal control over financial reporting described in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, we have concluded that internal control over financial reporting was effective as of December 31, 2011.

Ernst & Young LLP, an independent registered public accounting firm, has audited the Company’s consolidated financial statements and has issued an attestation report on the effectiveness of internal control over financial reporting which appears on the following page.

/s/ F. William Grube

F. William Grube

Chief Executive Officer, Director and

Vice Chairman of the Board of Calumet GP, LLC

February 29, 2012

/s/ R. Patrick Murray, II

R. Patrick Murray, II

Vice President, Chief Financial Officer and

Secretary of Calumet GP, LLC

February 29, 2012

Report of Independent Registered Public Accounting Firm

The Board of Directors of Calumet GP, LLC

General Partner of Calumet Specialty Products Partners, L.P.

We have audited Calumet Specialty Products Partners, L.P.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Calumet Specialty Products Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Calumet Superior, LLC, which is included in the 2011 consolidated financial statements of Calumet Specialty Products Partners, L.P. and constituted $456,027,000 of total assets as of December 31, 2011 and $341,152,000 of sales for the year then ended. Our audit of internal control over financial reporting of Calumet Specialty Products Partners, L.P. also did not include an evaluation of the internal control over financial reporting of Calumet Superior, LLC.

In our opinion, Calumet Specialty Products Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Calumet Specialty Products Partners, L.P. as of December 31, 2011 and 2010 and the related statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2011 of Calumet Specialty Products Partners, L.P. and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Indianapolis, Indiana

February 29, 2012

Report of Independent Registered Public Accounting Firm

The Board of Directors of Calumet GP, LLC

General Partner of Calumet Specialty Products Partners, L.P.

We have audited the accompanying consolidated balance sheets of Calumet Specialty Products Partners, L.P. as of December 31, 2011 and 2010, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Calumet Specialty Products Partners, L.P. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Calumet Specialty Products Partners, L.P.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Indianapolis, Indiana

February 29, 2012

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS


	Year Ended December 31,
	2011		2010
	(In thousands, except
	unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	64	$	37
Accounts receivable:
Trade, less allowance for doubtful accounts of $925 and $633, respectively		208,928		157,185
Other		3,137		776

		212,065		157,961

Inventories		497,740		147,110
Derivative assets		58,502		—
Prepaid expenses and other current assets		8,179		1,909
Deposits		2,094		2,094

Total current assets		778,644		309,111
Property, plant and equipment, net		842,101		612,433
Goodwill		48,335		48,335
Other intangible assets, net		22,675		29,666
Other noncurrent assets, net		40,303		17,127

Total assets	$	1,732,058	$	1,016,672

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	311,359	$	146,730
Accounts payable — related parties		1,967		27,985
Accrued salaries, wages and benefits		13,481		7,559
Taxes payable		13,068		7,174
Other current liabilities		4,600		16,605
Current portion of long-term debt		551		4,844
Derivative liabilities		43,581		32,814

Total current liabilities		388,607		243,711
Pension and postretirement benefit obligations		26,957		9,168
Other long-term liabilities		1,055		1,083
Long-term debt, less current portion		586,539		364,431

Total liabilities		1,003,158		618,393

Commitments and contingencies
Partners’ capital:
Limited partners’ interest (51,529,778 units and 35,279,778 units, issued and outstanding at December 31, 2011 and 2010, respectively)		666,471		407,773
General partner’s interest		23,902		18,125
Accumulated other comprehensive income (loss)		38,527		(27,619	)

Total partners’ capital		728,900		398,279

Total liabilities and partners’ capital	$	1,732,058	$	1,016,672

See accompanying notes to consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2011			2010			2009
	(In thousands, except per unit data)
Sales	$	3,134,923		$	2,190,752		$	1,846,600
Cost of sales		2,860,793			1,992,003			1,673,498

Gross profit		274,130			198,749			173,102

Operating costs and expenses:
Selling, general and administrative		50,836			35,224			32,570
Transportation		94,187			85,471			67,967
Taxes other than income taxes		5,661			4,601			3,839
Insurance recoveries		(8,698	)		—			—
Other		6,852			1,963			1,366

Operating income		125,292			71,490			67,360

Other income (expense):
Interest expense		(48,747	)		(30,497	)		(33,573	)
Debt extinguishment costs		(15,130	)		—			—
Realized gain (loss) on derivative instruments		(7,909	)		(7,704	)		8,342
Unrealized gain (loss) on derivative instruments		(10,383	)		(15,843	)		23,736
Other		842			(147	)		(3,929	)

Total other expense		(81,327	)		(54,191	)		(5,424	)

Income before income taxes		43,965			17,299			61,936
Income tax expense		929			598			151

Net income	$	43,036		$	16,701		$	61,785

Allocation of net income:
Net income	$	43,036		$	16,701		$	61,785
Less:
General partner’s interest in net income		861			334			1,236
General partner’s incentive distribution rights		322			—			—

Net income available to limited partners		41,853			16,367			60,549
Weighted average limited partner units outstanding:
Basic		42,599			35,335			32,372
Diluted		42,644			35,351			32,372
Limited partners’ interest basic and diluted net income per unit	$	0.98		$	0.46		$	1.87
Cash distributions declared per limited partner unit	$	2.00		$	1.84		$	1.81

See accompanying notes to consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Accumulated Other Comprehensive Income (Loss)			Partners’ Capital									Total
				General Partner			Limited Partners
				General Partner			Common			Subordinated
	(In thousands)
Balance at January 1, 2009	$	55,566		$	17,933		$	363,935		$	35,778		$	473,212
Comprehensive income:
Net income					1,236			38,094			22,455			61,785
Cash flow hedge gain reclassified to net income		(15,068	)											(15,068	)
Change in fair value of cash flow hedges		(29,371	)											(29,371	)
Defined benefit pension and retiree health benefit plans		1,517												1,517

Comprehensive income														18,863
Proceeds from public offering of common units, net								51,225						51,225
Contribution from Calumet GP, LLC					1,102									1,102
Units repurchased for phantom unit grants								(164	)					(164	)
Amortization of vested phantom units								367						367
Distributions to partners					(1,184	)		(34,555	)		(23,519	)		(59,258	)

Balance at December 31, 2009	$	12,644		$	19,087		$	418,902		$	34,714		$	485,347

Comprehensive loss:
Net income					334			10,305			6,062			16,701
Cash flow hedge gain reclassified to net income		(11,104	)											(11,104	)
Change in fair value of cash flow hedges		(29,015	)											(29,015	)
Defined benefit pension and retiree health benefit plans		(144	)											(144	)

Comprehensive loss														(23,562	)
Proceeds from public offering of common units, net								793						793
Contribution from Calumet GP, LLC					18									18
Units repurchased for phantom unit grants								(248	)					(248	)
Amortization of vested phantom units								1,670						1,670
Distributions to partners					(1,314	)		(40,579	)		(23,846	)		(65,739	)

Balance at December 31, 2010	$	(27,619	)	$	18,125		$	390,843		$	16,930		$	398,279

Comprehensive income:
Net income					1,183			41,853						43,036
Cash flow hedge loss reclassified to net income		104,020												104,020
Change in fair value of cash flow hedges		(34,160	)											(34,160	)
Defined benefit pension and retiree health benefit plans		(3,714	)											(3,714	)

Comprehensive income														109,182
Units repurchased for phantom unit grants								(620	)					(620	)
Issuance of phantom units								787						787
Amortization of vested phantom units								3,027						3,027
Subordinated unit conversion								10,789			(10,789	)		—
Proceeds from public offerings of common units, net								294,702						294,702
Contributions from Calumet GP, LLC					6,286									6,286
Distributions to partners					(1,692	)		(74,910	)		(6,141	)		(82,743	)

Balance at December 31, 2011	$	38,527		$	23,902		$	666,471		$	—		$	728,900

See accompanying notes to consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Operating activities
Net income	$	43,036		$	16,701		$	61,785
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		63,009			60,287			61,735
Amortization of turnaround costs		11,384			10,006			7,256
Non-cash interest expense		3,728			3,864			3,672
Provision for doubtful accounts		380			74			(916	)
Non-cash debt extinguishment costs		14,401			—			—
Unrealized (gain) loss on derivative instruments		10,383			15,843			(23,736	)
Loss on disposal of fixed assets		1,525			239			4,455
Non-cash equity based compensation		4,895			1,540			1,075
Other non-cash activities		74			142			180
Changes in assets and liabilities:
Accounts receivable		(54,484	)		(35,267	)		(12,296	)
Inventories		(167,028	)		(9,860	)		(18,726	)
Prepaid expenses and other current assets		(425	)		(98	)		(8	)
Derivative activity		11,742			2,990			8,531
Turnaround costs		(14,052	)		(10,684	)		(6,890	)
Deposits		—			4,767			(2,840	)
Other assets		(426	)		(2,006	)		1
Accounts payable		138,611			64,739			15,951
Accrued salaries, wages and benefits		4,066			1,189			(902	)
Taxes payable		5,894			(377	)		718
Other liabilities		(12,033	)		10,463			576
Pension and postretirement benefit obligations		(902	)		(409	)		1,233

Net cash provided by operating activities		63,778			134,143			100,854
Investing activities
Additions to property, plant and equipment		(49,478	)		(35,001	)		(23,521	)
Proceeds from insurance recoveries — equipment		1,942			—			—
Superior Acquisition		(413,173	)		—			—
Proceeds from sale of equipment		285			242			807

Net cash used in investing activities		(460,424	)		(34,759	)		(22,714	)
Financing activities
Proceeds from borrowings — revolving credit facility		1,598,680			1,015,485			805,361
Repayments of borrowings — revolving credit facility		(1,609,512	)		(1,044,553	)		(868,000	)
Repayments of borrowings — term loan credit facility		(367,385	)		(3,850	)		(3,850	)
Payments on capital lease obligation		(1,069	)		(1,302	)		(1,542	)
Proceeds from public offerings of common units, net		294,702			793			51,225
Proceeds from 2019 senior notes offerings		586,000			—			—
Debt issuance costs		(27,666	)		—			—
Contributions from Calumet GP, LLC		6,286			18			1,102
Change in bank overdraft		—			—			(3,013	)
Common units repurchased for vested phantom unit grants		(620	)		(248	)		(164	)
Distributions to partners		(82,743	)		(65,739	)		(59,258	)

Net cash provided by (used in) financing activities		396,673			(99,396	)		(78,139	)

Net increase (decrease) in cash and cash equivalents		27			(12	)		1
Cash and cash equivalents at beginning of year		37			49			48

Cash and cash equivalents at end of year	$	64		$	37		$	49

Supplemental disclosure of cash flow information
Interest paid, net of capitalized interest	$	37,856		$	26,389		$	30,343

Income taxes paid	$	568		$	188		$	161

Supplemental disclosure of noncash financing and investing activities
Equipment acquired under capital lease	$	—		$	—		$	1,659

See accompanying notes to consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per unit data)

1.	Description of the Business

Calumet Specialty Products Partners, L.P. (the “Company”) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of December 31, 2011, the Company had 51,529,778 limited partner common units and 1,051,628 general partner units outstanding. The number of common units outstanding includes 13,066,000 common units that converted from subordinated units on February 16, 2011. There are no longer any subordinated units outstanding. Refer to Note 11 for additional information. The general partner owns 2% of the Company and incentive distribution rights (as defined in the partnership agreement), while the remaining 98% is owned by limited partners. The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, asphalt and waxes and fuel and fuel related products including gasoline, diesel and jet fuel. The Company owns facilities located in Shreveport, Louisiana (“Shreveport”), Superior, Wisconsin (“Superior”), Princeton, Louisiana (“Princeton”), Cotton Valley, Louisiana (“Cotton Valley”), Karns City, Pennsylvania (“Karns City”) and Dickinson, Texas (“Dickinson”), and terminals located in Burnham, Illinois (“Burnham”), Rhinelander, Wisconsin (“Rhinelander”), Crookston, Minnesota (“Crookston”) and Proctor, Minnesota (“Duluth”).

2.	Summary of Significant Accounting Policies

Consolidation

The consolidated financial statements of the Company include the accounts of Calumet Specialty Products Partners, L.P. and its wholly-owned operating subsidiaries, Calumet Lubricants Co., Limited Partnership, Calumet Sales Company Incorporated, Calumet Penreco, LLC, Calumet Shreveport, LLC, Calumet Superior, LLC, Calumet Missouri, LLC and Calumet Finance Corp. Calumet Shreveport, LLC’s wholly-owned operating subsidiaries are Calumet Shreveport Fuels, LLC and Calumet Shreveport Lubricants & Waxes, LLC. All intercompany transactions and accounts have been eliminated.

Use of Estimates

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

Cash and Cash Equivalents

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

Inventories

The cost of inventories is determined using the last-in, first-out (LIFO) method. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Inventories consist of the following:


	December 31,
	2011		2010
Raw materials	$	105,802	$	12,885
Work in process		91,763		49,006
Finished goods		300,175		85,219

	$	497,740	$	147,110

The replacement cost of these inventories, based on current market values, would have been $87,635 and $55,855 higher as of December 31, 2011 and 2010, respectively. During the years ended December 31, 2011, 2010 and 2009, the Company recorded $5,166, $13,661 and $18,375, respectively, of gains in cost of sales in the consolidated statements of operations due to the liquidation of lower cost inventory layers.

Accounts Receivable

The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are generally due within 30 to 45 days from date of invoice for the specialty products segment and 10 days from date of invoice for the fuel products segment. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay. The activity in the allowance for doubtful accounts was as follows:


	December 31,
	2011			2010			2009
Beginning balance	$	633		$	801		$	2,121
Provision		380			(61	)		(916	)
Recoveries		—			—			11
Write-offs, net		(88	)		(107	)		(415	)

Ending balance	$	925		$	633		$	801

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. Assets under capital leases are amortized over the lesser of the useful life of the asset or the term of the lease.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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


	December 31,
	2011			2010
Land	$	8,857		$	3,249
Buildings and improvements (10 to 40 years)		19,729			6,848
Machinery and equipment (10 to 20 years)		1,012,318			770,973
Furniture and fixtures (5 to 10 years)		5,732			3,646
Assets under capital leases (1 to 4 years)		4,201			4,201
Construction-in-progress		22,945			7,673

		1,073,782			796,590
Less accumulated depreciation		(231,681	)		(184,157	)

	$	842,101		$	612,433

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

During 2011, 2010 and 2009, the Company incurred $49,339, $30,886 and $34,170, respectively, of interest expense of which $592, $389 and $597, respectively, was capitalized as a component of property, plant and equipment.

The Company has not recorded an asset retirement obligation as of December 31, 2011 or 2010 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.

Depreciation expense included $1,050, $1,050 and $1,074 for the years ended 2011, 2010 and 2009, respectively, related to the Company’s capital lease assets. During the years ended December 31, 2011, 2010 and 2009, the Company recorded $55,536, $51,365 and $50,327, respectively, of depreciation expense on its property, plant and equipment.

The Company capitalizes the cost of computer software developed or obtained for internal use. Capitalized software is amortized using the straight-line method over three years. As of December 31, 2011, $3,653 of costs have been capitalized and are included in construction in progress.

Goodwill

Goodwill represents the excess of purchase price over fair value of the net assets acquired in the acquisition of Penreco on January 3, 2008. The Company reviews goodwill for impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable in accordance with ASC 350, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment, (“ASU 2011-08”). In September 2011, the FASB issued ASU 2011-08 which amends the rules for testing goodwill for impairment. Under the new rules, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The Company early adopted ASU 2011-08 for the October 1, 2011 annual goodwill impairment test.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

In assessing the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company assesses relevant events and circumstances that may impact the fair value and the carrying amount of the reporting unit. The identification of relevant events and circumstances and how these may impact a reporting unit’s fair value or carrying amount involve significant judgments and assumptions. The judgment and assumptions include the identification of macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and Company specific events and making the assessment on whether each relevant factor will impact the impairment test positively or negatively and the magnitude of any such impact.

If the Company’s qualitative assessment concludes that it is probable that an impairment exists or the Company skips the qualitative assessment then the Company needs to perform a quantitative assessment. In the first step of the quantitative assessment, the Company’s assets and liabilities, including existing goodwill and other intangible assets, are assigned to the identified reporting units to determine the carrying value of the reporting units. If the carrying value of a reporting unit is in excess of its fair value, an impairment may exist, and the Company must perform an impairment analysis, in which the implied fair value of the goodwill is compared to its carrying value to determine the impairment charge, if any. Based on the results of the qualitative assessment of the reporting units, the Company believes it is more likely than not that the fair value of the reporting unit is greater than its carrying amount.

The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation, and risks associated with the reporting unit.

Based on the results of the qualitative assessment of the reporting unit, the Company believes it is more likely than not that the fair value of the specialty products reporting unit is greater than its carrying amount. No impairment was recognized in 2011, 2010 or 2009.

Other Intangible Assets

Other intangible assets primarily consist of supply agreements, customer relationships, non-compete agreements and patents acquired in the acquisition of Penreco on January 3, 2008. The majority of these assets are being amortized using the discounted estimated future cash flows method over the term of the related agreements. Intangible assets associated with customer relationships of Penreco are being amortized using the discounted estimated future cash flows method based upon an assumed rate of annual customer attrition. For more information, refer to Note 5.

Impairment of Long-Lived Assets

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

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Revenue Recognition

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

Concentrations of Credit Risk

The Company performs periodic credit evaluations of its customers’ financial condition and in some instances requires cash in advance or letters of credit prior to shipment for domestic orders. For international orders, letters of credit are generally required and the Company maintains insurance policies which cover certain export orders. The Company maintains an allowance for doubtful customer accounts for estimated losses resulting from the inability of its customers to make required payments. The allowance for doubtful accounts is developed based on several factors including historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay, which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, from time to time the Company has significant derivative assets with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s ASC 820-10, Fair Value Measurements and Disclosures, valuations to determine the impact of `counterparty credit risk on the valuation of its derivative instruments.

Income Taxes

The Company, as a partnership, is generally not liable for federal income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries. However, Calumet Sales Company Incorporated (“Calumet Sales Company”), a wholly-owned subsidiary of the Company, is a corporation and as a result, is liable for income taxes on its earnings. Income taxes on the earnings of the Company, with the exception of Calumet Sales Company, are the responsibility of its partners, with earnings of the Company included in partners’ earnings.

In the event that the Company’s taxable income did not meet certain qualification requirements, the Company would be taxed as a corporation. Interest and penalties related to income taxes, if any, would be recorded in income tax expense. The Company had no unrecognized tax benefits as of December 31, 2011 and 2010.

Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the Company’s partnership agreement. Individual partners have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each partner’s tax accounting, which is partially dependent upon the partner’s tax position, differs from the accounting followed in the consolidated financial statements. Accordingly, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in the partnership is not readily available.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Excise and Sales Taxes

The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of its products to non-exempt customers. Excise taxes and sales taxes assessed and collected from customers are recorded on a net basis within sales in the Company’s consolidated statements of operations.

Derivatives

The Company is exposed to fluctuations in the price of numerous commodities like crude oil, its principal raw material, and natural gas as well as the sales prices of gasoline, diesel and jet fuel. Given the historical volatility of commodity prices, these fluctuations can significantly impact sales, gross profit and net income. Therefore, the Company utilizes derivative instruments primarily to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas and the sale of fuel products. The Company employs various hedging strategies, and does not hold or issue derivative instruments for trading purposes. For further information, please refer to Note 8.

Other Noncurrent Assets

Other noncurrent assets include deferred debt issuance costs and turnaround costs. Deferred debt issuance costs were $26,374 and $5,812 as of December 31, 2011 and 2010, respectively, and are being amortized by the effective interest rate method or on a straight-line basis, which approximates the effective interest rate method, over the lives of the related debt instruments. These amounts are net of accumulated amortization of $1,996 and $5,246 at December 31, 2011 and 2010, respectively. For further information on deferred debt issuance costs, please read Note 7.

Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $12,471 and $9,803 as of December 31, 2011 and 2010, respectively. The Company capitalizes these costs and amortizes the costs on a straight-line basis over the lives of the turnaround assets. These amounts are net of accumulated amortization of $12,538 and $11,694 at December 31, 2011 and 2010, respectively.

Earnings per Unit

The Company calculates earnings per unit under ASC 260-10, Earnings per Share. The Company treats incentive distribution rights (IDRs) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to receive IDRs. Also, the undistributed earnings are allocated to the partnership interests based on the allocation of earnings to the Company’s partners’ capital accounts as specified in the Company’s partnership agreement. When distributions exceed earnings, net income is reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in its partnership agreement.

Shipping and Handling Costs

The Company complies with ASC 605-45, Revenue Recognition — Principal Agent Considerations. ASC 605-45 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 to be disclosed if classified elsewhere. The Company has reflected $94,187, $85,471 and $67,967, respectively, for the years ended December 31, 2011, 2010, and 2009, in transportation expense in the consolidated statements of operations, the majority of which is billed to customers.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Business Combinations

The Company accounts for acquisitions in accordance with ASC 805, Business Combinations. Amounts paid for each acquisition are allocated to the assets acquired and liabilities assumed based on their fair values at the date of acquisition. The Company allocates the purchase price in excess of the fair value of the net tangible assets acquired to identifiable intangible assets based on detailed valuations that use certain information and assumptions provided by management. The Company allocates any excess purchase price over the fair value of the net tangible and intangible assets acquired to goodwill.

New Accounting Pronouncements

In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures About Fair Value Measurements (“ASU 2010-06”), which amends ASC No. 820, Fair Value Measurements and Disclosures, to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. ASU 2010-06 also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. ASU 2010-06 is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for the requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a gross basis, which is effective for fiscal years (including interim periods) beginning after December 15, 2010. Effective January 1, 2010, the Company adopted ASU 2010-06 standard relating to disclosures about transfers in and out of Level 1 and 2 and the inputs and valuation techniques used to measure fair value. Effective January 1, 2011, the Company adopted ASU 2010-06 standard relating to the requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a gross basis. The adoption of ASU 2010-06 did not have a material impact on the Company’s consolidated financial statements.

In December 2010, the FASB issued ASU No. 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (“ASU 2010-28”), which amends ASC No. 830, Intangibles — Goodwill and Other to modify Step 1 of the evaluation of goodwill impairment for reporting units with zero or negative carrying amounts to require that Step 2 of the impairment test be performed to measure the amount of any impairment loss when it is more likely than not that a goodwill impairment exits. ASU 2010-28 is effective for fiscal years (including interim periods) beginning after December 15, 2010, with early adoption not permitted. The adoption of ASU 2010-28 in 2011 did not have a material impact on the Company’s consolidated financial statements.

In December 2010, the FASB issued ASU No. 2010-29, Disclosures of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”), which amends ASC No. 805, Business Combinations, to expand the requirements for supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010, and should be applied prospectively. The adoption of ASU 2010-29 in 2011 required additional disclosures in the Company’s financial statements, but did not have a material impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the FASB’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. ASU 2011-04 is effective for the first reporting period (including interim periods) beginning after December 15, 2011. The Company is currently evaluating the impact of the adoption of ASU 2011-04 on its consolidated financial statements.

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“ASU 2011-05”), which amends current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income as part of the statement of partners’ capital. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. In December 2011, the FASB issued ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12), which indefinitely defers the requirement in ASU 2011-05 to present reclassification adjustments out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which other comprehensive income is presented. During the deferral period, the existing requirements in U.S. GAAP for the presentation of reclassification adjustments must continue to be followed. Amendments to ASU 2011-05, as superseded by ASU 2011-12, are effective for fiscal years (including interim periods) beginning after December 15, 2011 and are to be applied retrospectively, with early adoption permitted. The Company is currently evaluating the impact of the adoption of the guidance on its consolidated financial statements.

In September 2011, the FASB issued ASU No. 2011-08, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). ASU 2011-08 allows companies to have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If after considering the totality of events and circumstances an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, however, early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011. The Company early adopted ASU 2011-08 for the October 1, 2011 annual goodwill impairment test. The adoption of ASU 2011-08 in 2011 did not have a material impact on the Company’s consolidated financial statements.

3.	Superior Acquisition

On September 30, 2011, the Company completed the acquisition of the Superior, Wisconsin refinery and associated operating assets and inventories and related business of Murphy Oil Corporation (“Murphy Oil”) for aggregate consideration of approximately $413,173 (“Superior Acquisition”). The Superior Acquisition was financed by a combination of (i) net proceeds of $193,538 from the Company’s September 2011 public offering of common units (including the general partner’s contribution and excluding the over-allotment option exercised), (ii) net proceeds of $180,296 from the Company’s September 2011 private placement of 9³/8% senior notes due May 1, 2019 and (iii) borrowings under the revolving credit facility. The Company acquired the following assets (collectively, the “Superior Business”):

•

Murphy Oil’s refinery located in Superior, Wisconsin and associated inventories;

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

•

Murphy Oil’s “SPUR” branded gasoline wholesale business and related assets.

The Superior refinery produces gasoline, diesel, asphalt, heavy fuel oils and specialty petroleum products that are primarily marketed in the Upper Midwest region of the U.S. and in Canada. The Superior wholesale marketing business transports products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through its leased and owned product terminals. The Superior wholesale business also sells gasoline wholesale to SPUR branded gas stations, which are owned and operated by independent franchisees.

The Company believes the Superior Acquisition provides greater scale, geographic diversity and development potential to its refining business.

As a result of the Superior Acquisition on September 30, 2011, the assets and certain liabilities previously held by Murphy Oil and the results of the operations of these assets have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. The Company is finalizing its allocation of the purchase price related to the pension and post-retirement obligations assumed. There were no intangible assets or goodwill recorded in connection with the Superior Acquisition. In connection with the Superior Acquisition, the Company incurred acquisition costs during 2011 of approximately $2,717 which are reflected in selling, general and administrative expenses in the consolidated statements of operations.

The preliminary allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:


	Allocation of Purchase Price
Inventories	$	183,602
Prepaid expenses and other current assets		5,845
Property, plant and equipment		239,478
Accrued salaries, wages and benefits		(775	)
Pension and postretirement benefit obligations		(14,977	)

Total purchase price	$	413,173

The following financial information reflects the results of revenue and earnings of the Superior Acquisition since the acquisition date of September 30, 2011 that is included in the consolidated statement of operations for the year ended December 31, 2011:


	Three Months Ended December 31, 2011
Sales	$	341,152
Net income		15,964

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The following unaudited pro forma financial information reflects the consolidated results of operations of the Company as if the Superior Acquisition had taken place on January 1, 2010.


	Year Ended December 31,
	2011		2010
Sales	$	4,251,480	$	3,280,193
Net income	$	108,092	$	7,185
Limited partners’ interest basic and diluted net income per unit	$	2.09	$	0.14

The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Superior Acquisition. This unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.

The 2011 unaudited pro forma financial information reflects adjustments to increase interest expense by $23,135 as a result of the issuance of the 2019 Notes, amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund a portion of the Superior Acquisition and the repayment of borrowings under the prior term loan from the net proceeds of the 2019 Notes issued in April 2011. Additionally, the unaudited pro forma financial information reflects adjustments to increase depreciation expense by $646 as a result of the addition of fixed assets related to the Superior Acquisition at their estimated fair value, as well as adjustments to eliminate the Superior Business’ income tax expense of $31,981.

The 2010 unaudited pro forma financial information reflects adjustments to increase interest expense by $27,400 as a result of the issuance of the 2019 Notes, amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund a portion of the Superior Acquisition and the repayment of borrowings under the prior term loan from the net proceeds of the 2019 Notes issued in April 2011. Additionally, the unaudited pro forma financial information reflects adjustments to increase depreciation expense by $3,003 as a result of the addition of fixed assets related to the Superior Acquisition at their estimated fair values, as well as adjustments to eliminate the Superior Business’ income tax expense of $13,413.

In connection with the Superior Acquisition on September 30, 2011, the Company entered into a crude oil supply agreement (the “Murphy Crude Oil Supply Agreement”) with Murphy Oil, pursuant to which the Company purchases from Murphy Oil (subject to certain customary conditions) up to 10,000 bpd of crude oil. The term of the Murphy Crude Oil Supply Agreement is month-to-month but, except under certain customary circumstances, Murphy Oil may not terminate the agreement until the fifth anniversary of its effective date. Under the Murphy Crude Oil Supply Agreement, the Company pays Murphy Oil for such crude oil and services on a cost-plus basis and provides to Murphy Oil a standby letter of credit of up to $75,000, the amount of which is subject to adjustment from time to time based on changes in crude oil prices. As of December 31, 2011 the Company had issued a letter of credit to Murphy Oil for approximately $66,000.

On October 5, 2011, the Company entered into a Crude Oil Purchase Agreement (the “BP Purchase Agreement”) with BP Products North America Inc. (“BP”), pursuant to which BP will supply the Superior refinery with approximately 75% of its daily crude oil requirements, utilizing a market-based pricing mechanism, plus transportation and handling costs. Total crude oil requirements for the Superior refinery are estimated to be between 35,000 and 45,000 bpd. The BP Purchase Agreement was effective as of October 1, 2011, with deliveries commencing November 1, 2011. The BP Purchase Agreement has an initial term of seven months, will automatically renew for successive one-year terms and may be terminated by either party on written notice

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

delivered at least 90 days prior to the end of the then-current term. To secure a portion of the Company’s payment obligations under the BP Purchase Agreement, the Company and its affiliates have granted a limited interest capped at $100,000 for physical forwards in the collateral pledged as security under the Collateral Trust Agreement to BP as a “Forward Purchase Secured Hedge Counterparty” under its Collateral Trust Agreement, as such term is defined therein.

4.	LyondellBasell Agreements

In November 2009, the Company entered into agreements (the “LyondellBasell Agreements”) with Houston Refining LP, a wholly-owned subsidiary of LyondellBasell (“Houston Refining”), to form a long-term specialty products affiliation under which Houston Refining provides the Company finished products for its specialty products segment. The initial term of the LyondellBasell Agreements expires on October 31, 2014 after which it is automatically extended for additional one-year terms until either party terminates with 24 months prior notice. Under the terms of the LyondellBasell Agreements, (i) the Company is required to purchase at least a minimum volume of 3,100 bpd of naphthenic lubricating oils produced at Houston Refining’s refinery in Houston, Texas, and has a right of first refusal to purchase any additional naphthenic lubricating oils produced at the refinery, and (ii) Houston Refining is required to process a minimum of approximately 800 bpd of white mineral oil for the Company at Houston Refining’s Houston, Texas refinery, which supplements the white mineral oil production at the Company’s Karns City and Dickinson facilities. LyondellBasell has also granted the Company rights to use certain registered trademarks and tradenames, including Tufflo, Duoprime, Duotreat, Crystex, Ideal and Aquamarine. The annual purchase commitment under these agreements is approximately $190,459.

5.	Goodwill and Other Intangible Assets

The Company has recorded $48,335 of goodwill as a result of the acquisition of Penreco on January 3, 2008, all of which is recorded within the Company’s specialty products segment.

Other intangible assets consist of the following:


	Weighted Average Life		December 31, 2011					December 31, 2010
	Weighted Average Life		Gross Amount		Accumulated Amortization			Gross Amount		Accumulated Amortization
Customer relationships		20	$	28,482	$	(12,936	)	$	28,482	$	(10,130	)
Supplier agreements		4		21,519		(19,926	)		21,519		(18,001	)
Patents		12		1,573		(966	)		1,573		(788	)
Non-competition agreements		5		5,732		(4,182	)		5,732		(2,323	)
Distributor agreements		3		2,019		(2,019	)		2,019		(2,019	)
Royalty agreements		19		4,499		(1,120	)		4,499		(897	)

		12	$	63,824	$	(41,149	)	$	63,824	$	(34,158	)

Intangible assets associated with supplier agreements, non-competition agreements, patents and distributor agreements are being amortized to properly match expense with the discounted estimated future cash flows over the term of the related agreements. Agreements with terms to allow for the potential extension of the agreement are being amortized based on the initial term only. Intangible assets associated with customer relationships of Penreco are being amortized using discounted estimated future cash flows based upon an assumed rate of annual customer attrition. For the years ended December 31, 2011, 2010 and 2009, the Company recorded amortization expense of intangible assets of $6,991, $8,810 and $11,409, respectively. The Company estimates that amortization of intangible assets will be $5,747, $3,114, $2,531, $2,066 and $1,697 for 2012, 2013, 2014, 2015 and 2016, respectively.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

6.	Commitments and Contingencies

Operating Leases

The Company has various operating leases for the use of land, storage tanks, compressor stations, railcars, equipment, precious metals and office facilities that extend through June 2026. Renewal options are available on certain of these leases in which the Company is the lessee. Rent expense for the years ended December 31, 2011, 2010, and 2009 was $20,490, $17,104 and $15,675, respectively.

As of December 31, 2011, 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	Operating Leases
2012	$	21,416
2013		19,700
2014		12,550
2015		9,344
2016		5,565
Thereafter		14,036

Total	$	82,611

Crude Oil Supply, Other Feedstocks and Finished Products

The Company is currently purchasing a majority of its crude oil under month-to-month evergreen contracts or on a spot basis. The BP Purchase Agreement has an initial term of seven months and will automatically renew for successive one-year terms as discussed in Note 3. The Company also purchases finished products from Houston Refining under the LyondellBasell Agreements as discussed in Note 4. Additionally, other feedstocks are purchased under long term supply contracts. As of December 31, 2011, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows:


Year	Commitment
2012	$	1,255,492
2013		237,716
2014		176,615
2015		—
2016		—
Thereafter		—

Total	$	1,669,823

In connection with the Company’s acquisition of Penreco on January 3, 2008, the Company entered into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, ConocoPhillips is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, the Company is obligated to purchase approximately $74,000 of feedstock for the LVT unit in each fiscal year of the term of the contract, expiring January 1, 2018, based on

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

pricing estimates as of December 31, 2011. This amount is not included in the table above. If the Base Volume is not supplied at any point during the first five years of the ten year term, a penalty for each gallon of shortfall must be paid to the Company as liquidated damages.

Labor Matters

The Company has approximately 470 employees covered by various collective bargaining agreements, or approximately 55.3% of its total workforce of approximately 850 employees. These agreements have expiration dates of July 1, 2012, March 31, 2013, April 30, 2013, October 31, 2014 and January 31, 2015. The Company has approximately 200 employees, or approximately 23.5% of its total workforce, covered by collective bargaining agreements that expire in less than one year and does not expect any work stoppages.

Contingencies

From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxation and regulatory authorities, such as the U.S. Environmental Protection Agency (“EPA”), Louisiana Department of Environmental Quality (“LDEQ”), the Wisconsin Department of Natural Resources (“WDNR”), the Internal Revenue Service, various state and local departments of revenue and the federal Occupational Safety and Health Administration, as amended (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.

Insurance Recoveries

During the second quarter of 2011, the Company reached a final settlement of its insurance claim related to the failure of an environmental operating unit at its Shreveport refinery in 2010, resulting in a gain (insurance recoveries) of $8,698 recorded for the year ended December 31, 2011 in the consolidated statements of operations and used the proceeds to repair the failed unit and for working capital needs. This claim related to both property damage and business interruption. Recoveries of $1,942 related to property damage have been reflected within investing activities (with the remainder in operating activities) in the consolidated statements of cash flows.

Environmental

The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations can impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Certain of these 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.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

In connection with the Superior Acquisition, the Company became a party to an existing consent decree (“Consent Decree”) with the EPA and WDNR that applies, in part, to its Superior refinery. Under the consent decree, the Company will have to complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the facility to the EPA and WDNR, and the Company currently estimates costs of approximately $4,100 to make known equipment upgrades and conduct other discrete tasks in compliance with the Consent Decree. Failure to perform required tasks under the Consent Decree could result in the imposition of stipulated penalties, which could be significant. In addition, the Company may have to pursue certain additional environmental and safety-related projects at the Superior refinery including, but not limited to: (i) installing process equipment pursuant to applicable EPA fuel content regulations (ii) purchasing emission credits on an interim basis until such time as any process equipment that may be required under the EPA fuel content regulations is installed and operational; (iii) performing monitoring and remediation of historical contamination at the facility; (iv) upgrading treatment equipment or possibly pursuing other remedies, as necessary, to satisfy new effluent discharge limits under a Clean Water Act permit renewal that is pending; and (v) pursuing various voluntary programs at the Superior refinery, including removing asbestos-containing materials or enhancing process safety or other maintenance practices. Completion of these additional projects would result in the Company incurring additional costs, which could be substantial. During 2011, the Company incurred approximately $2,270 costs related to installing process equipment pursuant to the fuel content regulations. The Company currently estimates costs for performing monitoring and remediation of historical contamination at the Superior refinery to be approximately $200 per year.

In addition, the Company is indemnified by Murphy Oil for specified environmental liabilities including: (i) certain obligations arising out of the Consent Decree (including payment of a civil penalty required under the Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or discharged by Murphy Oil. The Company is also indemnified by Murphy Oil for two years following the Superior Acquisition for liabilities arising from breaches of certain environmental representations and warranties made by Murphy Oil, subject to a maximum liability of $22,000, for which the Company is required to contribute up to the first $6,600.

On December 23, 2010, the Company entered into a settlement agreement with the LDEQ regarding (i) the Company’s voluntary participation in the LDEQ’s “Small Refinery and Single Site Refinery Initiative” with respect to its Louisiana refineries, and (ii) certain alleged past violations for which the LDEQ had previously initiated enforcement including (A) May 2001, December 2002 and December 2004 notifications received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations as well as alleged violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency and (B) an August 2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations. The LDEQ’s “Small Refinery and Single Site Refinery Initiative” is patterned after the EPA’s “National Petroleum Refinery Initiative,” which is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. The agreement, voluntarily entered into by the Company, requires the Company to make a $1,000 payment to the LDEQ and complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries. As of December 31, 2011, the Company has incurred approximately $4,000 of expenditures and it estimates additional expenditures of approximately $7,000 to $11,000 of capital expenditures and expenditures related to additional personnel and environmental studies over the next four years as a result of the implementation of these

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

requirements. This agreement also fully settles the aforementioned alleged environmental and permit violations at the Company’s Cotton Valley and Princeton refineries and stipulates that no further civil penalties over alleged past violations at those refineries will be pursued by the LDEQ. The required investments are expected to include projects resulting in (i) nitrogen oxide and sulfur dioxide emission reductions from heaters and boilers and the application of New Source Performance Standards for sulfur recovery plants and flaring devices, (ii) control of incidents related to acid gas flaring, tail gas and hydrocarbon flaring, (iii) electrical reliability improvements to reduce flaring, (iv) flare refurbishment at the Shreveport refinery, (v) enhancement of the Benzene Waste National Emissions Standards for Hazardous Air Pollutants programs and the Leak Detection and Repair programs at the Company’s three Louisiana refineries and (vi) Title V audits and targeted audits of certain regulatory compliance programs. During negotiations with the LDEQ, the Company voluntarily initiated projects for certain of these requirements prior to the settlement with the LDEQ, and currently anticipates completion of these projects over the next four years. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the settlement to have a material adverse effect on the Company’s financial results or operations. The terms of this settlement agreement were deemed final and effective on January 31, 2012 upon concurrence of the Louisiana Attorney General.

Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. These projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. The Company incurred approximately $338 and $541 in 2011 and 2010, respectively, of such capital expenditures at its Cotton Valley refinery.

The Company is indemnified by Shell Oil Company, as successor to Pennzoil-Quaker State Company and Atlas Processing Company, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The indemnity is unlimited in amount and duration, but requires the Company to contribute up to $1,000 of the first $5,000 of indemnified costs for certain of the specified environmental liabilities.

Occupational Health and Safety

The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company has implemented an internal program of inspection designed to monitor and enforce compliance with worker safety requirements as well as a quality system that meets the requirements of the ISO-9001-2008 Standard. The integrity of the Company’s ISO-9001-2008 Standard certification is maintained through surveillance audits by its registrar at regular intervals designed to ensure adherence to the standards. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures.

The Company has completed studies to assess the adequacy of its process safety management practices at its Shreveport refinery with respect to certain consensus codes and standards. As of December 31, 2011, the

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Company has incurred approximately $4,075 of capital expenditures and expects to incur between $1,000 and $4,000 of capital expenditures during 2012 and 2013 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards.

Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the “Shreveport Citation”) to the Company as a result of the Shreveport inspection, which included a civil penalty amount of $119 that was paid in January 2011. In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under this OSHA initiative. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $208. The Company has contested the Cotton Valley Citation and associated penalties and is currently in negotiations with OSHA to reach a settlement allowing an extended abatement period for a new refinery flare system study and for completion of facility site modifications, including relocation and hardening of structures.

Standby Letters of Credit

The Company has agreements with various financial institutions for standby letters of credit which have been issued to domestic vendors. As of December 31, 2011 and 2010, the Company had outstanding standby letters of credit of $230,040 and $90,725, respectively, under its senior secured revolving credit facility, which was amended and restated on June 24, 2011, (the “revolving credit facility”). Refer to Note 7 for additional information regarding the revolving credit facility. The maximum amount of letters of credit the Company can issue at December 31, 2011 under its revolving credit facility is subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $680,000, which is the greater of (i) $400,000 and (ii) 80% of revolver commitments ($850,000 at December 31, 2011) in effect. At December 31, 2010, the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base restrictions, with a letter of credit sublimit of $300,000.

As of December 31, 2011 and 2010, the Company had availability to issue letters of credit of $340,715 and $145,454, respectively, under its revolving credit facility. As discussed in Note 7, as of December 31, 2011 the outstanding standby letters of credit issued under the revolving credit facility included a $25,000 letter of credit issued to a hedging counterparty to support a portion of its fuel products hedging program.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

7.	Long-Term Debt

Long-term debt consisted of the following:


	December 31,
	2011			2010
Borrowings under prior term loan, extinguished in 2011	$	—		$	367,385
Borrowings under senior secured revolving credit agreement, amended and restated in June 2011		—			10,832
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments monthly, borrowings due June 2016		—			—
Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.79% for the year ended December 31, 2011		600,000			—
Capital lease obligations, at various interest rates, interest and principal payments quarterly through November 2013		786			1,781
Less unamortized discount on 2019 Notes issued in September 2011		(13,696	)		—
Less unamortized discount on prior term loan, extinguished in 2011		—			(10,723	)

Total long-term debt		587,090			369,275
Less current portion of long-term debt		551			4,844

	$	586,539		$	364,431

9³/8% Senior Notes

On April 21, 2011, in connection with the restructuring of the majority of its outstanding long-term debt, the Company issued and sold $400,000 in aggregate principal amount of 9³/8% of senior notes due May 1, 2019 (the “2019 Notes issued in April 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at par. The 2019 Notes issued in April 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $388,999 net of underwriters’ fees and expenses, which the Company used to repay in full borrowings outstanding under its prior term loan, as well as all accrued interest and fees, and for general partnership purposes.

On September 19, 2011, in connection with the Superior Acquisition, the Company issued and sold $200,000 in aggregate principal amount of 2019 Notes issued in September 2011 in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at a discounted price of 93 percent of par. The 2019 Notes issued in September 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $180,296 net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Superior Acquisition. Because the terms of the 2019 Notes issued in September 2011 are substantially identical to the terms of the 2019 Notes issued in April 2011, in this Annual Report, the Company collectively refers to the 2019 Notes issued in April 2011 and the 2019 Notes issued in September 2011 as the “2019 Notes.”

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corporation (a wholly owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2019 Notes). The operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into another company if such a sale would cause a default under the indentures governing the 2019 Notes. Since all Company’s operating subsidiaries guarantee the 2019 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.

At any time prior to May 1, 2014, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.

On and after May 1, 2015, the Company may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:


Year	Percentage
2015		104.688	%
2016		102.344	%
2017 and at any time thereafter		100.000	%

Prior to May 1, 2015, the Company may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indentures governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

The indentures governing the 2019 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indentures governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.

Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.

In connection with the 2019 Notes offering on April 21, 2011, the Company’s then current senior secured revolving credit facility was amended on April 15, 2011 to, among other things, (i) permit the issuance of the

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

2019 Notes issued in April 2011; (ii) upon consummation of the issuance of the 2019 Notes issued in April 2011 and the termination of the senior secured first lien credit facility, release the revolving credit facility lenders’ second priority lien on the collateral securing the senior secured first lien credit facility and (iii) change the interest rate pricing on the revolving credit facility.

Registration of 2019 Notes

In connection with the issuances and sales of the 2019 Notes, the Company entered into registration rights agreements with the initial purchasers of the 2019 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2019 Notes could offer to exchange the 2019 Notes for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. On December 16, 2011, the Company filed exchange offer registration statements for the 2019 Notes with the SEC, which were declared effective on January 3, 2012. The exchange offers were completed on February 2, 2012, thereby fulfilling all of the requirements of the 2019 Notes registration rights agreements by the specified dates.

Termination of Senior Secured First Lien Credit Facility

The Company’s prior $435,000 senior secured first lien credit facility (the “prior term loan”) included a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. The Company extinguished this facility on April 21, 2011 in connection with the issuance and sale of the 2019 Notes issued in April 2011, as further discussed below. The prior term loan bore interest at a rate equal to (i) with respect to a LIBOR Loan, the LIBOR Rate (as defined in the senior secured first lien credit agreement) plus 400 basis points and (ii) with respect to a Base Rate Loan, the Base Rate (as defined in the senior secured first lien credit agreement) plus 300 basis points. At December 31, 2010, the term loan bore interest at 4.29%.

On April 21, 2011, the Company used approximately $369,486 of the net proceeds from the issuance and sale of the 2019 Notes issued in April 2011 to repay in full its term loan, as well as accrued interest and fees, and terminated the entire senior secured first lien credit facility, including the term loan and a $50,000 prefunded letter of credit to support crack spread hedging. The Company did not incur any material early termination penalties in connection with its termination of the senior secured first lien credit facility. Further, in the second quarter of 2011 the Company recorded approximately $15,130 of debt extinguishment charges related to the write off of the unamortized debt issuance costs and the unamortized discount associated with the prior term loan.

Amended and Restated Senior Secured Revolving Credit Facility

On June 24, 2011, the Company entered into an amended and restated senior secured revolving credit facility (the “revolving credit facility”), which increased the maximum availability of credit under the revolving credit facility from $375,000 to $550,000, subject to borrowing base limitations, and included a $300,000 incremental uncommitted expansion option. On September 30, 2011, in conjunction with the Superior Acquisition, the Company fully exercised the $300,000 expansion option to increase the maximum availability of credit under the revolving credit facility from $550,000 to $850,000, subject to borrowing base limitations. The revolving credit facility, which is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations, matures in June 2016 and currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. As of December 31, 2011, the

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit agreement in the preceding calendar quarter as follows:


Quarterly Average Availability Percentage	Margin on Base Rate Revolving Loans			Margin on LIBOR Revolving Loans
³ 66%		1.00	%		2.25	%
³ 33% and < 66%		1.25	%		2.50	%
< 33%		1.50	%		2.75	%

In addition to paying interest monthly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.375% to 0.50% per annum depending on the average daily available unused borrowing capacity. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.

The borrowing capacity at December 31, 2011 under the revolving credit facility was $570,755. As of December 31, 2011, the Company had no outstanding borrowings under the revolving credit facility, leaving $340,715 available for additional borrowings based on specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s cash, accounts receivable, inventory and certain other personal property.

The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $46,364, (as increased, upon the effectiveness of the increase in the maximum availability under the revolving credit facility, by the same percentage as the percentage increase in the revolving credit agreement commitments), then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit agreement) of at least 1.0 to 1.0.

Collateral Trust Agreement

In connection with the Amendments, on April 21, 2011, the Company entered into a collateral sharing agreement (the “Collateral Trust Agreement”) with each of its secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties, which governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by the Company to the secured hedging counterparties under their respective master derivatives contracts. Subject to certain conditions set forth in the Collateral Trust Agreement, the Company has the ability to add secured hedging counterparties thereto.

In connection with the closing of the Superior Acquisition, on September 30, 2011, the Company entered into an amendment (the “CTA Amendment”) to the Collateral Trust Agreement with each of its secured hedging

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

counterparties and the administrative agent. The CTA Amendment modified the Collateral Trust Agreement so as to limit to $100,000 the extent to which forward purchase contracts for physical commodities would be covered by, and secured under, the Collateral Trust Agreement. The CTA Amendment also eliminated the credit rating requirement with respect to forward purchase contract counterparties on physical commodities.

Amendments to Master Derivative Contracts

In connection with the termination of the prior term loan and the amendment of the revolving credit facility, on April 21, 2011, the Company entered into amendments to certain of the Company’s master derivatives contracts (“Amendments”) to provide new credit support arrangements to secure the Company’s payment obligations under these contracts following the termination of the term loan facility and the amendment and restatement of the prior term loan facility. Under the new credit support arrangements, the Company’s payment obligations under all of the Company’s master derivatives contracts for commodity hedging generally are secured by a first priority lien on the Company’s real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). The Company also issued to one counterparty a $25,000 standby letter of credit under the revolving credit facility to replace a prefunded $50,000 letter of credit previously issued under the prior term loan. In the event that such counterparty’s exposure to the Company exceeds $200,000, the Company will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges. The Company had no additional letters of credit or cash margin posted with any hedging counterparty as of December 31, 2011. The Company’s master derivatives contracts and Collateral Trust Agreement (as defined above) continue to impose a number of covenant limitations on the Company’s operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.

Capital Lease Obligations

The Company has three capital lease obligations for catalysts used in refining processes which will expire in 2012 and 2013. Assets recorded under these capital lease obligations are included in property, plant and equipment and consist of $4,201 as of December 31, 2011 and 2010. As of December 31, 2011 and 2010, the Company had recorded $3,221 and $2,171, respectively, in accumulated depreciation for these capital lease assets.

As of December 31, 2011, the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows:


Year	Capital Leases
2012	$	570
2013		240

Total minimum lease payments		810
Less amount representing interest		24

Capital lease obligations		786
Less obligations due within one year		551

Long-term capital lease obligations	$	235

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

As of December 31, 2011, maturities of the Company’s long-term debt are as follows:


Year	Maturity
2012	$	551
2013		235
2014		—
2015		—
2016		—
Thereafter		600,000

Total	$	600,786

8.	Derivatives

The Company utilizes derivative instruments to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas, the sale of fuel products and interest payments. The Company employs various hedging strategies, which are further discussed below. The Company does not hold or issue derivative instruments for trading purposes.

The Company recognizes all derivative instruments at their fair values (see Note 10) as either assets or liabilities on the consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The Company’s financial results are subject to the possibility that changes in a derivative’s fair value could result in significant ineffectiveness and potentially result in such derivative no longer qualifying for hedge accounting. The Company recorded the following derivative assets and liabilities at their fair values as of December 31, 2011 and December 31, 2010:


	Derivative Assets					Derivative Liabilities
	December 31, 2011			December 31, 2010		December 31, 2011			December 31, 2010
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	83,919		$	—	$	56,041		$	134,916
Gasoline swaps		(20,605	)		—		(1,596	)		(14,149	)
Diesel swaps		(4,561	)		—		(22,586	)		(53,744	)
Jet fuel swaps		1,077			—		(72,537	)		(96,556	)
Interest rate swaps:		—			—		—			(2,681	)

Total derivative instruments designated as hedges		59,830			—		(40,678	)		(32,214	)

Derivative instruments not designated as hedges:
Fuel products segment:
Jet fuel crack spread collars (1)		—			—		—			20
Specialty products segment: (2)
Natural gas swaps		(1,328	)		—		(1,892	)		—
Crude oil swaps		—			—		—			662
Interest rate swaps: (3)		—			—		(1,011	)		(1,282	)

Total derivative instruments not designated as hedges		(1,328	)		—		(2,903	)		(600	)

Total derivative instruments	$	58,502		$	—	$	(43,581	)	$	(32,814	)

(1)	The Company entered into jet fuel crack spread collars, which do not qualify for hedge accounting, to economically hedge its exposure to changes in the jet fuel crack spread.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

(2)

The Company has historically entered into combinations of crude oil options and swaps and natural gas swaps to economically hedge its exposures to price risk related to these commodities in its specialty products segment. The Company has not designated these derivative instruments as cash flow hedges.

(3)	The Company refinanced a significant majority of its long-term debt in April 2011 and, as a result, all of its interest rate swaps that were designated as cash flow hedges of the interest payments under the previous term loan facility are no longer designated as cash flow hedges.

To the extent a derivative instrument is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the consolidated balance sheets, until the underlying transaction hedged is recognized in the consolidated statements of operations. The Company accounts for certain derivatives hedging purchases of crude oil, sales of gasoline, diesel and jet fuel and the payment of interest as cash flow hedges. The derivatives hedging sales and purchases are recorded to sales and cost of sales, respectively, in the consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. The derivatives designated as hedging payments of interest are recorded in interest expense in the consolidated statements of operations upon payment of interest. The Company assesses, both at inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

For derivative instruments not designated as cash flow hedges and the portion of any cash flow hedge that is determined to be ineffective, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the consolidated statements of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations. Ineffectiveness is inherent in the hedging of crude oil and fuel products. Due to the volatility in the markets for crude oil and fuel products, the Company is unable to predict the amount of ineffectiveness each period, which has the potential for the future loss of hedge accounting, determined on a derivative by derivative basis or in the aggregate for a specific commodity. Ineffectiveness has resulted, and the loss of hedge accounting would result, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize product margins and cash flows.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The Company recorded the following amounts in its consolidated balance sheets, consolidated statements of operations and its consolidated statements of partners’ capital as of, and for the years ended, December 31, 2011 and 2010 related to its derivative instruments that were designated as cash flow hedges:


	Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)						Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)							Amount of Loss Recognized in Net Income on Derivatives (Ineffective Portion)
	Year Ended December 31,							Year Ended December 31,							Year Ended December 31,
Type of Derivative	2011			2010			Location of (Gain) Loss	2011			2010			Location of Gain (Loss)	2011			2010
Fuel products segment:
Crude oil swaps	$	133,060		$	73,661		Cost of sales	$	(108,433	)	$	(81,647	)	Unrealized/Realized	$	(8,159	)	$	(10,077	)
Gasoline swaps		(38,289	)		(1,329	)	Sales		29,468			23,973		Unrealized/Realized		(1,850	)		(4,034	)
Diesel swaps		(53,622	)		(31,839	)	Sales		79,810			43,685		Unrealized/Realized		(573	)		(2,430	)
Jet fuel swaps		(77,288	)		(66,693	)	Sales		102,473			—		Unrealized/Realized		(2,715	)		(2,936	)
Specialty products segment:
Crude oil collars		—			—		Cost of sales		—			—		Unrealized/Realized		—			—
Crude oil swaps		—			—		Cost of sales		—			—		Unrealized/Realized		—			—
Natural gas swaps		—			—		Cost of sales		—			—		Unrealized/Realized		—			—
Interest rate swaps:		1,979			(2,815	)	Interest expense		702			2,885		Unrealized/Realized		—			—

Total	$	(34,160	)	$	(29,015	)		$	104,020		$	(11,104	)		$	(13,297	)	$	(19,477	)

The Company recorded the following gains (losses) in its consolidated statements of operations and its consolidated statements of partners’ capital for the years ended December 31, 2011 and 2010 related to its derivative instruments not designated as cash flow hedges:


	Amount of Gain (Loss) Recognized in Realized Loss on Derivatives Year Ended December 31,						Amount of Gain (Loss) Recognized in Unrealized Loss on Derivatives Year Ended December 31,
Type of Derivative	2011			2010			2011			2010
Fuel products segment:
Crude oil swaps	$	—		$	(9,508	)	$	—		$	10,907
Gasoline swaps		—			14,318			—			(14,864	)
Diesel swaps		—			(1,301	)		—			1,301
Jet fuel swaps		—			—			—			—
Jet fuel collars		(746	)		—			726			(355	)
Specialty products segment:
Crude oil collars		—			(3,698	)					153
Crude oil swaps		932			(1,086	)		(662	)		661
Natural gas swaps		(171	)		(515	)		(3,221	)		—
Interest rate swaps:		(2,124	)		(814	)		271			731

Total	$	(2,109	)	$	(2,604	)	$	(2,886	)	$	(1,466	)

The cash flow impact of the Company’s derivative activities is classified as a change in derivative activity in the operating activities section in the consolidated statements of cash flows.

The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however,

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of December 31, 2011, the Company had three counterparties, in which the derivatives held were net assets, totaling $58,502. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company executes all of its derivative instruments with large financial institutions that have ratings of at least Baa1 and A- by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark to market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed upon thresholds in its master derivative contracts with these counterparties. No such collateral was held by the Company as of December 31, 2011 or December 31, 2010. The Company’s contracts with these counterparties allow for netting of derivative instruments executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits on the Company’s consolidated balance sheets and not netted against derivative assets or liabilities. As of December 31, 2011, the Company had provided its counterparties with no collateral above the $25,000 letter of credit provided to one counterparty to support crack spread hedging. As of December 31, 2010, the Company had provided its counterparties with no cash collateral or letters of credit above the $50,000 prefunded letter of credit then in effect provided to one counterparty to support crack spread hedging. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.

Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating was lowered below its current level by either Moody’s or S&P, such counterparties would have the right to reduce the applicable threshold to zero and demand full collateralization of the Company’s net liability position on outstanding derivative instruments. As of December 31, 2011 and 2010, there was a net asset of $3,561 and net liability of $388, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business. The effective portion of the hedges classified in accumulated other comprehensive income is $47,094 as of December 31, 2011 and, absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2014 with balances being recognized as follows:


Year	Accumulated Other Comprehensive Income
2012	$	22,011
2013		21,681
2014		3,402

Total	$	47,094

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Based on fair values as of December 31, 2011, the Company expects to reclassify $22,011 of net gains on derivative instruments from accumulated other comprehensive income to earnings during the next twelve months due to actual crude oil purchases and gasoline, diesel and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the date of settlements.

Crude Oil Swap Contracts — Specialty Products Segment

The Company is exposed to fluctuations in the price of crude oil, its principal raw material. Historically the Company has utilized combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty products segment. These derivatives may be designated as cash flow hedges of the future purchase of crude oil if they meet the hedge criteria. The Company’s general policy is to enter into crude oil derivative contracts that mitigate the Company’s exposure to price risk associated with crude oil purchases related to specialty products production (for up to 70% of expected purchases). While the Company’s policy generally requires that these derivative instruments be short term in nature and expire within three to nine months from execution, the Company may execute derivative contracts for up to two years forward, if a change in the risks supports lengthening the Company’s position. As of December 31, 2011, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.

As of December 31, 2010, the Company had the following crude oil derivatives related to crude oil purchases in its specialty products segment, none of which were designated as cash flow hedges.


Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased		BPD		Average Swap ($/Bbl)
February 2011		33,600		1,200	$	83.10
March 2011		37,200		1,200		83.55

Totals		70,800
Average price					$	83.34

Crude Oil Swap Contracts — Fuel Products Segment

The Company is exposed to fluctuations in the price of crude oil, its principal raw material. The Company utilizes swap contracts to manage crude oil price risk and volatility of cash flows in its fuel products segment. The Company’s policy is generally to enter into crude oil swap contracts for a period no greater than five years forward and for no more than 75% of crude oil purchases used in fuels production. At December 31, 2011, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.


Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased		BPD		Average Swap ($/Bbl)
First Quarter 2012		2,866,500		31,500	$	85.34
Second Quarter 2012		2,775,500		30,500		84.83
Third Quarter 2012		2,852,000		31,000		84.83
Fourth Quarter 2012		2,622,000		28,500		86.73
Calendar Year 2013		4,420,000		12,110		97.93
Calendar Year 2014		1,000,000		2,740		90.55

Totals		16,536,000
Average price					$	89.07

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

At December 31, 2010, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.


Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased		BPD		Average Swap ($/Bbl)
First Quarter 2011		1,215,000		13,500	$	75.32
Second Quarter 2011		1,729,000		19,000		76.62
Third Quarter 2011		1,610,000		17,500		77.38
Fourth Quarter 2011		1,334,000		14,500		77.71
Calendar Year 2012		5,535,000		15,123		86.30

Totals		11,423,000
Average price					$	81.41

Fuel Products Swap Contracts

The Company is exposed to fluctuations in the prices of gasoline, diesel and jet fuel. The Company utilizes swap contracts to manage diesel, gasoline and jet fuel price risk and volatility of cash flows in its fuel products segment. The Company’s policy is generally to enter into diesel, jet fuel and gasoline swap contracts for a period no longer than five years forward and for no more than 75% of forecasted fuel sales.

Diesel Swap Contracts

At December 31, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2012		546,000		6,000	$	118.07
Second Quarter 2012		819,000		9,000		110.09
Third Quarter 2012		1,150,000		12,500		105.48
Fourth Quarter 2012		966,000		10,500		110.11
Calendar Year 2013		1,831,000		5,016		123.20

Totals		5,312,000
Average price					$	114.44

At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2011		630,000		7,000	$	89.57
Second Quarter 2011		637,000		7,000		89.57
Third Quarter 2011		552,000		6,000		91.74
Fourth Quarter 2011		552,000		6,000		91.74
Calendar Year 2012		1,560,000		4,262		99.27

Totals		3,931,000
Average price					$	94.03

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Jet Fuel Swap Contracts

At December 31, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2012		1,274,000		14,000	$	97.97
Second Quarter 2012		1,046,500		11,500		98.47
Third Quarter 2012		782,000		8,500		99.78
Fourth Quarter 2012		736,000		8,000		104.79
Calendar Year 2013		2,044,000		5,600		125.13
Calendar Year 2014		1,000,000		2,740		115.56

Totals		6,882,500
Average price					$	109.60

At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2011		405,000		4,500	$	86.12
Second Quarter 2011		819,000		9,000		89.58
Third Quarter 2011		920,000		10,000		89.86
Fourth Quarter 2011		644,000		7,000		89.21
Calendar Year 2012		3,838,500		10,488		99.78

Totals		6,626,500
Average price					$	95.28

Gasoline Swap Contracts

At December 31, 2011, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2012		1,046,500		11,500	$	100.72
Second Quarter 2012		910,000		10,000		102.48
Third Quarter 2012		920,000		10,000		102.48
Fourth Quarter 2012		920,000		10,000		102.48
Calendar Year 2013		545,000		1,493		107.11

Totals		4,341,500
Average price					$	102.63

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

At December 31, 2010, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		Average Swap ($/Bbl)
First Quarter 2011		180,000		2,000	$	81.84
Second Quarter 2011		273,000		3,000		82.66
Third Quarter 2011		138,000		1,500		85.50
Fourth Quarter 2011		138,000		1,500		85.50
Calendar Year 2012		136,500		373		89.04

Totals		865,500
Average price					$	84.40

Jet Fuel Put Spread Contracts

At December 31, 2011, the Company did not have any jet fuel put options related to jet fuel crack spreads in its fuel products segment. At December 31, 2010, the Company had the following jet fuel put options related to jet fuel crack spreads in its fuel products segment, none of which are designated as cash flow hedges.


Jet Fuel Put Option Crack Spread Contracts by Expiration Dates	Barrels		BPD		Average Sold Put ($/Bbl)		Average Bought Put ($/Bbl)
First Quarter 2011		630,000		7,000	$	4.00	$	6.00
Fourth Quarter 2011		184,000		2,000		4.75		7.00

Totals		814,000
Average price					$	4.17	$	6.23

Natural Gas Swap Contracts

Natural gas purchases comprise a significant component of the Company’s cost of sales; therefore, changes in the price of natural gas also significantly affect its profitability and cash flows. The Company utilizes swap contracts to manage natural gas price risk and volatility of cash flows. The Company’s policy is generally to enter into natural gas derivative contracts to hedge no more than 75% of its anticipated natural gas requirement for a period no greater than three years forward. At December 31, 2011 the Company had the following natural gas derivatives related to natural gas purchases in its specialty products segment, none of which were designated as cash flow hedges.


Natural Gas Swap Contracts by Expiration Dates	MMBtu		$/MMBtu
First Quarter 2012		1,200,000	$	3.90
Second Quarter 2012		1,200,000		3.93
Third Quarter 2012		1,200,000		4.03
Fourth Quarter 2012		600,000		4.08

Totals		4,200,000
Average price			$	3.97

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

At December 31, 2010, the Company did not have any derivatives outstanding related to natural gas purchases.

Interest Rate Swap Contracts

The Company’s profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of the Company’s interest rate risk management activities is to hedge its exposure to changes in interest rates. Historically, the Company’s policy has been to enter into interest rate swap agreements to hedge up to 75% of its interest rate risk related to variable rate debt. With the issuances during 2011 of the 2019 Notes, which constitute fixed rate debt, the Company does not expect to enter into additional hedges (beyond those listed below) to fix its interest rates. The following table summarizes our outstanding interest rate swaps as of December 31, 2011.


Interest Rate Swap Contract	Effective Date	Maturity Date	Notional Amount	Swap Contract	Weighted Average Fixed Rate
2006 Swap (1)	June 9, 2006	December 10, 2012	$40,056	3 Month LIBOR	5.44%
2006 Swap (1)	December 10, 2007	December 10, 2012	40,056	3 Month LIBOR plus 1.98% spread	5.44%
2010 Swap (2)	February 15, 2011	February 15, 2012	100,000	3 Month LIBOR	2.03%

(1)

Due to the repayment of $19,000 of the outstanding balance of the Company’s then existing term loan facility in August 2007 and subsequent refinancing of the remaining term loan balance, this interest rate swap contract was not designated as a cash flow hedge of the future payment of interest. The entire change in the fair value of this interest rate swap was recorded to unrealized loss on derivative instruments in the consolidated statements of operations. In the first quarter of 2008, the Company fixed its unrealized loss on this interest rate swap derivative instrument by entering into an offsetting interest rate swap expiring December 2012, which is not designated as a cash flow hedge. The notional amount is based upon a fixed schedule set forth in the confirmation, and the amount disclosed is notional amount as of December 31, 2011.

(2)

Due to the repayment of the variable rate prior term loan in April 2011 with proceeds from the 2019 Notes issued in April 2011, the interest rate swap was discontinued as a cash flow hedge for the future payment of interest. As a result the Company reclassified approximately $529 into unrealized loss and recognized $1,318 of realized losses of derivative instruments for the year ended December 31, 2011 in the consolidated statements of operations.

9.	Fair Value of Financial Instruments

The Company’s financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, pension plan assets, derivative instruments, accounts payable and indebtedness. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Pension assets are reported at fair value using quoted market prices in the accompanying consolidated financial statements. Derivative instruments are reported in the accompanying consolidated financial statements at fair value. The fair value of the Company’s 2019 Notes was $591,750 at December 31, 2011, using quoted market prices. The fair value of the Company’s prior term loan was $355,445 at December 31, 2010, using quoted market prices. The carrying values of borrowings under the Company’s revolving credit facility were $0 and $10,832 at December 31, 2011 and December 31, 2010, respectively, and approximate their fair values. In addition, based upon fees charged for similar agreements, the face values of outstanding standby letters of credit approximated their fair values at December 31, 2011 and 2010.

10.

Fair Value Measurements

The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.

As of December 31, 2011, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to crude oil, gasoline, diesel, jet fuel, natural gas and interest rates, and investments associated with the Company’s Pension Plan (as such term is hereinafter defined).

The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least Baa1 and A- by Moody’s and S&P, respectively. To estimate the fair values of the Company’s derivative instruments, the Company uses the market approach. Under this approach, the fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, jet fuel, natural gas and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the Company obtains this data through surveying its counterparties and performing various analytical tests to validate the data. In situations where the Company obtains inputs via quotes from its counterparties, it verifies the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. The Company also includes an adjustment for non-performance risk in the recognized measure of fair value of all of the Company’s derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When the Company is in a net asset position, it uses its counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. The Company uses its own peer group’s estimated CDS when it is in a net liability position. As a result of applying the applicable CDS, at December 31, 2011 the Company’s asset was reduced by approximately $1,297 and the liability was reduced by approximately $165. As a result of applying the applicable CDS, at December 31, 2010 the Company’s liability was reduced by approximately $687. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for crude oil, gasoline, jet fuel, diesel and natural gas, the Company has categorized these derivative instruments as Level 3. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds.

The Company’s investments associated with its Pension Plan primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded and (iii) a commingled fund. The mutual funds are publically traded and market prices are readily available, thus these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of shares held by the Pension Plan at year end.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The Company’s assets and liabilities measured at fair value at December 31, 2011 were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Cash and cash equivalents	$	64	$	—	$	—		$	64
Crude oil swaps		—		—		83,919			83,919
Gasoline swaps		—		—		(20,605	)		(20,605	)
Diesel swaps		—		—		(4,561	)		(4,561	)
Jet fuel swaps		—		—		1,077			1,077
Jet fuel options		—		—		—			—
Natural gas swaps		—		—		(1,328	)		(1,328	)
Pension plan investments		33,580		2,462		—			36,042

Total assets at fair value	$	33,644	$	2,462	$	58,502		$	94,608

Liabilities:
Crude oil swaps	$	—	$	—	$	56,041		$	56,041
Gasoline swaps		—		—		(1,596	)		(1,596	)
Diesel swaps		—		—		(22,586	)		(22,586	)
Jet fuel swaps		—		—		(72,537	)		(72,537	)
Jet fuel options		—		—		—			—
Natural gas swaps		—		—		(1,892	)		(1,892	)
Interest rate swaps		—		—		(1,011	)		(1,011	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(43,581	)	$	(43,581	)

118

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The Company’s assets and liabilities measured at fair value at December 31, 2010 were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Cash and cash equivalents	$	37	$	—	$	—		$	37
Crude oil swaps		—		—		135,578			135,578
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Jet fuel options		—		—		20			20
Pension plan investments		16,039		—		—			16,039

Total assets at fair value	$	16,076	$	—	$	135,598		$	151,674

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(14,149	)		(14,149	)
Diesel swaps		—		—		(53,744	)		(53,744	)
Jet fuel swaps		—		—		(96,556	)		(96,556	)
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(3,963	)		(3,963	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(168,412	)	$	(168,412	)

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the years ended December 31, 2011 and 2010:


	Derivative Instruments, Net Year Ended December 31,
	2011			2010
Fair value at January 1,	$	(32,814	)	$	26,138
Realized losses		7,909			7,704
Unrealized losses		(10,383	)		(15,843	)
Change in fair value of cash flow hedges		(34,160	)		(29,015	)
Purchases, issuances and settlements		84,369			(21,798	)
Transfers in (out) of Level 3		—			—

Fair value at December 31,	$	14,921		$	(32,814	)

Total losses included in net income attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of December 31,	$	(10,383	)	$	(15,843	)

All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives, cost of sales for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in the consolidated financial statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative

119

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

instruments are recorded in earnings immediately in unrealized gain (loss) on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments in the consolidated statements of operations. See Note 8 for further information on derivative instruments.

11.

Partners’ Capital

On December 14, 2009, the Company completed a public offering of its common units in which it sold 3,000,000 common units to the underwriters of the offering at a price to the public of $18.00 per common unit. In addition, on January 7, 2010 the Company sold an additional 47,778 common units to the underwriters at a price to the public of $18.00 per common unit pursuant to the underwriters’ over-allotment option. The proceeds received by the Company (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) from this offering were $51,225 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $2,295. The Company’s general partner contributed $1,102 to retain its 2% general partner interest.

In February 2011, the Company satisfied the last of the earnings and distributions tests contained in its partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution paid on February 14, 2011. Two days following this quarterly distribution to unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.

On February 24, 2011, the Company completed a public offering of its common units in which it sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $92,290 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $3,915. The Company’s general partner contributed $1,970 to retain its 2% general partner interest.

On September 8, 2011, the Company completed a public offering of its common units in which it sold 11,000,000 common units to the underwriters of the offering at a price to the public of $18.00 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $189,497 and were used to fund a portion of the purchase price of the Superior Acquisition. Underwriting discounts totaled $7,866. The Company’s general partner contributed $4,041 to retain its 2% general partner interest. See Note 3 for further information on the Superior Acquisition.

On October 13, 2011, the underwriters of the Company’s September 8, 2011 public offering elected to exercise a portion of their overallotment option. As a result, the Company sold an additional 750,000 common units to the underwriters at a price to the public of $18.00 per unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $12,915 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $540. The Company’s general partner contributed $275 to retain its 2% general partner interest.

Of the 51,529,778 common units outstanding at December 31, 2011, 32,148,052 common units were held by the public, with the remaining 19,381,726 common units held by the Company’s affiliates. At the time of conversion to common units on February 16, 2011, all of the 13,066,000 subordinated units were held by affiliates of the Company.

120

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Significant information regarding rights of the limited partners includes the following:

•

Rights to receive distributions of available cash within 45 days after the end of each quarter, to the extent the Company has sufficient cash from operations after the establishment of cash reserves.

•

Limited partners have limited voting rights on matters affecting the Company’s business. The general partner may consider only the interests and factors that it desires, and has no duty or obligation to give any consideration of any interests of, the Company’s limited partners. Limited partners have no right to elect the board of directors of the Company’s general partner.

•

The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Any holder, other than the general partner or the general partner’s affiliates, that owns 20% or more of any class of units outstanding, cannot vote on any matter.

•

The Company may issue an unlimited number of limited partner interests without the approval of the limited partners.

•

Limited partners may be required to sell their units to the general partner if at any time the general partner owns more than 80% of the issued and outstanding common units.

The Company’s general partner is entitled to incentive distributions if the amount it distributes to unitholders with respect to any quarter exceeds specified target levels shown below:


	Total Quarterly Distribution Per Common Unit	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.45		98	%		2	%
First Target Distribution	up to $0.495		98	%		2	%
Second Target Distribution	above $0.495 up to $0.563		85	%		15	%
Third Target Distribution	above $0.563 up to $0.675		75	%		25	%
Thereafter	above $0.675		50	%		50	%

The Company’s ability to make distributions is limited by its debt instruments. The revolving credit facility generally permits the Company to make cash distributions to unitholders as long as immediately after giving effect to such a cash distribution the Company has availability under the revolving credit facility at least equal to the greater of (i) 15% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) without giving effect to the LC Reserve (as defined in the revolving credit agreement) and (b) the revolving credit facility commitments then in effect and (ii) $45,000. The indentures governing the 2019 Notes provide that if the Company’s fixed charge coverage ratio (as defined in the indentures) for the most recently ended four full fiscal quarters is not less than 1.75 to 1.0, the Company will be permitted to pay distributions to its unitholders in an amount equal to available cash from operating surplus (each as defined in the Company’s partnership agreement) with respect to its preceding fiscal quarter, subject to certain customary adjustments described in the indentures. If the Company’s fixed charge coverage ratio is less than 1.75 to 1.0, the Company will be able to pay distributions to its unitholders up to an amount equal to a $70.0 million basket, subject to certain customary adjustments described in the indentures.

The Company’s distribution policy is as defined in its partnership agreement. For the years ended December 31, 2011, 2010 and 2009, the Company made distributions of $82,743, $65,739 and $59,258, respectively, to its partners. For the years ended December 31, 2011, 2010 and 2009, the general partner was allocated $322, $0 and $0, respectively, in incentive distribution rights.

121

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

12.

Unit-Based Compensation

The Company’s general partner originally adopted a Long-Term Incentive Plan (the “Plan”) on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by the compensation committee of the Company’s general partner’s board of directors.

Non-employee directors of our general partner have been granted phantom units under the terms of the Plan as part of their director compensation package related to fiscal years 2009, 2010 and 2011. These phantom units have a four year service period with one-quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.

For the years ended December 31, 2011 and 2010, named executive officers and certain employees were awarded phantom units under the terms of the Plan, as part of the Company’s achievement of specified levels of financial performance in the fiscal year. These phantom units are subject to time-vesting requirements whereby 25% of the units vest at grant, and the remainder will vest ratably over the next three years on each December 31. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients will earn DERs.

On January 22, 2009, the board of directors of the Company’s general partner approved discretionary contributions to participant accounts for certain directors and employees in the form of phantom units under the Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan. The phantom unit awards vest in one-quarter increments over a four year service period, subject to early vesting on a change in control, upon termination without cause, or due to death, disability or normal retirement. These phantom units also carry DERs from the date of grant.

The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and selling, general and administrative expense in the consolidated statements of operations using the straight-line method over the service period, as it expects these units to fully vest.

122

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

A summary of the Company’s nonvested phantom units as of December 31, 2011, and the changes during the years ended December 31, 2011, 2010 and 2009, are presented below:


	Number of Phantom Units			Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2009		27,708		$	12.91
Granted		47,121			13.29
Vested		(17,336	)		15.56
Forfeited		—			—

Nonvested at December 31, 2009		57,493		$	12.42
Granted		138,490			20.11
Vested		(90,491	)		18.05
Forfeited		—			—

Nonvested at December 31, 2010		105,492		$	17.68

Granted		403,275			21.40
Vested		(183,671	)		20.29
Forfeited		—			—

Nonvested at December 31, 2011		325,096		$	20.82

For the years ended December 31, 2011, 2010 and 2009, compensation expense of $3,027, $784 and $367, respectively, was recognized related to vested phantom unit grants. As of December 31, 2011 and 2010, there was a total of $6,768 and $1,865, respectively of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately three years. The total fair value of phantom units vested during the years ended December 31, 2011 and 2010, was $3,727 and $1,927, respectively.

13.

Employee Benefit Plans

The Company has a domestic defined contribution plan administered by its general partner. All full-time employees are eligible to participate in the plan. Participants are allowed to contribute 0% to 70% of their pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% contribution by the participant up to 4% and 50% of each additional 1% contribution up to 6% for a maximum contribution by the Company of 5% per participant. The Company’s matching contributions expenses were $2,343, $1,948 and $2,040 for 2011, 2010 and 2009, 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 expenses were $1,448, $1,331 and $1,308 for 2011, 2010 and 2009, respectively.

The Company has domestic noncontributory defined benefit plans for both those salaried employees as well as those employees represented by either the United Steelworkers (“USW”) or the International Union of Operating Engineers (“IUOE”); who (i) were formerly employees of Penreco and became employees of the Company as a result of the acquisition of Penreco on January 3, 2008 (“Penreco Pension Plan”) or -(ii) were formerly employees of Murphy Oil Corporation and who became employees of the Company as a result of the Superior Acquisition on September 30, 2011 (the “Superior Pension Plan” and together with the Penreco Pension Plan, the “Pension Plan”). The pension benefits are based primarily on years of service for USW and IUOE

123

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

represented employees and both years of service and the employee’s final 60 months’ average compensation for salaried employees. The funding policy is consistent with funding requirements of applicable laws and regulations. The assets of these plans consist of equity securities, foreign equity securities, fixed income, a commingled fund and cash and cash equivalents. In 2009, the Company amended the Penreco Pension Plan, which curtailed Penreco employees from accumulating additional benefits subsequent to December 31, 2009. All information for this plan presented below has been adjusted for this curtailment.

The Company also has domestic contributory defined benefit postretirement medical plans and contributory life insurance plans for (i) those salaried employees, as well as those employees represented by either the International Brotherhood of Teamsters (“IBT”), USW or IUOE, who were formerly employees of Penreco and who became employees of the Company as a result of the acquisition of Penreco on January 3, 2008 (“Penreco Other Plan”) or (ii) employees represented by the IUOE, who were formerly employees of Murphy Oil Corporation and who became employees of the Company as a result of the Superior Acquisition on September 30, 2011 (“Superior Other Plan”) and together with the Penreco Other Plan, the “Other Plan”.

During 2011, the Company made contributions to its Pension Plan and Other Plan of $1,942 and expects to make contributions in 2012 of approximately $3,506 to its Pension Plan and $128 to its Other Plan.

124

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The change in the benefit obligations, change in the plan assets, funded status and amounts recognized in the consolidated balance sheets were as follows:


	Year Ended December 31,
	2011						2010
	Pension Benefits			Other Post Retirement Employee Benefits			Pension Benefits			Other Post Retirement Employee Benefits
Change in projected benefit obligation (“PBO”):
Benefit obligation at beginning of year	$	24,761		$	446		$	22,382		$	781
Projected benefit obligation attributable to Superior Acquisition		26,218			6,477			—			—
Service cost		296			114			84			—
Interest cost		1,638			96			1,336			23
Benefits paid		(1,162	)		(81	)		(861	)		(114	)
Actuarial loss		3,554			624			1,917			31
Administrative expense		(40	)		—			(97	)		—
Plan amendments		—			—			—			(345	)
Employee contributions		—			58			—			70

Benefit obligation at end of year	$	55,265		$	7,734		$	24,761		$	446

Change in plan assets:
Fair value of plan assets at beginning of year	$	16,039		$	—		$	13,730		$	—
Fair value of pension assets attributable to Superior Acquisition		17,718			—			—			—
Benefit payments		(1,162	)		(81	)		(861	)		(114	)
Actual return on assets		1,568			—			2,256			—
Administrative expense		(40	)		—			(97	)		—
Employee contributions		—			58			—			70
Employer contribution		1,919			23			1,011			44

Fair value of plan assets at end of year	$	36,042		$	—		$	16,039		$	—

Funded status — benefit obligation in excess of plan assets	$	(19,223	)	$	(7,734	)	$	(8,722	)	$	(446	)

Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	$	(19,223	)	$	(7,734	)	$	(8,722	)	$	(446	)

Prior service credit		—			(275	)		—			(311	)
Unrecognized net actuarial loss (gain)		8,289			553			5,236			(73	)

Accumulated other comprehensive (income) loss		8,289			278			5,236			(384	)

Net amount recognized at end of year	$	(10,934	)	$	(7,456)		$	(3,486)		$	(830)

125

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The accumulated benefit obligation for the Pension Plan was $52,543 and $24,761 as of December 31, 2011 and 2010, respectively. The accumulated benefit obligation for the Pension Plan was more than plan assets by $16,501 and $8,722 as of December 31, 2011 and 2010, respectively. Selected information for our Pension Plan with an accumulated benefit obligation in excess of plan assets were as follows:


	Year Ended December 31,
	2011		2010
Projected benefit obligation	$	55,265	$	24,761
Accumulated benefit obligation		52,543		24,761
Fair value of plan assets		36,042		16,039

The components of net periodic pension cost and other post retirement benefits cost 2011, 2010 and 2009 were as follows:


	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2011			2010			2009			2011			2010			2009
Service cost	$	296		$	84		$	250		$	114		$	—		$	9
Interest cost		1,638			1,336			1,327			96			23			44
Expected return on assets		(1,347	)		(1,034	)		(748	)		—			—			—
Amortization of net (gain) loss		281			274			381			(2	)		(3	)		(4	)
Amortization of prior service cost		—			—			—			(35	)		(35	)		—
Curtailment loss recognized		—			—			2			—			—			—

Net periodic pension cost	$	868		$	660		$	1,212		$	173		$	(15)		$	49

The components of changes recognized in other comprehensive income for the Pension Plan and Other Plan for 2011, 2010 and 2009 were as follows:


	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2011			2010			2009			2011		2010			2009
Changes in plan assets and benefit obligations recognized in other comprehensive income:
Net (gain) loss	$	3,334		$	695		$	(1,058	)	$	624	$	30		$	(82	)
New prior service cost		—			—			—			—		(345	)		—
Amounts recognized as a component of net periodic benefit cost:
Amortization or settlement recognition of net (loss) gain		(281	)		(274	)		(381	)		2		3			4
Amortization or curtailment recognition of prior service credit		—			—			—			35		35			—

Total recognized in other comprehensive loss (income)	$	3,053		$	421		$	(1,439	)	$	661	$	(277	)	$	(78	)

Total recognized in net periodic benefit and other comprehensive loss (income)	$	3,921		$	1,081		$	(227)		$	834	$	(292)		$	(29)

126

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The portion relating to the Pension Plan and Other Plan classified in accumulated other comprehensive income is $8,567 as of December 31, 2011 and the portion classified in accumulated other comprehensive loss is $4,852 as of December 31, 2010. In 2012, the estimated amount that will be amortized from accumulated other comprehensive income includes a loss of $544 for the Pension Plan. Also in 2012, the estimated amounts that will be amortized from accumulated other comprehensive income include a gain of $4 and prior service credit of $35 for the Other Plan.

All pension and other post retirement plans have a December 31 measurement date. The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2011 and 2010 were as follows:


	Benefit Obligations Assumptions
	2011			2010
Pension Plan:
Discount rate		4.59	%		5.50	%
Rate of compensation increase for Penreco Pension Plan		N/A			N/A
Rate of compensation increase for Superior Pension Plan		3.75	%		N/A

Other Plan:
Discount rate		4.62	%		4.54	%
Immediate trend rate (1)		8.00	%		8.20	%
Ultimate trend rate (1)		4.50	%		4.50	%
Year that the rate reaches ultimate trend rate (1)		2029			2029

(1)

For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The medical trend assumptions for the Superior Other Plan were changed to be consistent with the Penreco Other Plan assumptions at the December 31 measurement date. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% for 2029 for the Penreco Other Plan and Superior Other Plan and remain at that level thereafter.

127

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The significant weighted average assumptions used to determine the net periodic benefit cost for the years ended December 31, 2011 and 2010 were as follows:


	Net Periodic Benefit Cost Assumptions
	2011			2010			2009
Pension Plan:
Discount rate for Penreco Pension Plan		5.50	%		6.04	%		6.18	%
Discount rate for Superior Pension Plan		4.71	%		N/A			N/A
Expected return on plan assets (1)		6.50	%		7.50	%		7.50	%
Rate of compensation increase for Penreco Pension plan		N/A			N/A			4.50	%
Rate of compensation increase for Superior Pension plan		3.75	%		N/A			N/A

Other Plan:
Discount rate for Penreco Other Plan		4.54	%		5.55	%		6.20	%
Discount rate for Superior Other Plan		4.82	%		N/A			N/A
Immediate trend rate (2)		8.20	%		8.40	%		8.60	%
Ultimate trend rate for Penreco Other Plan (2)		4.50	%		4.50	%		4.50	%
Ultimate trend rate for Superior Other Plan (2)		5.00	%		N/A			N/A
Year that the rate reaches ultimate trend rate for Penreco Other Plan (2)		2029			2029			2029
Year that the rate reaches ultimate trend rate for Superior Other Plan (2)		2020			N/A			N/A

(1)	The Company considered the historical returns and the future expectation for returns for each asset class, as well as the target asset allocation of the Pension Plan portfolio, to develop the expected long-term rate of return on plan assets.

(2)

For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% for 2029 for the Penreco Other Plan and remain at that level thereafter. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 5.0% for 2020 for the Superior Other Plan and remain at that level thereafter.

An increase or decrease by one percentage point in the assumed healthcare cost trend rates would have the following effect on the postretirement benefit obligation and service and interest cost components of benefit costs for the Other Plan as of December 31, 2011:


	1% Point Increase		1% Point Decrease
Increase (decrease) in:
Effect on total of service and interest cost components of benefit costs		47		(36	)
Effect on postretirement benefit obligation		1,587		(1,242	)

Investment Policy

Our Pension Plan investment policy is set with specific consideration of returns and risk requirements in relationship to the respective liabilities. Given the long term nature of our liabilities, the Pension Plan has the flexibility to manage a moderate level of risk. At the investment policy level, there are no specifically prohibited investments. However, within individual investment manager mandates, restrictions and limitations are contractually set to align with our investment objectives, ensure risk control, and limit concentrations.

128

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The Company manages the portfolio to minimize any concentration of risk by allocating funds within asset categories. In addition, within a category the Company uses different managers with various management objectives to eliminate any significant concentration of risk. Management believes there are no significant concentrations of risks associated with the investment assets.

The Pension Plan’s asset allocation strategy is currently comprised of the following:


Asset Class	Range of Asset Allocations			Target Allocation
Equities		25 — 35	%		30	%
Fixed income		45 — 55	%		50	%
Capital preservation portfolio		15 — 25	%		20	%

Trust assets will be invested in accordance with prudent expert standards as mandated by the Employee Retirement Income Security Act (“ERISA”). In the event market environments create asset exposures outside of the policy guidelines, reallocations will be made in an orderly manner to rebalance the investments and maximize the effectiveness of the Pension Plan asset allocation strategy. The Company’s investment consultant will assist in the continual assessment of assets and the potential reallocation of certain investments and will evaluate the selection of investment managers for the Pension Plan based on such factors as organizational stability, depth of resources, experience, investment strategy and process, performance expectations and fees.

The Company’s Pension Plan asset allocations, as of December 31, 2011 and 2010 by asset category, are as follows:


	2011			2010
	Pension Benefits			Pension Benefits
Cash and cash equivalents (1)		62	%		2	%
Equity		11	%		49	%
Foreign equities		2	%		12	%
Fixed income		18	%		37	%
Commingled fund		7	%		0	%

		100	%		100	%

(1)	The Superior Pension Plan assets are included in cash and cash equivalents and such assets will be invested in 2012 based upon the current investment policy.

129

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The Company’s investments associated with its Pension Plan primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded and (iii) a commingled fund. The mutual funds are publicly traded and market prices of the mutual funds are readily available, thus these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of the shares held by the Pension Plan at year end. See Note 10 for the definition of the Levels 1, 2 and 3. The Company’s Pension Plan assets measured at fair value at December 31, 2011 and 2010 were as follows:


	Fair Value of Pension Assets at December 31,
	2011				2010
	Level 1		Level 2		Level 1		Level 2
Cash and cash equivalents	$	22,243	$	—	$	347	$	—
Equity		4,000		—		7,784		—
Foreign equities		691		—		1,890		—
Commingled fund		—		2,462		—		—
Fixed income		6,646		—		6,018		—

	$	33,580	$	2,462	$	16,039	$	—

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2011:


	Pension Benefits		Other Post Retirement Employee Benefits
2012	$	2,259	$	128
2013		2,374		147
2014		2,465		159
2015		2,579		182
2016		2,701		206
2017 to 2021		15,828		1,924

Total	$	28,206	$	2,746

The Company participated in two multi-employer plans as a result of the acquisition of Penreco. The Company elected to withdraw from these plans in 2009 and made a final contribution of approximately $183 to the Penreco Local 710 Health, Welfare and Pension Funds plan and agreed to the final settlement of approximately $1,863 for the Western Pennsylvania Teamsters and Employers Pension Fund to be paid over 30 years. As of December 31, 2011, $1,055 was outstanding under the final settlement.

14.

Transactions with Related Parties

During the years ended December 31, 2011, 2010 and 2009, the Company had product sales to related parties owned by a limited partner of $16,500, $4,727 and $3,208, respectively. Trade accounts and other receivables from related parties at December 31, 2011 and 2010 were $1,818 and $422, respectively. The Company also had purchases from related parties owned by a limited partner, excluding crude purchases related to the Legacy Resources Co., L.P. (“Legacy Resources”) agreements and director’s and officers’ liability insurance premiums discussed below, during the years ended December 31, 2011, 2010 and 2009 of $1,768, $1,480 and $1,718, respectively. Accounts payable to related parties, excluding accounts payable related to the

130

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Legacy Resources agreements discussed below, at December 31, 2011 and 2010 were $1,393 and $1,246, respectively.

Legacy Resources is owned in part by one of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and vice chairman of the board of our general partner, F. William Grube, and the Company’s president and chief operating officer, Jennifer G. Straumins.

From May 2008 to May 2011, the Company purchased all of its crude oil requirements for its Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources (the “Legacy Princeton Agreement”). In addition, in January 2009, the Company entered into an agreement with Legacy Resources to begin purchasing certain of its crude oil requirements for its Shreveport refinery utilizing a market-based pricing mechanism from Legacy (the “Master Crude Oil Purchase and Sale Agreement”). In September 2009, the Company entered into a crude oil supply agreement with Legacy Resources (the “Legacy Shreveport Agreement”). Under the Legacy Shreveport Agreement, Legacy Resources supplied the Company’s Shreveport refinery with a portion of its crude oil requirements on a just in time basis utilizing a market-based pricing mechanism.

On May 31, 2011, the Company terminated the Legacy Princeton Agreement and the Legacy Shreveport Agreement and did not incur any material early termination penalties in connection with their termination. With the termination of these agreements, the Company has one remaining crude oil supply agreement with Legacy, the Master Crude Oil Purchase and Sale Agreement. No crude oil is currently being purchased by the Company under this agreement. During the years ended December 31, 2011 and 2010 and 2009, the Company had crude oil purchases of $229,793, $591,777 and $390,231, respectively, from Legacy Resources. Accounts payable to Legacy Resources at December 31, 2011 and 2010 related to these agreements were $574 and $26,739, respectively.

Nicholas J. Rutigliano, a member of the board of directors of our general partner, founded and is the president of Tobias Insurance Group, Inc. (“Tobias”), a commercial insurance brokerage business, that has historically placed our directors’ and officers’ liability insurance. The total premiums paid to Tobias by the Company for the years ended December 31, 2011, 2010 and 2009 were $566, $638 and $672, respectively. With the exception of its directors’ and officers’ liability insurance which were placed with this commercial insurance brokerage company, the Company placed its insurance requirements with third parties during the years ended December 31, 2011, 2010 and 2009.

15.

Segments and Related Information

a. Segment Reporting

The Company has two reportable segments: Specialty Products and Fuel Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes and asphalt. 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, jet fuel and heavy fuel oils. The Company sells the majority of the fuel products it produces to markets located in Arkansas, Iowa, Louisiana, Michigan, Minnesota, Montana, North Dakota, South Dakota, east Texas and Wisconsin. The Company also has the ability to ship additional fuel products to the Midwest region and the northern states bordering Canada through the TEPPCO and Magellan pipelines should the need arise. The assets and results of the operations from such assets acquired as a result of the Superior Acquisition have been included in the both segments since the date of acquisition, September 30, 2011.

131

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 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:


Year Ended December 31, 2011	Specialty Products		Fuel Products			Combined Segments		Eliminations			Consolidated Total
Sales:
External customers	$	1,807,626	$	1,327,297		$	3,134,923	$	—		$	3,134,923
Intersegment sales		1,079,338		46,119			1,125,457		(1,125,457	)		—

Total sales	$	2,886,964	$	1,373,416		$	4,260,380	$	(1,125,457	)	$	3,134,923

Depreciation and amortization		70,084		4,309			74,393		—			74,393
Operating income (loss)		134,844		(9,552	)		125,292		—			125,292
Reconciling items to net income:
Interest expense												(48,747	)
Debt extinguishment costs												(15,130	)
Loss on derivative instruments												(18,292	)
Other												842
Income tax expense												(929	)

Net income											$	43,036

Capital expenditures	$	45,141	$	4,337		$	49,478	$	—		$	49,478

Year Ended December 31, 2010	Specialty Products		Fuel Products			Combined Segments		Eliminations			Consolidated Total
Sales:
External customers	$	1,408,872	$	781,880		$	2,190,752	$	—		$	2,190,752
Intersegment sales		775,366		39,410			814,776		(814,776	)		—

Total sales	$	2,184,238	$	821,290		$	3,005,528	$	(814,776	)	$	2,190,752

Depreciation and amortization		70,293		—			70,293		—			70,293
Operating income (loss)		73,194		(1,704	)		71,490		—			71,490
Reconciling items to net income:
Interest expense												(30,497	)
Debt extinguishment costs												—
Loss on derivative instruments												(23,547	)
Other												(147	)
Income tax expense												(598	)

Net income											$	16,701

Capital expenditures	$	35,001	$	—		$	35,001	$	—		$	35,001

132

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)



Year Ended December 31, 2009	Specialty Products		Fuel Products		Combined Segments		Eliminations			Consolidated Total
Sales:
External customers	$	971,220	$	875,380	$	1,846,600	$	—		$	1,846,600
Intersegment sales		724,062		25,023		749,085		(749,085	)		—

Total sales	$	1,695,282	$	900,403	$	2,595,685	$	(749,085	)	$	1,846,600

Depreciation and amortization		68,991		—		68,991		—			68,991
Operating income		48,161		19,199		67,360		—			67,360
Reconciling items to net income:
Interest expense											(33,573	)
Debt extinguishment costs											—
Gain on derivative instruments											32,078
Other											(3,929	)
Income tax expense											(151	)

Net income										$	61,785

Capital expenditures	$	23,521	$	—	$	23,521	$	—		$	23,521


	December 31,
	2011		2010
Segment assets:
Specialty products	$	1,159,040	$	962,850
Fuel products		573,018		53,822

Total assets	$	1,732,058	$	1,016,672

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2011, 2010 and 2009. All of the Company’s long-lived assets are domestically located.

133

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

c. Product Information

The Company offers products primarily in five general categories consisting of lubricating oils, solvents, waxes, fuels and asphalt and by-products. Fuel products primarily consist of gasoline, diesel, jet fuel and heavy fuel oils and other. The following table sets forth the major product category sales:


	Year Ended December 31,
	2011		2010		2009
Specialty products:
Lubricating oils	$	947,798	$	759,701	$	500,938
Solvents		495,934		396,894		260,185
Waxes		143,111		124,964		97,658
Fuels		3,432		5,507		8,951
Asphalt and other by-products		217,351		121,806		103,488

Total		1,807,626		1,408,872		971,220

Fuel products:
Gasoline		619,630		304,544		317,435
Diesel		513,334		330,756		372,359
Jet fuel		148,036		135,796		167,638
Heavy fuel oils and other		46,297		10,784		17,948

Total		1,327,297		781,880		875,380

Consolidated sales	$	3,134,923	$	2,190,752	$	1,846,600

d. Major Customers

During the years ended December 31, 2011, 2010 and 2009, the Company had no customer that represented 10% or greater of consolidated sales.

16.

Quarterly Financial Data (Unaudited)


	First Quarter		Second Quarter			Third Quarter		Fourth Quarter		Total (1)
2011
Sales	$	605,240	$	733,770		$	777,780	$	1,018,133	$	3,134,923
Gross profit		46,864		50,565			96,601		80,100		274,130
Net income (loss)		4,201		(7,651	)		19,614		26,872		43,036
Net income (loss) available to limited partners		4,117		(7,498	)		19,182		26,052		41,853
Limited partners’ interest basic and diluted net income (loss) per unit	$	0.11	$	(0.19	)	$	0.46	$	0.50	$	0.98
Weighted average limited partner units outstanding — basic		36,875,000		39,886,000			41,828,000		51,589,000
Weighted average limited partner units outstanding — diluted		36,895,000		39,886,000			41,837,000		51,600,000

134

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)


	First Quarter			Second Quarter			Third Quarter		Fourth Quarter		Total (1)
2010
Sales	$	484,616		$	514,652		$	595,273	$	596,210	$	2,190,752
Gross profit		31,675			49,619			62,106		55,348		198,749
Net income (loss)		(13,067	)		(907	)		21,221		9,454		16,701
Net income (loss) available to limited partners		(12,806	)		(889	)		20,797		9,265		16,367
Limited partners’ interest basic and diluted net income (loss) per unit	$	(0.36	)	$	(0.03	)	$	0.59	$	0.26	$	0.46
Weighted average limited partner units outstanding — basic		35,351,000			35,359,000			35,337,000		35,341,939
Weighted average limited partner units outstanding — diluted		35,351,000			35,359,000			35,352,000		35,361,456

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

17.

Subsequent Events

On January 3, 2012, the Company completed the acquisition of the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) of Hercules Incorporated, a subsidiary of Ashland, Inc. for aggregate consideration of approximately $19,591, excluding certain customary post-closing purchase price adjustments. The acquisition was financed with borrowings under the Company’s revolving credit facility and cash on hand. The Company also acquired a manufacturing facility located in Louisiana, Missouri.

On January 6, 2012, the Company completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC, a specialty petroleum packaging and distribution company located in Shreveport, Louisiana (“TruSouth”) for aggregate consideration of approximately $25,544, which was financed with borrowings under the Company’s revolving credit facility. Immediately prior to its acquisition by the Company, TruSouth was owned in part by affiliates of the Company’s general partner. As a result, the terms of the acquisition of TruSouth were reviewed by the conflicts committee of the board of directors of the Company’s general partner, which consists entirely of independent directors. The conflicts committee approved the agreement after determining that the terms of the acquisition of TruSouth were fair and reasonable to the Company.

On January 23, 2012, the Company declared a quarterly cash distribution of $0.53 per unit on all outstanding units, or approximately $28,190 in aggregate, for the quarter ended December 31, 2011. The distribution was paid on February 14, 2012 to unitholders of record as of the close of business on February 3, 2012. This quarterly distribution of $0.53 per unit equates to $2.12 per unit, or approximately $112,760 in aggregate on an annualized basis.

On December 16, 2011, the Company filed an exchange offer registration statement for the 2019 Notes with the SEC, which was declared effective on January 3, 2012. The exchange offer was completed on February 2, 2012, thereby fulfilling all of the requirements of the 2019 Notes registration rights agreements by the specified dates.

The fair value of the Company’s derivatives decreased by approximately $101,000 subsequent to December 31, 2011 to a liability of approximately $86,000. The fair value of the Company’s long-term debt, excluding capital leases, has increased by approximately $36,000 subsequent to December 31, 2011.

135

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2011 at the reasonable assurance level. See Management’s Report on Internal Control Over Financial Reporting included in Item 8 “Financial Statements and Supplementary Data”.

Changes in Internal Control over Financial Reporting

There have been no changes to our internal controls over financial reporting during the fourth quarter of fiscal year 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On September 30, 2011, we completed the Superior Acquisition, which includes certain existing information systems and internal controls over financial reporting that previously existed. In conducting our evaluation of effectiveness of our internal control over financial reporting, we have elected to exclude the Superior Business from our evaluation, as permitted under existing SEC rules. We are currently in the process of evaluating and integrating the Superior Business’ historical internal controls over financial reporting with ours. We expect to complete this integration in fiscal year 2012.

See Management’s Report on Internal Control Over Financial Reporting included in Item 8 “Financial Statements and Supplemental Data”.

136

Item 9B.

Other Information

None.

PART III

Item 10.

Directors, Executive Officers of Our General Partner and Corporate Governance

Management of Calumet Specialty Products Partners, L.P. and Director Independence

Our general partner, Calumet GP, LLC, manages our operations and activities. Unitholders are limited partners and are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to our unitholders, as limited by the various provisions of our partnership agreement modifying and restricting the fiduciary duties that might otherwise be owed by our general partner to our unitholders.

The directors of our general partner oversee our operations. The owners of our general partner have appointed seven members to our general partner’s board of directors. The directors of our general partner are generally elected by a majority vote of the owners of our general partner on an annual basis. However, as long as our chief executive officer and vice chairman of our general partner, F. William Grube, or trusts established for the benefit of his family members, continue to own at least 30% of the membership interests in our general partner, Mr. Grube (or in certain specified instances, his designee or transferee) has the right to serve as a director of our general partner. The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified.

Pursuant to Section 4360 of the NASDAQ Stock Market (“NASDAQ”) Marketplace Rules, NASDAQ does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. However, three of our general partner’s seven directors are “independent” as that term is defined in the applicable NASDAQ rules and Rule 10A-3 of the Exchange Act. In determining the independence of each director, our general partner has adopted standards that incorporate the NASDAQ and Exchange Act standards. Our general partner’s independent directors as determined in accordance with those standards are: James S. Carter, Robert E. Funk and George C. Morris III.

The officers of our general partner manage the day-to-day affairs of our business. Officers serve at the discretion of the board of directors.

137

Directors and Executive Officers

The following table shows information regarding the directors and executive officers of Calumet GP, LLC as of February 29, 2012.


Name	Age		Position with Calumet GP, LLC
Fred M. Fehsenfeld, Jr.		61	Chairman of the Board
F. William Grube		64	Chief Executive Officer and Vice Chairman of the Board
Jennifer G. Straumins		38	President and Chief Operating Officer
R. Patrick Murray, II		40	Vice President, Chief Financial Officer and Secretary
Timothy R. Barnhart		52	Vice President — Operations
William A. Anderson		43	Vice President — Sales and Marketing
Robert M. Mills		58	Vice President — Crude Oil Supply
Jeffrey D. Smith		49	Vice President — Planning and Economics
James S. Carter		63	Director
William S. Fehsenfeld		61	Director
Robert E. Funk		66	Director
George C. Morris III		56	Director
Nicholas J. Rutigliano		64	Director

All members of the board of directors are elected for one-year terms and until their successors have been elected and qualified. Each director’s biographical information set forth below includes the particular experience and qualifications that led the board of directors to conclude that the director is qualified to serve in such capacity.

Fred M. Fehsenfeld, Jr. has served as the chairman of the board of our general partner since September 2005. Mr. Fehsenfeld also served as the vice chairman of the board of our Predecessor from 1990 until our initial public offering. 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.

As co-founder of our Predecessor, Mr. Fehsenfeld has an extensive knowledge base regarding the Company’s operations and has participated in all major strategic decision making for the Company and our Predecessor since their inception. In his role as managing trustee of The Heritage Group, Mr. Fehsenfeld serves in lead executive roles, including the role of chairman and chief executive officer, for a multitude of different companies within The Heritage Group, providing breadth of experience in leadership and management across a wide variety of industries, including energy. Since 2008, Mr. Fehsenfeld has served as chairman of the board of directors of Heritage-Crystal Clean, Inc., a publicly-traded environmental services company which is owned in part by The Heritage Group.

F. William Grube has served as the chief executive officer and vice chairman of the board of our general partner since January 2011. From September 2005 through December 2010, Mr. Grube served as chief executive officer, president and director of our general partner. Mr. Grube has also served as president and chief executive officer of our Predecessor from 1990 until our initial public offering. From 1973 to 1989, Mr. Grube served as executive vice president of Rock Island Refining Corporation. Mr. Grube received his B.S. in Chemical Engineering from Rose-Hulman Institute of Technology and his M.B.A. from Harvard University. Mr. Grube is the father of Jennifer G. Straumins, president and chief operating officer of our general partner.

As co-founder of our Predecessor and through his role as the chief executive officer since inception, Mr. Grube possesses unique experience relative to the management of the Company on a day-to-day basis over a significant time period and across all functional areas of the Company. Mr. Grube has significant technical expertise in refining developed over the course of his career, with both the Company and our Predecessor, as well as another refining company which specialized in the production of fuel products.

138

Jennifer G. Straumins has served as president and chief operating officer of our general partner since January 2011. From December 2009 through December 2010, Ms. Straumins served as executive vice president and chief operating officer of our general partner. From February 2007 through December 2009, Ms. Straumins served as senior vice president of our general partner. From January 2006 through February 2007, Ms. Straumins served as vice president — investor relations of our general partner. Ms. Straumins served in various capacities in financial planning and economics for our Predecessor from 2002 until our initial public offering. Prior to joining our Predecessor, Ms. Straumins held financial planning positions with Great Lakes Chemical Company and Exxon Chemical Company. Ms. Straumins received a B.E. in Chemical Engineering from Vanderbilt University and her M.B.A. from the University of Kansas. Ms. Straumins is the daughter of F. William Grube, the chief executive officer and vice chairman of the board of our general partner.

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

Timothy R. Barnhart has served as vice president — operations of our general partner since December 2009. Mr. Barnhart served as the plant manager of our Karns City facility from January 2008 to December 2009. Prior to joining Calumet in 2008 upon our acquisition of Penreco, Mr. Barnhart held various engineering, supervisory and management positions at Penreco and Pennzoil Products Company since 1981. Mr. Barnhart received his B.S. in Engineering from Grove City College.

William A. Anderson has served as vice president — sales and marketing of our general partner since September 2005. Mr. Anderson served as vice president — sales and marketing of our Predecessor from 2000 until our initial public offering and served in various other capacities from 1993 to 2000. Mr. Anderson received his B.A. in Communications from DePauw University.

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

Jeffrey D. Smith has served as vice president — planning and economics of our general partner since September 2005. He served as vice president — planning and economics of our Predecessor from 2002 until our initial public offering. 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.

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

Mr. Carter brings extensive marketing and managerial experience with one of the largest integrated energy companies in the world. He possesses a broad background in petroleum products marketing, with specific experience in the marketing of fuel products.

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

139

In his role as a trustee of The Heritage Group, which held the controlling interest in our Predecessor, Mr. Fehsenfeld has extensive knowledge of the Company and its operations over time and has been involved in strategic decision making for the Company during his tenure. His role as a trustee of The Heritage Group provides significant breadth of oversight experience of a multitude of companies across various industry sectors, including energy. As a founder and owner of a successful independent bookselling business, Mr. Fehsenfeld also brings executive management and entrepreneurial skills to the board of directors.

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

Mr. Funk has extensive refining industry experience including planning, operations and managerial roles for a large multinational refining company. His broad background of experience provides helpful insight to the Company in its implementation of strategic initiatives and its refinery operations in general.

George C. Morris III has served as a member of the board of directors of our general partner since May 2009. Mr. Morris has served as president of Morris Energy Advisors, Inc. since March 2009 and most recently served as a managing director at Merrill Lynch & Co. from December 2006 until his retirement in March 2009. Mr. Morris served as a managing director of investment banking at Petrie Parkman & Co. until its acquisition by Merrill Lynch in December 2006 and also served as a managing director of investment banking at Simmons & Company International and as a director of investment banking at First Boston Corporation. Mr. Morris holds B.B.A. and M.B.A. degrees from the University of Texas and a J.D. from Southern Methodist University.

Mr. Morris’ long tenure in the investment banking industry with a focus on the energy sector provides unique breadth of experience to the board of directors in areas of finance and capital markets. In his role as a financial advisor to the Company prior to joining the board of directors, Mr. Morris gained significant insight into the Company’s operations and strategy.

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

In his role as a trustee of The Heritage Group, which held the controlling interest in our Predecessor, Mr. Rutigliano has extensive knowledge of the Company and its operations over time and has been involved in strategic decision making for the Company from the inception of the Company’s Predecessor. His role as a trustee of The Heritage Group provides significant breadth of oversight experience of a multitude of companies across various industry sectors, including energy. As the founder and chief executive officer of a successful commercial insurance brokerage business, Mr. Rutigliano brings unique risk management, executive management and entrepreneurial skills to the board of directors.

Board of Directors Committees

Conflicts Committee

Two members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may

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not be owners, officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by NASDAQ and the Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The two independent board members who serve on the conflicts committee are Messrs. James S. Carter and Robert E. Funk. Mr. Carter serves as the chairman of the conflicts committee.

Compensation Committee

The board of directors of our general partner also has a compensation committee which, among other responsibilities, oversees the compensation plans awarded to directors, officers and key employees described in Item 11 “Executive and Director Compensation.” NASDAQ does not require a limited partnership like us to have a compensation committee comprised entirely of independent directors. Accordingly, Messrs. Fred M. Fehsenfeld, Jr. and F. William Grube serve as members of our compensation committee. Mr. Fehsenfeld serves as the chairman of the compensation committee.

The board of directors has adopted a written charter for the compensation committee which defines the scope of the committee’s authority. The committee may form and delegate some or all of its authority to subcommittees comprised of committee members when it deems appropriate. The committee is responsible for reviewing and recommending to the board of directors for its approval the annual salary and other compensation components for the chief executive officer. The committee reviews and makes recommendations to the board of directors for its approval any of the Company’s equity compensation-based plans, including the Long-Term Incentive Plan, or any cash bonus or incentive compensation plans or programs. Also, the committee reviews and approves all annual salary and other compensation arrangements and components for the senior executives of the Company. Further, the compensation committee periodically reviews and makes a recommendation to the board of directors for changes in the compensation of all directors. The committee has the authority to retain and terminate any compensation consultant to assist it in the evaluation of director and senior executive compensation and to obtain independent advice and assistance from internal and external legal, accounting and other advisors.

See Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Peer Group and Compensation Targets” for additional discussion regarding the results of this executive compensation review.

Audit Committee

The board of directors of our general partner has an audit committee comprised of three directors, Messrs. James S. Carter, Robert E. Funk and George C. Morris III, each of whom the board of directors of our general partner has determined meets the independence and experience standards established by NASDAQ and the SEC. In addition, the board of directors of our general partner has determined that Mr. Morris is an “audit committee financial expert” as defined by the SEC. Mr. Morris serves as the chairman of the audit committee.

The board of directors has adopted a written charter for the audit committee. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof and pre-approves any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee.

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Code of Ethics

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

Available on our website at www.calumetspecialty.com are copies of our board of directors committee charters and Code of Business Conduct and Ethics, all of which also will be provided to unitholders without charge upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, IN 46214.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires Calumet’s directors and certain executive officers, as well as beneficial owners of ten percent or more of Calumet’s common units, to report their holdings and transactions in Calumet’s securities. Based on information furnished to Calumet and contained in reports provided pursuant to Section 16(a), as well as written representations that no other reports were required for 2011, Calumet’s directors and executive officers filed all reports required by Section 16(a).

Item 11.

Executive and Director Compensation

Compensation Discussion and Analysis

Overview

The compensation committee of the board of directors of our general partner oversees our compensation programs. Our general partner maintains compensation and benefits programs designed to allow us to attract, motivate and retain the best possible employees to manage us, including executive compensation programs designed to reward the achievement of both short-term and long-term goals necessary to promote growth and generate positive unitholder returns. Our general partner’s executive compensation programs are based on a pay-for-performance philosophy, including measurement of our performance against a specified financial target, namely distributable cash flow. Our executive compensation programs include both long-term and short-term compensation elements which, together with base salary and employee benefits, constitute a total compensation package intended to be competitive with similar companies.

Under their collective authority, the compensation committee and the board of directors maintain the right to develop and modify compensation programs and policies as they deem appropriate. Factors they may consider in making decisions to materially increase or decrease compensation include our overall financial performance, our growth over time, our changes in complexity as well as individual executive job scope complexity, individual executive job performance and changes in competitive compensation practices in our defined labor markets. In determining any forms of compensation other than the base salary for the senior executives, or in the case of the chief executive officer the recommendation to the board of directors of the forms of compensation for the chief executive officer, the compensation committee considers our financial performance and relative unitholder return, the value of similar incentive awards to senior executives at comparable companies and the awards given to senior executives in past years.

Financial Performance Metric Used in Compensation Programs

Our primary business objective is to generate cash flows to make distributions to our unitholders. As a result, our distributable cash flow is the primary measurement of performance taken into account in setting policies and making compensation decisions, as we believe this represents the most comprehensive measurement of our ability to generate cash flows. Both short-term and long-term forms of executive compensation are specifically structured on our achievement relative to annual distributable cash flow goals and, as such, determination of related awards, as well as their grant or payment, occurs subsequent to the end of each fiscal year upon final determination of distributable cash flow. We believe that including this financial objective as the primary performance measurement to determine compensation awards for all of our executive officers recognizes

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the integrated and collaborative effort required by the full executive team to maximize performance. Distributable cash flow is a non-GAAP measure that we define, consistent with the terms of our revolving credit agreement and senior notes indentures, as our Adjusted EBITDA less replacement capital expenditures, cash interest expense, turnaround costs and income tax expense. Please refer to Part II, Item 6 “Selected Financial Data — Non-GAAP Financial Measures” for our definition of Adjusted EBITDA.

Peer Group and Compensation Targets

To evaluate all areas of executive compensation, the compensation committee seeks the additional input of outside compensation consultants and available comparative information to validate that the compensation programs established for our executives are consistent with the philosophy of compensating our executives at ranges that approximate within 15% of the median of market for companies of similar size to us. In 2010, the compensation committee retained Buck Consultants, LLC (“Buck Consultants”) as an independent consultant to review our general partner’s executive compensation programs. Buck Consultants reported directly to the compensation committee and did not provide any additional services to our general partner. The scope of this engagement included the following:

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review of a peer group of publicly-traded master limited partnerships for executive compensation benchmarking;

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analysis of market pay levels and trends for our named executive officers, other officers and key employees from peer companies including base salary, annual incentives and long-term incentives; and

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assessment of Calumet’s executive pay levels relative to overall market levels.

The following master limited partnerships were included by Buck Consultants in the peer group for the compensation review: Atlas Pipeline Partners, L.P., Buckeye Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, L.P., DCP Midstream Partners, LP, Genesis Energy, L.P., Inergy Holdings, L.P., Magellan Midstream Partners, L.P., MarkWest Energy Partners, L.P., Penn Virginia Resource Partners, L.P., Regency Energy Partners LP and Suburban Propane Partners, L.P. Peer group companies were validated and selected based on their comparability of EBITDA (a non-GAAP measurement), sales and market capitalization to those of Calumet. Market data compiled from public disclosures of the peer group companies were used in the review to benchmark our compensation of the key executive group against the market. Buck Consultants provided a presentation of its findings to the compensation committee in October 2010.

The compensation committee used the findings of the Buck Consultants executive compensation review to validate the total competitiveness of compensation for Calumet’s key executives, including each named executive officer. Specifically, the Buck Consultants review indicated that Calumet’s aggregate target total direct compensation of its key executives, which includes all the major elements of its executive compensation program, including base salary, short-term incentives and long-term compensation, was above the median of market by less than 15%. While the Buck Consultants review indicated that aggregate base salaries for key executives fall at the median of the peer group, aggregate short-term incentives for the key executives, assuming the target levels of such incentives are achieved, fall below the 75th percentile of the market by less than 10%. As a result of higher short-term incentives, total cash compensation of our key executives, in aggregate, falls above the median of the peer group by approximately 10%. Long-term incentives for the key executives fall above the median of the peer group by less than 15%.

Review of Named Executive Officer Performance

The compensation committee reviews, on an annual basis, each compensation element of a named executive officer. In each case, the compensation committee takes into account the scope of responsibilities and experience and balances these against competitive salary levels. The compensation committee has the opportunity to meet with the named executive officers at various times during the year, which allows the compensation committee to form its own assessment of each individual’s performance.

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Objectives of Compensation Programs

Our executive compensation programs are designed with the following primary objectives:

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reward strong individual performance that drives our positive financial results;

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make incentive compensation a significant portion of an executive’s total compensation, designed to balance short-term and long-term performance;

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align the interests of our executives with those of our unitholders; and

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attract, develop and retain executives with a compensation structure that is competitive with other publicly-traded partnerships of similar size.

Elements of Executive Compensation

The compensation committee believes the total compensation and benefits program for our named executive officers should consist of the following:

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base salary;

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annual incentive plan which includes short-term cash awards and also includes an optional deferred compensation element;

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long-term incentive compensation, including unit-based awards;

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retirement, health and welfare benefits; and

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perquisites.

These elements are designed to constitute an integrated executive compensation structure meant to incentivize a high level of individual executive officer performance in line with our financial and operating goals.

Base Salary

Salaries provide executives with a base level of monthly income as consideration for fulfillment of certain roles and responsibilities. The salary program assists us in achieving our objective of attracting and retaining the services of quality individuals who are essential for the growth and profitability of Calumet. Generally, changes in the base salary levels for our named executive officers are determined on an annual basis by the compensation committee of the board of directors and are effective at the beginning of the following fiscal year.

Mr. Grube’s initial base salary was established under his employment agreement, which provides that the amount of his annual salary increase must be at least equal to the average of the percentage increases of all salaried employees of Calumet’s general partner. For fiscal years 2011 and 2012, after taking into account the increases to base salary made for fiscal 2010, the compensation committee determined to increase base salaries for our other executive officers based on the same criteria. Accordingly, the salary increases for 2011 and 2012 were approximately 3.1% and 3.2%, respectively, which was equivalent to the average of the percentage increases of all salaried employees for each of those fiscal years.

Short-Term Cash Awards

Under the Cash Incentive Compensation Plan (the “Cash Incentive Plan”), short-term cash awards are designed to aid Calumet in retaining and motivating executives to assist us in meeting its financial performance objectives on an annual basis. Short-term cash awards are granted to named executive officers and certain other management employees based on Calumet’s achievement of performance targets on its distributable cash flow, thereby establishing a direct link between executive compensation and our financial performance.

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The compensation committee establishes minimum, target and stretch incentive opportunities for each executive officer and other key employees expressed as a percentage of base salary. The amount that is paid out is based on Calumet’s achievement of a minimum, target or stretch level of distributable cash flow for the fiscal year. Generally, no awards are paid under the Cash Incentive Plan unless we achieve at least the minimum distributable cash flow goal. The compensation committee can recommend to the full board of directors, however, that cash awards be given notwithstanding the fact that we failed to achieve at least the minimum distributable cash flow goal. If the minimum, target or stretch level distributable cash flow goal is achieved, participants in the plan will receive their minimum, target or stretch cash award opportunity, respectively. If our distributable cash flow is between specified goal levels, participants are eligible to receive a prorated percentage of their cash award opportunity based on where the actual distributable cash flow amount falls between the levels. For fiscal year 2011, the minimum distributable cash flow goal was $79.4 million, the target goal was $89.6 million and the stretch goal was $110.0 million. For the reasons described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 2011 Update,” we achieved our stretch goal with a 2011 distributable cash flow of $126.4 million.

The following table summarizes the levels of cash award opportunity for each named executive officer and the actual percentage earned by them in 2011:


	Cash Incentive Award Opportunity as a Percentage of Base Salary
	Minimum			Target			Stretch			Actual Payout
F. William Grube		50	%		100	%		200	%		217	%(1)
Jennifer G. Straumins, R. Patrick Murray, II, Timothy R. Barnhart and William A. Anderson		50	%		100	%		200	%		200	%

(1)	Mr. Grube’s employment agreement guarantees him a potential award that is at least 150% of the amount of the next highest potential award by any other executive officer of our general partner, which would be the maximum potential award for Ms. Straumins of $577,000.

The compensation committee determined these percentages of base salary at levels, when combined with both base salary and potential long-term, unit-based awards, to develop a total direct compensation structure for the named executive officers which is intended to be within 15% of the median of our peer group, while placing significant emphasis on the achievement of our distributable cash flow goals.

At the recommendation of the compensation committee, the board of directors approves distributable cash flow targets for each fiscal year based on budgets prepared by management. When making the annual determination of the minimum goal, target goal and stretch goal levels of distributable cash flow, the compensation committee and the board of directors consider the specific circumstances facing us during the relevant year. Generally, the compensation committee seeks to set the minimum goal, target goal and stretch goal levels such that the relative challenge of achieving each level is consistent from year to year. The expectation that management will achieve the minimum goal level is very high, while meaningful additional effort would be required to achieve the target goal and considerable additional effort would be required to achieve the stretch goal.

For 2011, the target goal for distributable cash flow was set at the budgeted amount, a level that the board of directors believed reflected the reasonable expectations management had for our financial performance during the fiscal year and likely to be achieved given actual distributable cash flow achieved for the 2010 fiscal year. The board of directors set the stretch cash flow goal at 23% above the budgeted amount, a level which they believed would be attained only with higher levels of performance relative to the reasonable expectations management had for our financial performance and therefore not likely to be achieved. The minimum goal was set at approximately 11% below the budgeted amount.

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For the 2011 fiscal year, our distributable cash flow was above the stretch goal. As described in greater detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 2011 Update,” the primary drivers of us exceeding our distributable cash flow targets were higher gross profit per barrel of specialty products sold and higher sales volume of both specialty products and fuel products consistent with higher production at our facilities overall.


Distributable Cash Flow (In millions)
Fiscal Year	Actual			Minimum Goal		Target Goal		Stretch Goal
2011	$	126.4	(1)(2)	$	79.4	$	89.6	$	110.0
2010	$	79.8	(1)(2)	$	79.4	$	89.6	$	110.0
2009	$	101.7	(2)	$	101.2	$	126.6	$	157.2

(1)	As adjusted. When assessing our 2010 performance with respect to our distributable cash flow targets, the compensation committee determined it was appropriate to include an interim payment of certain insurance proceeds. Such amounts were excluded from distributable cash flow for 2011.

(2)

For 2011, we adjusted the calculation of Distributable Cash Flow to reflect calculations contained in our debt instruments. For additional information please read Part II, Item 6 “Selected Financial Data — Non-GAAP Financial Measures” for our definition of Distributable Cash Flow. For 2010 and 2009 Distributable Cash Flow calculations, please refer to our 2010 and 2009 Annual Reports.

Upon the recommendation of the compensation committee, the board of directors has approved new distributable cash flow targets for the 2012 fiscal year based on budgets prepared by management. We do not disclose our confidential 2012 targets, which, if disclosed, would put us at a competitive disadvantage. As reflected in the table above, the performance targets we established for 2011, 2010 and 2009 illustrate on a historical basis the relative difficulty of attaining each level.

For further description of this compensation program, please see “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Cash Incentive Plan.”

Executive Deferred Compensation Plan

The compensation committee allows for the participation of the executive officers in the Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan (the “Deferred Compensation Plan”) to encourage the officers to save for retirement and to assist us in retaining our officers. The Deferred Compensation Plan is intended to promote retention by giving employees an opportunity to save in a tax-efficient manner. The terms governing the retirement benefit under this plan for the executive officers are the same as those available for other eligible employees in the U.S. Pursuant to the Deferred Compensation Plan, a select group of management, including the named executive officers, and all of the non-employee directors are eligible to participate by making an annual irrevocable election to defer, in the case of management, all or a portion of their annual cash incentive award under the Cash Incentive Plan, and, in the case of non-management directors, all or none of their annual cash retainer. The deferred amounts are credited to participant’s accounts in the form of phantom units, with each such phantom unit representing a notional unit that entitles the holder to receive either an actual common unit or the cash value of a common unit (determined by using the fair market value of a common unit at the time a determination is needed). The phantom units credited to each Plan participant’s account also receive distribution equivalent rights (“DERs”), which are credited to the participant’s account in the form of additional phantom units. In our sole discretion, we may make matching contributions of phantom units or purely discretionary contributions of phantom units, in amounts and at times as it determines. On February 28, 2011, we made discretionary matching contributions of phantom units to the accounts of those participants in the Deferred Compensation Plan, including certain of the named executive officers, who elected to defer all or a portion of their annual cash incentive award, related to the 2010 fiscal year. These contributions, which were subject to continued service vesting requirements, were made as a reward for prior service and future efforts toward our success and growth, as well as an incentive for continued participation through elective

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deferrals into the Deferred Compensation Plan allowing participants to save in a tax-efficient manner knowing that we, in our discretion, may make such matching contributions. Please see “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Nonqualified Deferred Compensation — Nonqualified Deferred Compensation Table for 2011” for a more detailed disclosure of the value of contributions into this plan, as well as the DERs associated with such contributions.

Long-Term, Unit-Based Awards

Long-term unit-based awards may consist of phantom units, restricted units, unit options, substitution awards and DERs. These awards are granted to employees, consultants and directors of our general partner under the provisions of our Long-Term Incentive Plan, as amended, (the “Plan”) originally adopted on January 24, 2006 and administered by the compensation committee. These awards aid Calumet in retaining and motivating executives to assist us in meeting our financial performance objectives.

In fiscal year 2011, the annual unit award opportunity to named executive officers consisted of the contingent right to receive phantom units. Under the Plan, phantom units are granted only upon our achievement of specified levels of distributable cash flow. When granted, phantom units are subject to further time-based vesting criteria specified in the grant. Upon satisfaction of the time-based vesting criteria specified in the grant, phantom units convert into common units (or cash equivalent). Accordingly, these awards established a direct link between executive compensation and our financial performance. This component of executive compensation, when coupled with an extended ratable vesting period as compared to cash awards, further aligns the interests of executives with our unitholders in the longer-term and reinforces unit ownership levels among executives.

The following table provides the annual unit award opportunity for each named executive officer. Our general objective when determining the size of the phantom unit awards is to provide our named executive officers with long-term incentive opportunities targeted between the 25th percentile and the 50th percentile of peer practices for long-term equity based awards for similarly situated executive officers. The distributable cash flow minimum, target and stretch levels were the same ones discussed above in “Short-Term Cash Awards” for determining payouts for the 2011 cash incentive awards. Accordingly, because we achieved our “stretch” distributable cash flow goal, we granted the “stretch” number of phantom unit awards, which will granted to our executive officers in the first quarter of 2012.


	2011 Phantom Unit Award Opportunity						Phantom Units Granted
	Minimum		Target		Stretch		Phantom Units Granted
F. William Grube		10,800		21,600		32,400		32,400
Jennifer G. Straumins, R. Patrick Murray, II, Timothy R. Barnhart and William A. Anderson		7,200		14,400		21,600		21,600

Phantom units granted are subject to a time-vesting requirement, whereby 25% of the units vest immediately at grant and the remainder vest ratably over three years on each December 31. These phantom units also receive DERs, which are paid in the form of cash.

For further description of this compensation program, please see “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Long-Term Incentive Plan.”

Health and Welfare Benefits

We offer a variety of health and welfare benefits to all eligible employees of our general partner. These benefits are consistent with the types of benefits provided by our peer group and provided so as to ensure that we are able to maintain a competitive position in terms of attracting and retaining executive officers and other

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employees. In addition, the health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. The named executive officers generally are eligible for the same benefit programs on the same basis as the rest of our employees. Our health and welfare programs include medical, pharmacy, dental, life insurance and accidental death and dismemberment. In addition, certain employees are eligible for long-term disability coverage. Coverage under long-term disability offers benefits specific to the named executive officers. We provide the named executive officers with a compensation allowance, which is grossed up for the payment of taxes to allow them to purchase long-term disability coverage on an after-tax basis at no net cost to them. As structured, these long-term disability benefits will pay 60% of monthly earnings, as defined by the policy, up to a maximum of $6,000 per month during a period of continuing disability up to normal retirement age, as defined by the policy. Executive officers and other key employees are also eligible to obtain executive physical examinations which are paid for by Calumet. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.

Retirement Benefits

We provide the Calumet GP, LLC Retirement Savings Plan (the “401(k) Plan”) to assist our eligible officers and employees in providing for their retirement. Named executive officers participate in the same retirement savings plan as other eligible employees subject to ERISA limits. We match 100% of each 1% of eligible compensation contribution by the participant up to 4% and 50% of each additional 1% of eligible compensation contribution up to 6%, for a maximum contribution by us of 5% of eligible compensation contributions per participant. These contributions are provided as a reward for prior contributions and future efforts toward our success and growth.

The retirement savings plan also includes a discretionary profit-sharing component. Determination of annual contributions is subjectively made by the compensation committee based on our overall profitability. The board of directors approved a discretionary profit sharing contribution to the 401(k) plan for all eligible participants equivalent to 2.5% of their eligible compensation for the 2011 fiscal year. The value our contributions to the retirement savings plan for named executive officers is included in the Summary Compensation Table. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.

Perquisites

We provide executive officers with perquisites and other personal benefits that we believe are reasonable and consistent with our overall compensation programs and philosophy. These benefits are provided in order to enable us to attract and retain these executives. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.

All named executive officers are provided with all, or certain of, the following benefits as a supplement to their other compensation:

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Use of Company Vehicles: In order to assist them in conducting our daily affairs, we provide each named executive officer with a company vehicle that may be used for personal use as well as business use. Personal use of a company vehicle is treated as taxable compensation to the named executive officer.

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Executive Physical Program: Generally on an annual basis, we pay for a complete and professional personal physical exam for each named executive officer appropriate for his or her age to improve their health and productivity.

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Club Memberships: We pay club membership fees for a certain named executive officer. Although such club memberships may be used for personal purposes in addition to business entertainment purposes, each named executive officer having such a membership is responsible for the reimbursement to us or direct payment for any incremental costs above the base membership fees associated with his or her personal use of such membership.

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•

Spousal Travel: On an occasional basis, we pay expenses related to travel of the spouses of our named executive officers in order to accompany the named executive officer to business-related events.

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Long-Term Disability Insurance: We provide compensation to allow each named executive officer to purchase long-term disability insurance on an after-tax basis at no net cost to them.

The compensation committee periodically reviews the perquisite program to determine if adjustments are appropriate.

Other Compensation Related Matters

Tax Implications of Executive Compensation

Because Calumet is not an entity taxable as a corporation, many of the tax issues associated with executive compensation that face publicly traded corporations do not directly affect us. Internal Revenue Code Section 409A (“Section 409A”) provides that amounts deferred under nonqualified deferred compensation plans are includible in a participant’s income when vested, unless certain requirements are met. If these requirements are not met, participants are also subject to an additional income tax and interest. All of our awards under our Long-Term Incentive Plan, severance arrangements and other nonqualified deferred compensation plans presently meet these requirements. As a result, employees will be taxed when the deferred compensation is actually paid to them. We will be entitled to a tax deduction at that time.

Executive Ownership of Units

While we have not adopted any security ownership requirements or policies for our executives, our executive compensation programs foster the enhancement of executives’ equity ownership through long-term, unit-based awards under Calumet’s Long-Term Incentive Plan. Further, in 2006 several executives purchased a significant number of our common units as participants in our directed unit program in conjunction with our initial public offering. For a listing of security ownership by our named executive officers, refer to Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

The board of directors has adopted the Insider Trading Policy of Calumet GP, LLC and Calumet Specialty Products Partners, L.P. (the “Insider Trading Policy”), which provides guidelines to employees, officers and directors with respect to transactions in our securities. Pursuant to Calumet’s Insider Trading Policy, all executive officers and directors must confer with our Chief Financial Officer before effecting any put or call options for our securities. Further, the Insider Trading Policy states that we strongly discourage all such transactions by officers, directors and all other employees and consultants. The Insider Trading Policy is available on our website at www.calumetspecialty.com or a copy will be provided at no cost to unitholders upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, IN 46214.

Employment Agreement with F. William Grube

We have entered into an employment agreement with our chief executive officer and vice chairman of the board, F. William Grube, to ensure he will perform his role for an extended period of time given his position and value to us. For a discussion of the major terms of Mr. Grube’s employment agreement, please refer to “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Employment Agreement with F. William Grube.”

Under his employment agreement, Mr. Grube is entitled to receive severance compensation if his employment is terminated under certain conditions, such as termination by Mr. Grube for “good reason” or by us without “cause,” each as defined in the agreement and further described in “Potential Payments Upon Termination or Change in Control — Employment Agreement with F. William Grube.”

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Our employment agreement with Mr. Grube and the related severance provisions are designed to meet the following objectives:

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Change in Control: In certain scenarios, the potential for merger or being acquired may be in the best interests of our unitholders. We provide the potential for severance compensation to Mr. Grube in the event of a change in control transaction to promote his ability to act in the best interests of our unitholders even though his employment could be terminated as a result of the transaction.

•

Termination without Cause: We believe severance compensation in such a scenario is appropriate because Mr. Grube is bound by confidentiality, nonsolicitation and noncompetition provisions covering one year after termination and because we and Mr. Grube have mutually agreed to a severance package that is in place prior to any termination event. This provides us with more flexibility to make a change in this executive position if such a change is in our and our unitholders’ best interests.

The salary multiple of the change of control benefits, use of the single trigger change of control benefits and the amount of the severance payout were determined through negotiation with Mr. Grube at the time that we entered into his employment agreement. Relative to the overall value of us, the compensation committee believes these potential benefits are reasonable.

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Summary Compensation Table

The following table sets forth certain compensation information of our named executive officers for the years ended December 31, 2011, 2010 and 2009:


	Summary Compensation Table for 2011
Name and Principal Position	Year		Salary		Unit Awards			Non-Equity Incentive Plan Compensation (4)			Change in Pension Value and Nonqualified Deferred Compensation Earnings (5)		All Other Compensation (6)		Total
F. William Grube (1)		2011	$	398,000	$	935,597	(3)	$	692,400		$	—	$	19,760	$	2,045,757
Chief Executive Officer and		2010		386,131		278,220	(3)		115,378			—		19,574		799,303
Vice Chairman of the Board		2009		371,280		113,338	(7)		113,338	(7)		—		15,133		613,089

Jennifer G. Straumins (2)		2011		288,500		506,130	(3)		577,000			—		19,381		1,391,011
President and Chief		2010		280,000		173,736	(3)		101,728			—		17,884		573,348
Operating Officer		2009		214,500		162,607	(7)		—	(7)		—		28,659		405,766

R. Patrick Murray, II		2011		283,500		545,094	(3)		510,300			—		19,363		1,358,257
Vice President and Chief		2010		275,000		129,699	(3)		114,184			—		17,240		536,123
Financial Officer		2009		242,000		75,968	(7)		74,029	(7)		—		16,000		407,997

Timothy R. Barnhart		2011		263,000		614,752	(3)		420,800			64,866		19,290		1,382,708
Vice President — Operations		2010		255,000		179,931	(3)		66,175			38,800		17,735		557,641
President		2009		209,196		114,878	(7)		49,972	(7)		19,511		18,661		412,218

William A. Anderson		2011		263,000		466,128	(3)		526,000			—		35,219		1,290,347
Vice President — Sales and		2010		255,000		76,680	(3)		132,350			—		40,960		504,990
Marketing		2009		220,000		—	(7)		112,165	(7)		—		31,412		363,577

(1)	Mr. Grube was appointed vice chairman of the board effective January 1, 2011.

(2)	Ms. Straumins was appointed president effective January 1, 2011.

(3)

The amounts include the aggregate grant date fair value of (i) awards made in connection with each executive officer’s election to defer a portion of his or her cash incentive plan award, (ii) discretionary matching phantom unit awards granted during the fiscal year, (iii) phantom units the grant date of which occurred in the current fiscal year, which that are granted to reward services provided during the fiscal year and the number of which is determined based on our level of distributable cash flow during the fiscal year, excluding the effect of estimated forfeitures and (iv) DERs granted in the form of phantom units pursuant to the Deferred Compensation Plan.

(4)	Represents amounts earned under our Cash Incentive Compensation Plan and not deferred into the Deferred Compensation Plan. Please read “Compensation Discussion and Analysis — Elements of Executive Compensation — Short-Term Cash Awards.”

(5)	Represents aggregate change in the actuarial present value of accumulated benefits under the Penreco Pension Plan. Please read “Pension Benefits.”

(6)

The following table provides the aggregate “All Other Compensation” information for each of the named executive officers, except that it excludes perquisites or other personal benefits received by Mr. Grube, Ms. Straumins, Mr. Murray and Mr. Barnhart in 2011, as such amounts for these named executive officers were each less than $10,000 in aggregate.

(7)	2009 amounts have been restated to reallocate the portion of the cash incentive award for each named executive officer that was deferred into the Deferred Compensation Plan as phantom units.


	401(k) Plan Matching Contributions		Vehicle		Spousal Travel		Club Membership		Long-Term Disability Insurance		Term Life Insurance		Total
F. William Grube	$	18,375	$	—	$	—	$	—	$	—	$	1,385	$	19,760
Jennifer G. Straumins		18,375		—		—		—		—		1,006		19,381
R. Patrick Murray, II		18,375		—		—		—		—		988		19,363
Timothy R. Barnhart		18,375		—		—		—		—		915		19,290
William A. Anderson		18,375		3,492		315		11,330		792		915		35,219

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Grants of Plan-Based Awards

The following table sets forth grants of plan-based awards to our named executive officers for the year ended December 31, 2011:

Grants of Plan-Based Awards Table for the Year Ended December 31, 2011


	Grant Date		Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1)						Estimated Future Payouts Under Equity Incentive Plan Awards (2)						All Other Unit Awards: Number of Units (3)		Grant Date Fair Value of Unit Awards
Name	Grant Date		Minimum		Target		Maximum		Minimum		Target		Maximum		All Other Unit Awards: Number of Units (3)		Grant Date Fair Value of Unit Awards
F. William Grube			$	216,375	$	432,750	$	865,500		10,800		21,600		32,400
		2-14-11														149	$	3,445
		2-28-11														1,818		38,451
		5-13-11														324		6,911
		8-12-11														364		7,218
		11-14-11														364		7,280

Jennifer G. Straumins				144,250		288,500		577,000		7,200		14,400		21,600
		2-14-11														225		5,202
		2-28-11														687		14,530
		5-13-11														307		6,548
		8-12-11														344		6,822
		11-14-11														345		6,900

R. Patrick Murray, II				141,750		283,500		567,000		7,200		14,400		21,600
		2-14-11														106		2,451
		2-28-11														450		9,518
		5-13-11														156		3,327
		8-12-11														175		3,470
		11-14-11														175		3,500

Timothy R. Barnhart				131,500		263,000		526,000		7,200		14,400		21,600
		2-14-11														160		3,699
		2-28-11														1,043		22,059
		5-13-11														268		5,716
		8-12-11														300		5,949
		11-14-11														300		6,000

William A. Anderson				131,500		263,000		526,000		7,200		14,400		21,600

(1)

Estimated future payouts under non-equity incentive plan awards represent the ranges of potential cash incentive awards granted under Calumet’s Cash Incentive Plan related to fiscal year 2011. For a description of this plan and available awards please read “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Cash Incentive Plan.”

(2)

Estimated future payouts under equity incentive plan awards represent the ranges of potential unit based awards earned under the 2011 Phantom Unit Program as part of Calumet’s Long-Term Incentive Plan. These units will be granted in the first quarter of 2012. For a description of this plan and available awards under the 2011 Phantom Unit Program please read “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Long-Term Incentive Plan.”

(3)

All other unit awards represents discretionary matching contributions made by us in fiscal year 2011, if any, in connection with the named executive officer’s deferral of a portion of his or her cash incentive award under Calumet’s Cash Incentive Compensation Plan into the Calumet Executive Deferred Compensation Plan. See “Compensation Discussion and Analysis — Elements of Executive Compensation — Executive Deferred Compensation Plan” for additional discussion of this plan. Also included are DERs credited in the form of phantom units earned on discretionary phantom unit grants, deferred cash incentive awards and discretionary matches on such deferred cash incentive awards.

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Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

Description of Cash Incentive Plan

Annual distributable cash flow goals are recommended by the compensation committee to the board of directors and are based upon our annual forecast of financial performance for the upcoming fiscal year, and such goals are reviewed and approved by the board of directors. Three increasing distributable cash flow goals are established to calculate awards under the Cash Incentive Plan: minimum, target and stretch. Under the Cash Incentive Plan, if our actual performance meets at least the minimum distributable cash flow goal for the fiscal year, executives and certain other management employees may receive incentive awards ranging from 15% to 50% of base salary, depending on the employee’s position with the general partner. If financial performance exceeds the minimum distributable cash flow goal, the cash incentive award paid as a percentage of base salary may be larger, ultimately reaching an upper range of 60% to 200% of base salary, if distributable cash flow for the fiscal year reaches the stretch goal. Cash incentive awards are prorated if actual performance falls between the defined minimum and stretch cash flow goals. If distributable cash flow falls below the minimum goal, no cash incentive awards are paid under the Cash Incentive Plan. The compensation committee can recommend to the full board of directors, however, that cash awards be given notwithstanding the fact that we failed to achieve at least the minimum distributable cash flow goal. Awards earned, if any, under this plan are generally paid in the first quarter of the following fiscal year after finalizing the calculation of our performance relative to the distributable cash flow targets. The following table summarizes the levels of awards available to participants in the Cash Incentive Plan:


	Cash Incentive Award Calculated as a Percentage of Base Salary
Incentive Level (1)	Minimum			Target			Stretch
1		50	%		100	%		200	%
2		50	%		100	%		150	%
3		20	%		40	%		80	%
4		15	%		30	%		60	%

(1)	Mr. Grube, Ms. Straumins, Mr. Murray, Mr. Barnhart and Mr. Anderson participate in the Cash Incentive Plan at Incentive Level 1.

Participants in the Cash Incentive Plan are eligible to defer all or a portion of their award, if any, under the Cash Incentive Plan into the Deferred Compensation Plan, which was adopted by the board of directors on December 18, 2008 and effective as of January 1, 2009. See “Compensation Discussion and Analysis — Elements of Executive Compensation — Executive Deferred Compensation Plan” for additional discussion of this plan.

Description of Long-Term Incentive Plan

Following is a summary of the major terms and provisions of our Long-Term Incentive Plan:

General. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of DERs. Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan, of which 306,154 have already been awarded to the non-employee directors and certain key employees, including certain of the named executive officers, of our general partner. Units withheld to satisfy our general partner’s tax withholding obligations are available for delivery pursuant to other awards.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such

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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 compensation 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 of directors terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the grant agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner is entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase. Any outstanding restricted unit or phantom unit awards fully vest upon the occurrence of certain events including, but not limited to, change of control, death, disability and normal retirement.

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

Participants do not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

2011 Phantom Unit Program. In addition to the features described above, potential awards under our 2011 Phantom Unit Program range from 1,800 to 10,800 phantom units for achievement of the minimum distributable cash flow goal, 3,600 to 21,600 phantom units for achievement of the target distributable cash flow goal and from 5,400 to 32,400 phantom units for achievement of the stretch distributable cash flow goal. Awards are not prorated for actual distributable cash flow that is achieved between the minimum, target and stretch levels. Phantom units that are granted are subject to a time-vesting requirement, whereby 25% of the units vest immediately at grant and the remainder vest ratably over three years on each December 31. At the election of the general partner, phantom unit awards may be settled in either cash or common units. These phantom units also receive DERs, which are paid in the form of cash.

The following table summarizes the levels of phantom unit awards available to participants in the 2011 program:


	Phantom Unit Award Opportunity
Incentive Level (1)	Minimum		Target		Stretch
1		10,800		21,600		32,400
2		7,200		14,400		21,600
3		5,400		10,800		16,200
4		3,600		7,200		10,800
5		1,800		3,600		5,400

(1)

Mr. Grube is the only employee and named executive officer who is eligible for a long-term unit-based award under Incentive Level 1. Ms. Straumins, Mr. Murray, Mr. Barnhart and Mr. Anderson are the only employees and named executive officers who are eligible for a long-term unit-based award under Incentive Level 2.

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

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

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

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

Description of Employment Agreement with F. William Grube

We have an employment agreement with F. William Grube, our chief executive officer and vice chairman of the board, dated as of January 31, 2006 (the “Effective Date”). The initial term of the employment agreement was five years and expired on January 31, 2011 (the “Employment Period”), with automatic extensions of an additional twelve months added to the Employment Period beginning on the third anniversary of the Effective Date, and on every anniversary of the Effective Date thereafter, unless either party notifies the other of non-extension at least ninety days prior to any such anniversary date. As neither we nor Mr. Grube provided notice of a non-renewal of the agreement within the ninety day period prior to January 31, 2012, the effective term now extends to at least January 31, 2015.

The agreement provides for an initial annual base salary of approximately $333,000, subject to annual adjustment by the compensation committee of the board of directors of our general partner, as well as the right to participate in our Long-Term Incentive Plan and other bonus plans. Mr. Grube will generally be entitled to receive a payout or distribution of at least 150% of the amount of any cash, equity or other payout or distribution that may be made to any other executive officer under the terms of these plans. Mr. Grube’s employment agreement may be terminated at any time by either party with proper notice. For the term of the employment agreement and for the one-year period following the termination of employment, Mr. Grube is prohibited from engaging in competition (as defined in the employment agreement) with us and soliciting our customers and employees.

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Salary in Proportion to Total Compensation

The following table sets forth the percentage of each named executive officer’s total compensation that we paid in the form of salary.

Salary Percentage at December 31, 2011


Name	Year		Percentage of Total Compensation
F. William Grube		2011		19	%
		2010		48	%
		2009		61	%

Jennifer G. Straumins		2011		21	%
		2010		49	%
		2009		53	%

R. Patrick Murray, II		2011		21	%
		2010		51	%
		2009		59	%

Timothy R. Barnhart		2011		19	%
		2010		46	%
		2009		51	%

William A. Anderson		2011		20	%
		2010		50	%
		2009		61	%

Outstanding Equity Awards at Fiscal Year-End

Our named executive officers had the following outstanding equity awards at December 31, 2011.

Outstanding Equity Awards at December 31, 2011


	Unit Awards
Name	Number of Units That Have Not Vested			Market Value of Units That Have Not Vested (1)
F. William Grube (2)		6,247	(7)	$	125,940
Jennifer G. Straumins (3)		6,723	(7)		135,536
R. Patrick Murray, II (4)		4,300	(7)		86,688
Timothy R. Barnhart (5)		5,952	(7)		119,992
William A. Anderson (6)		1,800	(7)		36,288

(1)	Market value of phantom units reported in these columns is calculated by multiplying the closing market price ($20.16) of our common units at December 31, 2011 (the last trading day of the fiscal year) by the number of units.

(2)	2,700 phantom units vest ratably over two years on each December 31; 1,599 phantom units vest ratably over three years on each July 1 and 1,948 phantom units vest ratably over four years on each July 1.

(3)	1,800 phantom units vest ratably over two years on each December 31; 2,645 phantom units vest ratably over two years on each January 22; 1,542 phantom units vest ratably over three years on each July 1 and 736 phantom units vest ratably over four years on each July 1.

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(4)	1,800 phantom units vest ratably over two years on each December 31; 1,321 phantom units vest ratably over two years on each January 22; 697 phantom units vest ratably over three years on each July 1 and 482 phantom units vest ratably over four years on each July 1.

(5)	1,800 phantom units vest ratably over two years on each December 31; 1,979 phantom units vest ratably over two years on each January 22; 1,055 phantom units vest ratably over three years on each July 1 and 1,118 phantom units vest ratably over four years on each July 1.

(6)	1,800 phantom units vest ratably over two years on each December 31.

(7)	Does not include the following phantom unit awards, which will be granted during the first quarter of 2012 and which relate to services provided during fiscal year 2011: Mr. Grube (32,400), Ms. Straumins (21,600), Mr. Murray (21,600), Mr. Barnhart (21,600) and Mr. Anderson (21,600).

Options Exercises and Stock Vested

Our named executive officers exercised no options and had a total of 29,292 phantom units related to the Deferred Compensation Plan and the Long Term Incentive Plan vest during the year ended December 31, 2011. The vested units related to the Deferred Compensation Plan will remain in the Deferred Compensation Plan until the earlier of the date specified by each participant and the participant’s termination of employment.

Unit Awards Vested During Year Ended December 31, 2011


	Unit Awards
Name	Number of Units Vested		Value Realized on Vesting (1)
F. William Grube		9,603	$	201,453
Jennifer G. Straumins		6,491		139,844
R. Patrick Murray, II		4,441		94,718
Timothy R. Barnhart		6,957		148,733
William A. Anderson		1,800		37,134

(1)	Market value of phantom units reported in this column is calculated by multiplying the closing market price of our common units on the vesting date by the number of units.

Pension Benefits


Executive	Plan Name	Number of Years of Credited Service (1)		Present Value of Accumulated Benefits (2)		Payments During 2011
Timothy R. Barnhart	Penreco Pension Plan		26.3205	$	304,477	$	—

(1)

Mr. Barnhart’s “Number of Years Credited Service” is computed using the same pension plan measurement dates used for our financial statement reporting purposes with respect to our audited consolidated financial statements for the 2011 fiscal year; a further description can be found in Note 13 to such statements included in this Annual Report. This column contemplates Mr. Barnhart’s previous employment with Penreco, as well as our decision to freeze account benefit accumulation for all salaried participants, as of January 31, 2009.

(2)

In addition to the assumptions noted within Note 13 to our audited consolidated financial statements for the 2011 fiscal year, the assumptions used to calculate the amounts shown in the “Present Value of Accumulated Benefits” column above are as follows: (a) payments under the Pension Plan were assumed to begin for Mr. Barnhart at age 65; (b) the December 31, 2011 Financial Accounting Standards (“FAS”) disclosure weighted average discount rate of 4.59% was used; and (c) payments assumed to be made following age 65 were also discounted using the FAS disclosure mortality assumption (no mortality was assumed prior to age 65).

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We acquired Penreco from ConocoPhillips and M.E. Zukerman Specialty Oil Corporation on January 3, 2008. In connection with this acquisition, we also took over the Penreco Pension Plan, a noncontributory defined benefit plan, in which both salaried and union employees were entitled to participate (the “Pension Plan”). However, while we agreed to maintain and continue administration of the Pension Plan, we froze the plan as in effect for salaried employees effective January 31, 2009. “Freezing” this portion of the Pension Plan meant that no more salaried employees were permitted to join the plan following January 31, 2009, and the accounts of current participants were not permitted to accrue further benefits following January 31, 2009.

Mr. Timothy R. Barnhart, as a former salaried Penreco employee, participates in the Pension Plan. Salaried employees such as Mr. Barnhart were eligible to participate in the plan following one year of completed service. The Pension Plan is intended to provide a “normal” pension benefit to participants upon their “normal” retirement age of 65. A normal retirement benefit is equal to the greater of: (1) the sum of (a) one and one-sixth percent of the participant’s “final average compensation” multiplied by his years of service prior to 1974, plus (b) one and one-tenth percent of a participant’s “final average compensation” multiplied by his years of service after 1973, plus (c) five-tenths percent of the amount of the participant’s monthly “final average compensation” in excess of the participant’s final “covered compensation” in the year of retirement, multiplied by his years of service after 1973; or (2) $40 multiplied by a participant’s years of service; or (3) the accrued pension amount as determined under the terms of the Pension Plan as in effect on June 30, 2003. Once the greatest of these three options is determined, a normal pension will then be calculated by subtracting the pension benefit determined under two of the various superseded and prior plans, or the pension benefit as calculated under the union employee portion of the Pension Plan if the participant was previously a participant in that portion of the Pension Plan.

The “average final compensation” is the highest monthly “considered compensation” of a participant during the 60 consecutive months immediately prior to January 31, 2009. A participant’s “considered compensation” under the Pension Plan consists of all of the compensation actually provided to a participant in consideration of his performance of services to his employer that is considered taxable wages, excluding any compensation received from the exercise of stock options, from distributions of any other employee benefit plan accounts, or amounts paid by his employer for life insurance policies; this amount will be limited to the amount as noted in Code section 401(a)(17)(B) for an applicable year (which was $245,000 for the 2011 year). However, due to our freezing of benefits in 2009, no amount of compensation earned after January 31, 2009 shall be deemed “considered compensation” for purposes of the Pension Plan. “Covered compensation” under the Pension Plan means the average taxable wage base during the 35 years immediately prior to the date the participant reaches the social security retirement age.

Other than a “normal” retirement, there are various events that would require or allow the distribution of Pension Plan accounts. Participants may receive an “early” retirement benefit upon reaching the age of 55 but prior to reaching age 65. In the event that a participant suffers a “disability” prior to normal retirement, the participant will be eligible to receive a disability pension benefit upon reaching the age of 65. If a participant works past the age of 65, his Pension Plan benefit will not be calculated differently than if calculated at age 65. If a participant separates from service prior to retirement, the retirement benefit will be calculated based upon years of service completed at the separation date, although payments will not begin until the participant reaches a normal or early retirement age. As of December 31, 2011, Mr. Barnhart was not yet eligible to receive an “early” or a “normal” retirement benefit pursuant to the Pension Plan. Any participant in the Pension Plan as of January 31, 2009 was also considered fully vested in his or her account, thus Mr. Barnhart is 100% vested in all portions of his Pension Plan account.

A normal form of payment will be distributed in a monthly annuity payment, but a participant may also elect a different monthly benefit amount prior to normal retirement, which would allow the participant to receive a reduced pension amount while continuing to provide for a surviving spouse upon his death, known as a joint and survivor annuity benefit. This will typically provide a 50% benefit as a retirement benefit and 50% will be deferred until it is needed for surviving spouse support, although the participant and his spouse may make written elections to alter these percentages during the participant’s service.

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Nonqualified Deferred Compensation

The Deferred Compensation Plan became effective as of January 1, 2009. The Deferred Compensation Plan is an unfunded arrangement intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of the Employee Retirement Income Security Act of 1974, as amended, and to comply with Section 409A of the Code. Our obligations under the Deferred Compensation Plan will be general unsecured obligations to pay deferred compensation in the future to eligible participants in accordance with the terms of the Deferred Compensation Plan from our general assets. The compensation committee of our general partner’s board of directors acts as the plan administrator.


	Nonqualified Deferred Compensation Table for 2011
Name	Executive Contributions in 2011 (1)		Company Contributions in 2011 (2)		Aggregate Earnings in 2011 (3)		Aggregate Withdrawals/ Distributions		Aggregate Balance at end of 2011 (4)
F. William Grube	$	115,373	$	38,451	$	24,854	$	—	$	329,152
Jennifer G. Straumins		43,590		14,530		25,472		—		332,015
R. Patrick Murray, II		28,553		9,518		12,748		—		167,167
Timothy R. Barnhart		66,178		22,059		21,365		—		283,913
William A. Anderson		—		—		—		—		—

(1)

Executive contributions in 2011 represent phantom unit grants on February 28, 2011 to certain of our named executive officers based on their individual elections to defer all or a portion of their cash incentive award under Calumet’s Cash Incentive Compensation Plan related to the 2010 fiscal year into the Deferred Compensation Plan. These amounts, which represent the fair value of the phantom units on the date of grant were included as compensation in 2010 under “Unit Awards” in the Summary Compensation Table.

(2)

Our contributions in 2011 represent discretionary matching contributions made in the form of phantom unit grants on February 28, 2011 to our named executive officers based on their individual elections to defer all or a portion of their cash award under Calumet’s Cash Incentive Compensation Plan related to the 2010 fiscal year into the Deferred Compensation Plan. These amounts, which represent the fair value of the phantom units on the date of grant are included as compensation in 2011 under “Unit Awards” in the Summary Compensation Table.

(3)

Aggregate earnings in 2011 represent additional phantom units earned through DERs in the applicable named executive officer’s Deferred Compensation Plan account on phantom units granted under the aforementioned executive contribution and discretionary matching contribution on February 28, 2011, as well as phantom units granted in fiscal year 2010 and 2009. These amounts, which represent the fair value of the phantom units earned on the corresponding dates of our distributions to our unitholders in fiscal year 2011 are included as compensation in 2011 under “Unit Awards” in the Summary Compensation Table.

(4)

While the aggregate balance of each participant’s Deferred Compensation Plan account at the end of the fiscal year is comprised of the phantom units related to the executive and discretionary matching contributions as well as the phantom units attributable to aggregate earnings accumulated during the 2011 year, the dollar amount of each participant’s account as of December 31, 2011 was determined by multiplying all phantom units deemed to be included in the participant’s account by the closing price of our common units on December 31, 2011, which was $20.16. The phantom units associated with each executive’s account as of December 31, 2011 were as follows: Mr. Grube, 16,327; Ms. Straumins, 16,469; Mr. Murray, 8,292; Mr. Barnhart, 14,083; and Mr. Anderson, 0. Subject to the executive’s continued employment with us, these phantom units will become vested over a four year period (except for phantom units associated with executive contributions, which are fully vested at the time of cash incentive deferral), but such vesting applies to the number of phantom units credited to the participant’s account, and not the value of the account at any given time. The value of the executives’ accounts will fluctuate due to the fact that the value of their phantom units will track the value of our common units. Also, please keep in mind that the executives’ accounts are not currently fully vested; subject to the forfeiture provisions described

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below, these amounts do not reflect the payout amount that an executive would receive if he or she voluntarily left our service prior to vesting. The amounts in this column also include amounts that were previously reported as compensation in the Summary Compensation Table during previous years as follows: (a) For 2009, Mr. Grube, $113,338; Ms. Straumins, $109,362; Mr. Murray, $49,354; and Mr. Barnhart, $74,939 (b) For 2010, Mr. Grube, $115,373; Ms. Straumins, $43,590; Mr. Murray, $28,553 and Mr. Barnhart, $66,178.

The named executive officers, as well as other officers and key employees, participate in the Deferred Compensation Plan by making an annual irrevocable election to defer all or a portion of their annual cash incentive award for the year. The deferred amounts will be credited to the participants’ accounts in the form of phantom units, and will receive DERs to be credited in the form of additional phantom units to the participants’ account. We have the discretion to make matching contributions of phantom units or purely discretionary contributions of phantom units, in amounts and at times as the compensation committee determines appropriate. For the 2011 year, the compensation committee authorized matching contributions of deferred amounts related to the 2010 fiscal year. For each equivalent three phantom units credited to a participant’s account at the time the 2010 cash incentive award was paid during the first quarter of 2011, we matched with one additional phantom unit credited to the participant’s account. Participants will at all times be 100% vested in amounts they have deferred; however, amounts we have contributed may be subject to a vesting schedule, as determined appropriate by the compensation committee. The 2011 matching contributions related to fiscal year 2010 will vest ratably over four years on each July 1 beginning July 1, 2012. The participants’ accounts are adjusted at least quarterly to determine the fair market value of our phantom units, as well as any DERs that may have been credited in that time period. Distributions from the Deferred Compensation Plan are payable on the earlier of the date specified by each participant and the participant’s termination of employment. Death, disability, normal retirement or our change of control (such terms of which are defined as within our Long-Term Incentive Plan) require automatic distribution of the Deferred Compensation Plan benefits, and will also accelerate at that time the vesting of any portion of a participant’s account that has not already become vested. Benefits will be distributed to participants in the form of our common units, cash or a combination of common units and cash at the election of the compensation committee. In the event that accounts are paid in common units, such units will be distributed pursuant to our Long-Term Incentive Plan. Unvested portions of a participant’s account will be forfeited in the event that a distribution was due to a participant’s voluntary resignation or a termination for cause. To ensure compliance with Section 409A of the Code, distributions to participants that are considered “key employees” (as defined in Code Section 409A of the Code) may be delayed for a period of six months following such key employees’ termination of employment with us.

Potential Payments Upon Termination or Change in Control

Employment Agreement with F. William Grube

Following is a description of our obligations, including potential payments to Mr. Grube, upon termination of Mr. Grube’s employment under various termination scenarios. We have assumed for purposes of quantifying Mr. Grube’s potential payments that his termination occurred on December 31, 2011, and earned salary and bonus amounts are paid current. The amounts are our best estimates as to the potential payout he would have received upon December 31, 2011, but the amounts Mr. Grube would receive upon an actual termination of employment could only be calculated with certainty upon a true termination of employment.

In consideration for any potential severance Mr. Grube may receive pursuant to his employment agreement, he will not compete or solicit our employees for a period of one year following a termination of employment. Prior to receipt of any potential severance payments or the acceleration of any outstanding equity awards, Mr. Grube will be required to sign, and not revoke, a full waiver and release in our favor. Following such release and waiver’s period of revocability, Mr. Grube will be eligible to receive payments as soon as administratively possible, though if Code Section 409A would subject Mr. Grube to additional taxes upon receipt of the payments, we will delay the payment of these amounts for a period of six months and provide for interest to accrue on such delayed amounts at the maximum nonusurious rate from the date of the originally scheduled payment date. Mr. Grube is also eligible to receive an additional sum from us in the event that any termination payments we

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provide to him are considered “parachute” payments pursuant to Section 280G of the Internal Revenue Code of 1986, as amended (the “Code”); a parachute payment could occur in connection with a change in control or a termination of employment that was also in connection with a change in control, but such a payment would not occur in the event of a termination of Mr. Grube’s employment that is not in connection with a change in control. This additional payment, if necessary, would equal the amount necessary to place Mr. Grube in the same after-tax position he would have been in absent the additional excise taxes imposed by Section 280G of the Code.

Termination of Employment Due to Death or Disability

Upon the termination of Mr. Grube’s employment due to his disability or death:

a. We will pay him or his beneficiary a lump sum equal to his earned annual base salary through the date of termination to the extent not theretofore paid;

b. We will pay him or his beneficiary a lump sum equal to any compensation incentive awards payable in cash with respect to fiscal years ended prior to the year that includes the date of termination to the extent not theretofore paid;

c. We will pay him or his beneficiary a lump sum cash payment with respect to his participation in any plans, programs, contracts or other arrangements that may result in a cash payment for the fiscal year that includes the date of termination on a prorated basis considering the date of termination relative to the full fiscal year; and

d. Any equity awards held by Mr. Grube shall immediately vest and become fully exercisable or payable, as the case may be.

For this purpose, Mr. Grube will be deemed to have a “disability” if he is unable to perform his duties under the employment agreement by reason of mental or physical incapacity for 90 consecutive calendar days during the Employment Period, provided that we will not have the right to terminate his employment for disability if in the written opinion of a qualified physician reasonably acceptable to us is delivered to the us within 30 days of our delivery to Mr. Grube of a notice of termination (as defined in the employment agreement) that it is reasonably likely that Mr. Grube will be able to resume his duties on a regular basis within 90 days of the notice of termination and Mr. Grube does resume such duties within such time.

If Mr. Grube’s employment were to have been terminated on December 31, 2011, due to death or disability (as defined in the employment agreement), we estimate that the value of the payments and benefits described in clauses (a), (b), (c) and (d) above he would have been eligible to receive is as follows: (a) $0; (b) $0; (c) $1,252,344; and (d) $734,832, with an aggregate value of $1,987,176.

Termination of Employment by Mr. Grube for Good Reason or by Us Without Cause

Upon the termination of Mr. Grube’s employment by him for good reason or by us without cause:

a. We will pay him a lump sum cash payment in an amount equal to three times his annual base salary then in effect;

b. We will pay him a lump sum equal to his earned annual base salary through the date of termination to the extent not theretofore paid;

c. We will pay him a lump sum equal to any compensation incentive awards payable in cash with respect to fiscal years ended prior to the year that includes the date of termination to the extent not theretofore paid;

d. We will pay him a lump sum cash payment with respect to his participation in any plans, programs, contracts or other arrangements that may result in a cash payment for the fiscal year that includes the date of termination on a prorated basis considering the date of termination relative to the full fiscal year;

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e. All equity-based awards (including phantom unit awards) held by Mr. Grube shall immediately vest in full (at their target levels, if applicable) and become fully exercisable or payable, as the case may be.

“Good reason” as defined in the employment agreement includes: (i) any material breach by us of the employment agreement; (ii) any requirement by us that Mr. Grube relocate outside of the metropolitan Indianapolis, Indiana area; (iii) failure of any successor to us to assume the employment agreement not later than the date as of which it acquires substantially all of the equity, assets or business of us; (iv) any material reduction in Mr. Grube’s title, authority, responsibilities, or duties (including a change that causes him to cease being a member of the board of directors or reporting directly and solely to the board of directors); or (v) the assignment of Mr. Grube any duties materially inconsistent with his duties as our chief executive officer.

“Cause” as defined in the employment agreement includes: (i) Mr. Grube’s willful and continuing failure (excluding as a result of his mental or physical incapacity) to perform his duties and responsibilities with us; (ii) Mr. Grube’s having committed any act of material dishonesty against us or any of its affiliates as defined in the employment agreement; (iii) Mr. Grube’s willful and continuing breach of the employment agreement; (iv) Mr. Grube’s having been convicted of, or having entered a plea of nolo contendre to any felony; or (v) Mr. Grube’s having been the subject of any final and non-appealable order, judicial or administrative, obtained or issued by the Securities and Exchange Commission, for any securities violation involving fraud.

If Mr. Grube’s employment were to have been terminated by him for good reason or by us without cause on December 31, 2011, we estimate that the value of the payments and benefits described in clauses (a), (b), (c), (d) and (e) above he would have been eligible to receive is as follows: (a) $1,194,000 (or three times $398,000); (b) $0; (c) $0; (d) $1,252,344; and (e) $734,832, with an aggregate value of $3,181,176.

Termination of Employment by Mr. Grube Without Good Reason or by Us for Cause

Upon the termination of employment by Mr. Grube without good reason or by us with cause:

a. We will pay him a lump sum equal to his earned annual base salary through the date of termination to the extent not theretofore paid;

b. We will pay him a lump sum equal to any compensation incentive awards payable in cash with respect to fiscal years ended prior to the year that includes the date of termination to the extent not theretofore paid; and

c. We will pay him a lump sum cash payment with respect to his participation in any plans, programs, contracts or other arrangements that may result in a cash payment for the fiscal year that includes the date of termination on a prorated basis considering the date of termination relative to the full fiscal year.

If Mr. Grube’s employment were to have terminated by him without good reason or by us for cause on December 31, 2011, we estimate that the value of the payments and benefits described in clauses (a), (b) and (c) above he would have been eligible to receive is as follows: (a) $0; (b) $0; (c) $1,252,344, with an aggregate value of $1,252,344.

Termination or Change of Control Pursuant to Long-Term Incentive Plan

Unless specifically provided otherwise in the named executive officer’s individual award agreement, upon a Change of Control all outstanding awards granted pursuant to the Long-Term Incentive Plan shall automatically vest and be payable at their maximum target level or become exercisable in full, as the case may be, or any restricted periods connected to the award shall terminate and all performance criteria, if any, shall be deemed to have been achieved at the maximum level. We provide these “single-trigger” change of control benefits because we believe such benefits are important retention tools for us, as providing for accelerated vesting of awards under the Long-Term Incentive Plan upon a Change of Control enables employees, including the named executive

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officers, to realize value from these awards in the event that we go through a change of control transaction. In addition, we believe that it is important to provide the named executive officers with a sense of stability, both in the middle of transactions that may create uncertainty regarding their future employment and post-termination as they seek future employment. Whether or not a change of control results in a termination of its officers’ employment with us or a successor entity, we want to provide its officers with certain guarantees regarding the importance of equity incentive compensation awards they were granted prior to that change of control. Further, we believe that change of control protection allows management to focus their attention and energy on the business transaction at hand without any distractions regarding the effects of a change of control. Also, we believe that such protection maximizes unitholder value by encouraging the named executive officers to review objectively any proposed transaction in determining whether such proposed transaction is in the best interest of our unitholders, whether or not the executive will continue to be employed.

For purposes of the Long-Term Incentive Plan, a Change of Control shall be deemed to have occurred upon one or more of the following events: (i) any person or group, other than a person or group who is our affiliate, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of fifty percent (50%) or more of the voting power of our outstanding equity interests; (ii) a person or group, other than our general partner or one of our general partner’s affiliates, becomes our general partner; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of our assets or the assets of our general partner in one or more transactions to any person or group other than an a person or group who is our affiliate. However, in the event that an award is subject to Code Section 409A, a Change of Control shall have the same meaning as such term in the regulations or other guidance issued with respect to Code Section 409A for that particular award.

Under the Long-Term Incentive Plan, the awards will also accelerate upon a termination due to death, disability or a normal retirement upon or after reaching the age of 66. The Board has the final authority to determine if a disability is permanent or of a long term duration resulting in termination from us. A “disability” per the terms of the Long-Term Incentive Plan grant means (i) a participant’s inability to engage in any substantial gainful activity by reason of a physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of 12 months, or (ii) the participant is, by reason of a physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of 12 months, receiving income replacement benefits for a period of not less than 3 months under one of our accident and health plans. We have determined that providing acceleration of Long-Term Incentive Plan awards upon a death or disability is appropriate because the termination of a participant’s employment with us due to such an occurrence is often an unexpected event, and it is our belief that providing an immediate value to the participant or his or her family, as appropriate, in such a situation is a competitive retention tool. We also believe that providing for acceleration upon a normal retirement is appropriate due to the fact that the definition of a normal retirement requires an executive to remain employed with us until late in his or her career, and the acceleration of their equity awards upon such an event provides the executives with a reassurance that they will receive value for their awards at the end of their career. We have determined that it is in the unitholders’ best interest to provide such retention tools with respect to our equity compensation awards due to the fact that we strive to retain a high level of executive talent while competing in a very aggressive industry.

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The following table discloses the amount each executive could receive as of December 31, 2011 under the Long-Term Incentive Plan upon a termination of employment or a Change of Control:


	Potential Payments from the Long-Term Incentive Plan (1)
Name	Change of Control		Termination due to Death, Disability or Normal Retirement
F. William Grube	$	734,832	$	734,832
Jennifer G. Straumins		489,888		489,888
R. Patrick Murray, II		489,888		489,888
Timothy R. Barnhart		489,888		489,888
William A. Anderson		489,888		489,888

(1)

All amounts assume that the executives received full vesting of equity awards due to the applicable termination or Change of Control event, and the value of all phantom units pursuant to equity awards under the Long-Term Incentive Plan were valued at our December 31, 2011 closing common unit price of $20.16. As required pursuant to Section 409A of the Code, in the event that any of the executives are also “key employees” as defined in Section 409A of the Code at the time a settlement would become due, we would delay the settlement of such an executive’s equity awards until the first day of the seventh month following the applicable event requiring settlement of equity awards under the Long-Term Incentive Plan.

Termination or Change of Control with respect to the Deferred Compensation Plan Participants

The Deferred Compensation Plan provides the executives with the opportunity to defer a portion of their eligible compensation each year. At the time of their deferral election, the executive may choose a day in the future in which a payout from the plan will occur with regard to their vested account balance, or, if earlier, the payout of vested accounts will occur upon the executive’s termination from service for any reason. Despite the executive’s payout election date, however, the Deferred Compensation Plan accounts will also receive accelerated vesting and a pay out in the event of the executive’s termination from service due to death, disability or normal retirement, or upon the occurrence of a Change of Control.

A “disability” under the Deferred Compensation Plan means (i) a participant’s inability to engage in any substantial gainful activity by reason of a physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of 12 months, or (ii) the participant is, by reason of a physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of 12 months, receiving income replacement benefits for a period of not less than 3 months under one of our accident and health plans. A “normal retirement” means a participant’s termination of employment on or after the date that he or she reaches the age of 66.

There are various connections between the Deferred Compensation Plan and the Long-Term Incentive Plan. A “Change of Control” for the Deferred Compensation Plan shall have the same definition as that term within our Long-Term Incentive Plan noted above. Our compensation committee also has the discretion to pay Deferred Compensation Plan accounts in either cash or our common units. In the event that a Deferred Compensation Plan account is settled in our common units, those units will be issued pursuant to our Long-Term Incentive Plan. For purposes of this disclosure we have assumed that the compensation committee would determine to settle the Deferred Compensation Plan accounts solely in our common units, meaning that the amounts below would reflect the fair market value of common units that could be issued pursuant to Long-Term Incentive Plan in connection with a termination of employment or a Change of Control. Please note that the compensation committee’s decision regarding such a settlement could not be determined with any certainty until such an event actually occurred.

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The following table discloses the amount each executive could receive as of December 31, 2011 under the Deferred Compensation Plan upon a termination of employment or a Change of Control:


	Potential Payments from the Deferred Compensation Plan (1)
Name	Change of Control		Termination due to Death, Disability or Normal Retirement
F. William Grube	$	329,152	$	329,152
Jennifer G. Straumins		332,015		332,015
R. Patrick Murray, II		167,167		167,167
Timothy R. Barnhart		283,913		283,913
William A. Anderson		—		—

(1)

All amounts assume that the executives received full vesting of the accounts due to the applicable termination or Change of Control event, and the value of all phantom units held in the Deferred Compensation Plan accounts was valued at our December 31, 2011 closing common unit price of $20.16. As required pursuant to Section 409A of the Code, in the event that any of the executives are also “key employees” as defined in Section 409A of the Code at the time a settlement would become due, we would delay the settlement of such an executive’s account until the first day of the seventh month following the applicable event requiring settlement of the Deferred Plan account.

Compensation of Directors

Officers or employees of our general partner who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner receives an annual fee as well as compensation for attending meetings of the board of directors and committee meetings. Non-employee director compensation consists of the following:

•

an annual fee of $50,000, payable in quarterly installments;

•

an annual award of restricted or phantom units with a market value of approximately $40,000;

•

an audit committee chair annual fee of $8,000, payable in quarterly installments;

•

a non-chair audit committee member annual fee of $4,000, payable in quarterly installments;

•

all other committee chair annual fee of $5,000; and

•

all other committee member annual fee of $2,500, payable in quarterly installments.

In addition, we reimburse each non-employee director for his out-of-pocket expenses incurred in connection with attending meetings of the board of directors or committees. Under certain circumstances, we will also indemnify each director for his actions associated with being a director to the fullest extent permitted under Delaware law.

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The following table sets forth certain compensation information of our non-employee directors for the year ended December 31, 2011:


	Director Compensation Table for 2011
Name	Fees Earned or Paid in Cash		Unit Awards (1)		Total
Fred M. Fehsenfeld, Jr.	$	55,000	$	76,541	$	131,541
James S. Carter		59,000		81,148		140,148
William S. Fehsenfeld		50,000		40,060		90,060
Robert E. Funk		56,500		68,098		124,598
George C. Morris III		58,000		57,254		115,254
Nicholas J. Rutigliano		50,000		75,270		125,270

(1)

The amounts in this column are calculated based on the aggregate grant date fair value of (i) annual phantom unit awards to all non-employee directors, (ii) matching phantom unit awards granted to those non-employee directors who deferred all of the fees they earned in 2011 pursuant to the Deferred Compensation Plan and (iii) DERs credited in the form of phantom units earned on deferred fees and discretionary matches on such deferred fees. Please see “Compensation Discussion and Analysis — Elements of Executive Compensation — Executive Deferred Compensation Plan” for a discussion of how we calculated these values.

Annual Phantom Unit Awards

On November 2, 2011, each non-employee director was granted 2,148 phantom units with a grant date fair value of $40,060. With respect to this award, 25% of the phantom units vested on December 31, 2011, entitling the director to receive an equal number of common units, with an additional 25% vesting on December 31 of each of the three successive years. As of December 31, 2011, each non-employee director had 3,152 unvested phantom units outstanding with a market value of $63,544 related to annual equity awards from 2009, 2010 and 2011. Related to these annual equity awards made to non-employee directors, an aggregate of 18,912 unvested phantom units with a market value of $381,266 were outstanding as of December 31, 2011.

Deferred Compensation Plan

Messrs. F. Fehsenfeld, Jr., Carter, Funk, Morris and Rutigliano each elected to defer all of their fees earned related to fiscal year 2011 into the Deferred Compensation Plan. These deferred amounts are credited to the participant’s account in the form of phantom units, and will receive DERs to be credited to the participant’s account in the form of additional phantom units on the corresponding dates of our distributions to our unitholders. The compensation committee recommended, and the board of directors approved, a matching contribution of one phantom unit for each equivalent three phantom units deferred for those fees earned related to fiscal year 2011. Phantom units credited to a participant’s account pursuant to matching contributions also carry DERs to be credited to the participant’s account in the form of additional phantom units. The matching contribution for each participant for fiscal year 2011 was made on a quarterly basis as of the date of our quarterly board meetings related to fiscal year 2011.

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The following table summarizes grants of phantom units made to those directors participating in the Deferred Compensation Plan in fiscal year 2011. The fair value of such grants is calculated by multiplying the closing market price of our common units on the grant date by the number of units. Phantom units granted in 2011 under the Deferred Compensation Plan will vest in 25% increments on July 1 of each year beginning on July 1, 2012.


Name	Grant Date		All Other Unit Awards: Number of Units		Grant Date Fair Value of Unit Awards
Fred M. Fehsenfeld, Jr.		2-14-11		151	$	3,491
		2-15-11		199		4,589
		5-3-11		219		4,592
		5-13-11		202		4,309
		8-2-11		205		4,586
		8-12-11		247		4,898
		11-1-11		243		4,576
		11-14-11		272		5,440

				1,738		36,481
James S. Carter		2-14-11		181		4,185
		2-15-11		213		4,912
		5-3-11		234		4,906
		5-13-11		239		5,098
		8-2-11		220		4,921
		8-12-11		291		5,771
		11-1-11		261		4,915
		11-14-11		319		6,380

				1,958		41,088
Robert E. Funk		2-14-11		118		2,728
		5-3-11		225		4,718
		5-13-11		149		3,178
		8-2-11		210		4,698
		8-12-11		189		3,748
		11-1-11		250		4,708
		11-14-11		213		4,260

				1,354		28,038
George C. Morris III		5-3-11		230		4,823
		5-13-11		20		427
		8-2-11		216		4,832
		8-12-11		44		873
		11-1-11		257		4,839
		11-14-11		70		1,400

				837		17,194
Nicholas J. Rutigliano		2-14-11		157		3,630
		2-15-11		181		4,174
		5-3-11		199		4,173
		5-13-11		206		4,394
		8-2-11		186		4,161
		8-12-11		253		5,017
		11-1-11		221		4,161
		11-14-11		275		5,500

				1,678		35,210

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Compensation Committee Interlocks and Insider Participation

The members of our compensation committee are F. William Grube and Fred M. Fehsenfeld, Jr. Mr. Grube is our chief executive officer and vice chairman of the board of our general partner. Mr. F. Fehsenfeld, Jr. is the chairman of the board of our general partner. Please read Item 13 “Certain Relationships and Related Transactions and Director Independence — Specialty Product Sales and Related Purchases and — Crude Oil Purchases” for descriptions of our transactions in fiscal year 2011 with certain entities related to Messrs. Grube and F. Fehsenfeld, Jr. No executive officer of our general partner served as a member of the compensation committee of another entity that had an executive officer serving as a member of our board of directors or compensation committee.

Risk Considerations in our Overall Compensation Program

Our compensation policies and practices are designed to provide rewards for high levels of financial performance. Currently, our incentive compensation programs are based on performance, at the Company level, relative to goals we set for distributable cash flow. In our assessment of risk related to such use of a single financial performance metric, we considered the relative difficulty for any employee to engage in an undue amount of risk-taking activity with a result that would be reasonably likely to have a material adverse effect on us due to the breadth and scope of activities, both operational and financial, across that organization that are captured in the calculation of distributable cash flow. Also, we considered the current approval controls that exist to mitigate against excessive risk-taking that might impact distributable cash flow and, in turn, our compensation programs. For example, we have specific approval policies related to the entry into derivative instruments, material commercial agreements and significant capital expenditures. Also, our full board of directors, as well as through the actions of its various committees, regularly assesses our key risk areas to monitor the impacts of such risks on our financial performance. Further, we considered the design of our incentive compensation programs, noting that the inclusion of both shorter-term cash incentive awards and longer-term unit awards further align the interest our employees and its unitholders. As a result of these considerations, we have concluded that the risks arising from our compensation policies and practices for our employees are not reasonably likely to have a material adverse effect on us.

Report of the Compensation Committee for the Year Ended December 31, 2011

The compensation committee of our general partner has reviewed and discussed our Compensation Discussion and Analysis with management. Based upon such review, the related discussion with management and such other matters deemed relevant and appropriate by the compensation committee, the compensation committee has recommended to the board of directors that our Compensation Discussion and Analysis be included in the Company’s Annual Report on Form 10-K.

Members of the Compensation Committee:

Fred M. Fehsenfeld, Jr., Chairman

F. William Grube

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth the beneficial ownership of our units as of February 27, 2012 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.

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

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The address for the beneficial owners listed below, other than The Heritage Group and Calumet, Incorporated, is 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, Indiana 46214.


Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Total Units Beneficially Owned
The Heritage Group (1)		11,867,533		23.03	%
Janet K. Grube (2)		3,081,142		5.98	%
Calumet, Incorporated (3)		1,934,287		3.75	%
F. William Grube (4)		855,354		1.66	%
Fred M. Fehsenfeld, Jr. (1)(2)(5)(6)		671,260		1.30	%
Timothy R. Barnhart		13,250		*
Jennifer G. Straumins (7)		46,122		*
R. Patrick Murray, II		14,911		*
Robert M. Mills		5,087		*
William A. Anderson (8)		17,598		*
Jeffrey D. Smith		9,142		*
James S. Carter		40,217		*
William S. Fehsenfeld (1)(6)(9)		73,598		*
Robert E. Funk		35,592		*
Nicholas J. Rutigliano (1)(6)(10)		56,192		*
George C. Morris III (11)		78,149		*
All directors and executive officers as a group (12 persons)		1,916,472		3.72	%

*	= 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 Amy M. Schumacher, 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 units owned by The Heritage Group, and none of these units are shown as being beneficially owned by such directors in the table above. The address for The Heritage Group is 5400 W. 86th St., Indianapolis, Indiana 46268. Of these common units, 367,197 are owned by The Heritage Group Investment Company, LLC (“Investment LLC”). Investment LLC is under common ownership with The Heritage Group. The Heritage Group, although not the owner of the common units, serves as the Manager of Investment LLC, and in that capacity has sole voting and investment power over the common units. The Heritage Group disclaims beneficial ownership of the common units owned by Investment LLC except to the extent of its pecuniary interest therein.

(2)	Janet K. Grube’s holdings include common 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

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children are the beneficiaries of such trusts. Janet K. Grube’s holdings also include common 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. The address of Janet K. Grube is 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, Indiana 46214.

(3)

The common units of Calumet, Incorporated are indirectly owned 45.8% by The Heritage Group and 5.1% by Fred M. Fehsenfeld, Jr. personally. Fred M. Fehsenfeld, Jr. is also a director of Calumet, Incorporated. Accordingly, 885,294 of the common units owned by Calumet, Incorporated are also shown as being beneficially owned by The Heritage Group in the table above, and 97,971 of the common units owned by Calumet, Incorporated are also shown as being beneficially owned by Fred M. Fehsenfeld, Jr. in the table above. The Heritage Group and Fred M. Fehsenfeld, Jr. disclaims beneficial ownership of all of the common units owned by Calumet, Incorporated in excess of their respective pecuniary interests in such units. The address of Calumet, Incorporated is 5400 W. 86th St., Indianapolis, Indiana 46268.

(4)

Includes 775,000 common units that are owned by AEG Associates II, LLC, and Indiana domestic limited liability company (“AEG II”). F. William Grube has sole voting and investment power over the common units. AEG II is co-owned by F. William Grube, William F. Grube, Jennifer G. Straumins, one grantor retained annuity trust for which Jennifer G. Straumins serves as sole trustee, and one grantor retained annuity trust for which Janet K. Grube, the spouse of F. William Grube, serves as sole trustee. F. William Grube disclaims beneficial ownership of the common units owned by AEG II except to the extent of his pecuniary interest therein.

(5)	Includes common units that are owned by the spouse and certain children of Fred M. Fehsenfeld, Jr., for which he disclaims beneficial ownership.

(6)

Does not include a total of 1,979,804 common units owned by two trusts, the direct or indirect beneficiaries of which are members of the Fred M. Fehsenfeld, Jr. family. Each of the trusts has five trustees, Fred M. Fehsenfeld, Jr., James C. Fehsenfeld, Nicholas J. Rutigliano, William S. Fehsenfeld and Amy M. Schumacher, 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 units owned by the trusts, and none of these units are shown as being beneficially owned by such directors in the table above.

(7)	Includes common units that are owned by the children of Jennifer G. Straumins, of which she disclaims beneficial ownership.

(8)	Includes common units that are owned by the children of William A. Anderson, of which he disclaims beneficial ownership.

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

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

(11)	Includes common units that are owned by the spouse of George C. Morris III of which he disclaims beneficial ownership.

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Equity Compensation Plan Information

The following table summarizes information about our equity compensation plans as of December 31, 2011:


	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (1) (a)		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
Equity compensation plans approved by unitholders		—	$	—		—
Equity compensation plans not approved by unitholders		206,511		—		486,650

Total		206,511	$	—		486,650

(1)

The Long-Term Incentive Plan contemplates the issuance or delivery of up to 783,960 common units to satisfy awards under the plan. The number of units presented in column (a) assumes that all outstanding grants will be satisfied by the issuance of new units or the purchase of existing units on the open market upon vesting. In fact, some portion of the phantom units may be settled in cash and some portion may be withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under Column (c). For more information on our Long-Term Incentive Plan, which did not require approval by our limited partners, refer to Item 11 “Executive and Director Compensation — Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Description of Long-Term Incentive Plan.”

Item 13.

Certain Relationships and Related Transactions and Director Independence

Distributions and Payments to Our General Partner and its Affiliates

Owners of our general partner and their affiliates own 19,381,726 common units representing a 37.6% limited partner interest in us. In addition, our general partner owns a 2% general partner interest in us and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.495 ($1.98 annualized) per unit, 25% of the amounts we distribute in excess of $0.563 ($2.25 annualized) per unit and 50% of amounts we distribute in excess of $0.675 ($2.70 annualized) per unit. Please refer to Part II, Item 5 “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities — Market Information” for a summary of cash distribution levels of the Company during the year ended December 31, 2011.

Our general partner does not receive any management fee or other compensation for its management of our partnership; however, our general partner and its affiliates are reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.

Omnibus Agreement

We entered into an omnibus agreement, dated January 31, 2006, with The Heritage Group and certain of its affiliates pursuant to which The Heritage Group and its controlled affiliates agreed not to engage in, whether by

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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.

Insurance Brokerage

Nicholas J. Rutigliano, a member of the board of directors of our general partner, founded and is the president of Tobias Insurance Group, Inc., a commercial insurance brokerage business, that has historically placed a portion of our insurance underwriting requirements, including our general liability, automobile liability, excess liability, workers’ compensation as well as directors’ and officers’ liability. The total premiums paid by us through Mr. Rutigliano’s firm for 2011 were approximately $0.6 million and were related to our directors’ and officers’ liability insurance. We believe these premiums are comparable to the premiums we would pay for such insurance from a non-affiliated third party and we have assessed our other insurance brokerage options to confirm this belief. We have transitioned the majority of the aforementioned insurance underwriting requirements to a non-affiliated third party commercial insurance broker.

Crude Oil Purchases

Since May 2008, we purchased a portion of our crude oil supplies from Legacy Resources Co., L.P. (“Legacy Resources”), an exploration and production company owned in part by The Heritage Group, our chief executive officer and vice chairman of the board of our general partner, F. William Grube, and Jennifer G. Straumins, our president and chief operating officer. Mr. Grube and Ms. Straumins serve as members of the board of directors of Legacy Resources. The total purchases made by us from Legacy Resources in 2011 were approximately $229.8 million, which represented purchases based upon standard, index-based market rates.

In May 2008, we began purchasing all of our crude oil requirements for our Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources. Based on historical usage, the estimated volume of crude oil sold by Legacy Resources and purchased by us for the Princeton refinery is approximately 7,000 barrels per day.

On January 26, 2009, we entered into a Master Crude Oil Supply Agreement with Legacy Resources (the “Master Crude Oil Supply Agreement”). Under this agreement, Legacy Resources may supply our Shreveport refinery with a portion of its crude oil requirements that are received via common carrier pipeline. Pricing for the

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crude oil purchased under each confirmation will be mutually agreed to by the parties and set forth in such confirmation and will include a market-based premium as determined and agreed to by the parties. The agreement was effective as of January 26, 2009 and will continue to be in effect until terminated by either party by written notice. Based on historical usage, the estimated volume of crude oil to be sold by Legacy Resources and purchased by us under this Agreement is up to 15,000 barrels per day. This agreement is not currently in use.

In September 2009, we entered into a Crude Oil Supply Agreement (the “Shreveport Crude Oil Supply Agreement”) with Legacy Resources. Under the Agreement, Legacy Resources supplies our Shreveport refinery with a portion of its crude oil requirements on a just in time basis utilizing a market-based pricing mechanism. Based on historical usage, the estimated volume of crude oil to be sold by Legacy Resources and purchased by us under this Agreement is up to 20,000 barrels per day.

On March 24, 2011, we entered into Amendment No. 5 (the “Princeton Amendment”) to that certain Crude Oil Supply Agreement, effective as of April 30, 2008 (as amended since such date, the “Princeton Crude Oil Supply Agreement”), by and between us and Legacy Resources, under which Legacy Resources supplied our Princeton refinery with all of the refinery’s crude oil requirements on a just-in-time basis. The Princeton Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Princeton Crude Oil Supply Agreement and shortened the termination notice period set forth in the Princeton Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Princeton Amendment, on March 24, 2011, we provided notice to Legacy Resources that it was exercising its contractual rights under the Princeton Crude Oil Supply Agreement, as amended by the Princeton Amendment, to terminate the Princeton Crude Oil Supply Agreement on May 31, 2011. We did not incur any material early termination penalties in connection with its termination of the Princeton Crude Oil Supply Agreement.

On March 24, 2011, we entered into Amendment No. 5 (the “Shreveport Amendment”) to the Shreveport Crude Oil Supply Agreement, effective as of September 1, 2009 (as amended since such date), by and between us and Legacy Resources, under which Legacy Resources supplies our Shreveport refinery with a portion of the refinery’s crude oil requirements on a just-in-time basis. The Shreveport Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Shreveport Crude Oil Supply Agreement and shortened the termination notice period set forth in the Shreveport Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Shreveport Amendment, on March 24, 2011, we provided notice to Legacy Resources that it was exercising its contractual rights under the Shreveport Crude Oil Supply Agreement, as amended by the Shreveport Amendment, to terminate the Shreveport Crude Oil Supply Agreement on May 31, 2011. We did not incur any material early termination penalties in connection with its termination of the Shreveport Crude Oil Supply Agreement.

With the termination of the agreements, we have one remaining crude oil supply agreement with Legacy Resources, the Master Crude Oil Purchase and Sale Agreement, that was entered into on January 26, 2009. No crude oil is currently being purchased by the Company under this agreement.

Because Legacy Resources is owned in part by one of our limited partners, an affiliate of our general partner, our chief executive officer and vice chairman of the board of directors of our general partner, F. William Grube, and our president and chief operating officer, Jennifer G. Straumins, the terms of those agreements were reviewed by the conflicts committee of the board of directors of our general partner, which consists entirely of independent directors. The conflicts committee approved the agreements after determining that the terms of the agreements are fair and reasonable to us.

Specialty Product Sales and Related Purchases

During 2011, we made ordinary course sales of certain specialty products to TruSouth Oil, LLC, a specialty petroleum packaging and distribution company located in Shreveport, Louisiana (“TruSouth”). Prior to the TruSouth Acquisition (described below), TruSouth was owned in part by The Heritage Group, Calumet,

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Incorporated, Fred M. Fehsenfeld, Jr. (chairman of the board of directors of our general partner) as an individual, certain Fehsenfeld family trusts established where Mr. Fehsenfeld or his family members are the beneficiary, Janet K. Grube (the spouse of F. William Grube) individually, and certain Grube family trusts for which Janet K. Grube is sole trustee. The total sales made by us to TruSouth in 2011 were approximately $14.7 million. As of December 31, 2011, the balance due us from TruSouth related to these products sales was approximately $1.7 million. The total purchases made by us from TruSouth in 2011 for blending and packaging services were approximately $0.6 million. As of December 31, 2011, there was an immaterial balance due from us to TruSouth related to these purchases. We believe that the product sales prices and credit terms offered to TruSouth are comparable to prices and terms offered to non-affiliated third party customers.

During 2011, we made ordinary course sales of certain specialty products to Johann Haltermann, Ltd. (“Haltermann”), a specialty chemical company owned in part by The Heritage Group and certain Grube family trusts for which Janet K. Grube is sole trustee. The total sales made by us to Haltermann in 2011 were approximately $1.4 million. As of December 31, 2011 there was no balance due us from Haltermann related to these products sales. We anticipate that we will continue to sell products to Haltermann in the future. We believe that the product sales prices and credit terms offered to Haltermann are comparable to prices and terms offered to non-affiliated third party customers.

During 2011, we made ordinary course sales of certain specialty products to Heritage-Crystal Clean Inc. (“Crystal Clean”), a cleaning and waste removal company owned in part by The Heritage Group and Fred M. Fehsenfeld, Jr. as an individual. The total sales made by us to Crystal Clean in 2011 were approximately $0.3 million. As of December 31, 2011, there was an immaterial balance due us from Crystal Clean related to these products sales. We anticipate that we will continue to sell products to Crystal Clean in the future. The total purchases made by us from Crystal Clean in 2011 for cleaning and waste removal services were approximately $0.6 million. As of December 31, 2011, there was an immaterial balance due from us to Crystal Clean related to these purchases. We believe that the product sales prices and credit terms offered to Crystal Clean are comparable to prices and terms offered to non-affiliated third party customers.

During 2011, we made payments to Asphalt Materials, Inc., an affiliate of The Heritage Group (“Asphalt Materials”), for expenses related to the business use of The Heritage Group’s company plane by our senior executive officers and for environmental consulting services provided to us by Asphalt Materials. The aggregate payments for these services made by us to Asphalt Materials in 2011 were approximately $0.5 million. As of December 31, 2011, there was an immaterial balance due from us to Asphalt Materials related to these services. We believe that the costs of the services provided to us by Asphalt Materials are comparable to costs charged by non-affiliated third-party suppliers of similar services. We also reimburse Asphalt Materials for ordinary course purchases made by us under a procurement card program administered by Asphalt Materials. As of December 31, 2011, there was approximately $1.3 million payable by us to Asphalt Materials related to the reimbursement of these ordinary course purchases. We expect that we will continue to utilize each of these services from Asphalt Materials in the future.

TruSouth Acquisition

On January 6, 2012, we completed the acquisition of all of the outstanding membership interests of TruSouth for aggregate consideration of approximately $25.5 million. Immediately prior to its acquisition, TruSouth was owned in part by Fred M. Fehsenfeld, Jr.; the spouse of F. William Grube; and other members of the Fehsenfeld and Grube families, who also own our general partner. The terms of the agreement were reviewed by the conflicts committee of the board of directors of our general partner, which consists entirely of independent directors. The conflicts committee approved the agreement after determining that the terms of the agreement were fair and reasonable to us.

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Procedures for Review and Approval of Related Person Transactions

Effective February 9, 2007, to further formalize the process by which related person transactions are analyzed and approved or disapproved, the board of directors of our general partner has adopted the Calumet Specialty Products Partners, L.P. Related Person Transactions Policy (the “Policy”) to be followed in connection with all related person transactions (as defined by the Policy) involving the Company and its subsidiaries. The Policy was adopted to provide guidelines and procedures for the application of the partnership agreement to related person transactions and to further supplement the conflicts resolutions policies already set forth therein.

The Policy defines a “related person transaction” to mean any transaction since the beginning of the Company’s last fiscal year (or any currently proposed transaction) in which: (i) the Company or any of its subsidiaries was or is to be a participant; (ii) the amount involved exceeds $120,000 (including any series of similar transactions exceeding such amount on an annual basis); and (iii) any related person (as defined in the Policy) has or will have a direct or indirect material interest. Under the terms of the policy, our general partner’s chief executive officer (“CEO”) has the authority to approve a related person transaction (considering any and all factors as the CEO determines in his sole discretion to be relevant, reasonable or appropriate under the circumstances) so long as it is:

(a) in the normal course of the Company’s business;

(b) not one in which the CEO or any of his immediate family members has a direct or indirect material interest; and

(c) on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or fair to the Company, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Company).

The CEO does not have the authority to approve the issuances of equity or grants of awards under the Company’s Long-Term Incentive Plan, except as provided in that plan. Pursuant to the Policy, any other related person transaction must be approved by the conflicts committee acting in accordance with the terms and provisions of its charter.

A copy of the Policy is available on our website at www.calumetspecialty.com and will be provided to unitholders without charge upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Suite 200, Indianapolis, IN 46214.

Please see Item 10 “Directors, Executive Officers of Our General Partner and Corporate Governance” for a discussion of director independence matters.

Item 14.

Principal Accounting Fees and Services

The following table details the aggregate fees billed for professional services rendered by our independent auditor during 2011 and 2010.


	Year Ended December 31,
	2011		2010
Audit fees	$	1,680,000	$	1,485,000
Audit-related fees		581,000		131,000
Tax fees		—		12,000
All other fees		139,500		195,500

Total	$	2,400,500	$	1,823,500

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“Audit fees” above include those related to our annual audit, audit of our general partner, and quarterly review procedures.

“Audit-related fees” primarily relate to our offering of senior unsecured notes in April and September 2011, our public offering of common units in February and September 2011 and purchase price allocation related to the Superior Acquisition.

“Tax fees” are related property tax reviews.

“All other fees” primarily consist of those associated with insurance claim consulting services.

Pre-Approval Policy

The audit committee of our general partner’s board of directors has adopted an audit committee charter, which is available on our website at www.calumetspecialty.com. The charter requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee. Services for the audit, tax and all other fee categories above were pre-approved by the audit committee.

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PART IV

Item 15.

Exhibits

(a)(1) Consolidated Financial Statements

The consolidated financial statements of Calumet Specialty Products Partners, L.P. and Calumet GP, LLC are included in Part II, Item 8 “Financial Statements and Supplementary Data”.

(a)(2) Financial Statement Schedules

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

(a)(3) Exhibits

The following documents are filed as exhibits to this Annual Report:


Exhibit Number		Description
2.1	—	Asset Purchase Agreement, dated as of July 25, 2011, between Calumet Specialty Products Partners, L.P. and Murphy Oil Corporation (incorporated by reference to Exhibit 2.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 4, 2011 (File No 000-51734)).
3.1	—	Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.2	—	Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
3.3	—	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No 000-51734)).
3.4	—	Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No 000-51734)).
3.5	—	Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.6	—	Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
4.1	—	Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Quarterly Report on Form 10-Q filed with the Commission on November 4, 2010 (File No 000-51734).
4.2	—	Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association (as successor by merger to Wilmington Trust FSB), as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).

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Exhibit Number		Description
4.3**	—	First Supplemental Indenture to the Indenture dated April 21, 2011, dated October 7, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association (as successor by merger to Wilmington Trust FSB), as trustee.
4.4**	—	Second Supplemental Indenture to the Indenture dated April 21, 2011, dated February 15, 2012, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association (as successor by merger to Wilmington Trust FSB), as trustee.
4.5	—	Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).
4.6	—	Indenture, dated September 19, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on September 21, 2011 (File No. 000-51734)).
4.7**	—	First Supplemental Indenture to the Indenture dated as of September 19, 2011, dated February 15, 2012, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee.
4.8	—	Registration Rights Agreement, dated September 19, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on September 21, 2011 (File No. 000-51734)).
10.1	—	Noncompetition Agreement, dated January 3, 2008, between ConocoPhillips Company and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
10.2	—	Noncompetition Agreement, dated January 3, 2008, between M.E. Zukerman Specialty Oil Corporation and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
10.3	—	LVT Unit Agreement, effective January 1, 2008, between ConocoPhillips Company and Calumet Penreco, LLC (incorporated by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.4	—	LVT Feedstock Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.5	—	HDW Diesel Sale and Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.6	—	Amended Crude Oil Sale Contract, effective April 1, 2008, between Plains Marketing, L.P. and Calumet Shreveport Fuels, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on March 20, 2008 (File No 000-51734)).

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Exhibit Number		Description
10.7	—	Crude Oil Supply Agreement, dated as of April 30, 2008 and effective May 1, 2008, between Calumet Lubricants Co., Limited Partnership, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on May 6, 2008 (File No 000-51734)).
10.8	—	Amendment No. 1 to Crude Oil Supply Agreement, dated as of November 25, 2008 and effective October 1, 2008, between Calumet Lubricants Co., Limited Partnership, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on December 1, 2008 (File No 000-51734)).
10.9	—	Amendment No. 2 to Crude Oil Supply Agreement, dated as of April 20, 2009 and effective April 1, 2009, between Calumet Lubricants Co., Limited Partnership, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on April 22, 2009 (File No 000-51734)).
10.10	—	Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.23 to the Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No 000-51734).
10.11	—	Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Lubricants Co., Limited Partnership., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.25 to the Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000- 51734)).
10.12	—	Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Lubricants Co., Limited Partnership and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.26 to the Partnership’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).
10.13	—	Crude Oil Supply Agreement, effective as of September 1, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on September 4, 2009 (File No 000-51734)).
10.14	—	Amendment No. 1 to Crude Oil Supply Agreement, dated as of September 30, 2009 and effective September 1, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the Commission on November 6, 2009 (File No 000-51734)).
10.15		Amendment No. 2 to Crude Oil Supply Agreement, dated as of December 3, 2009 and effective November 1, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on December 3, 2009 (File No 000-51734)).
10.16	—	Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.22 to the Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No 000-51734).
10.17	—	Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.24 to the Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000-51734)).
10.18	—	Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Shreveport Fuels, LLC and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.27 to the Partnership’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).

179


Exhibit Number		Description
10.19*	—	Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan, dated December 18, 2008 and effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K) filed with the Commission on December 22, 2008 (File No 000-51734).
10.20*	—	Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No 000-51734)).
10.21*	—	F. William Grube Employment Contract (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
10.22	—	Omnibus Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Registration Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
10.23*	—	Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement on Form S-1 (File No. 333-128880)) filed with the Commission on November 16, 2005.
10.24*	—	Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009 (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K filed with the Commission on March 4, 2009 (File No. 000-517347).
10.25*	—	Reaffirmation Agreement, General Release and Covenant Not to Sue, dated December 22, 2010 and effective as of December 29, 2010, between Calumet GP, LLC and Allan A. Moyes III (incorporated by reference to Exhibit 10.26 to the Current Report on Form 8-K filed with the Commission on January 4, 2011 (File No 000- 51734)).
10.26	—	Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)).
10.27**	—	First Amendment to Amended and Restated Credit Agreement, dated as December 28, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders and Bank of America, N.A., as Agent.
10.28	—	Collateral Trust Agreement, as amended, dated as of April 21, 2011, among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 10-Q filed with the SEC on August 8, 2011 (File No 000-51734)).
10.29	—	Amendment No. 2 to Collateral Trust Agreement, effective as of September 30, 2011, by and among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on October 6, 2011 (File No. 000-51734)).
10.30**	—	Crude Oil Purchase Agreement effective as of October 1, 2011, by and between BP Products North America Inc. and Calumet Superior, LLC. Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
12.1**	—	Statement regarding computation of ratios.
21.1**	—	List of Subsidiaries of Calumet Specialty Products Partners, L.P.
23.1**	—	Consent of Ernst & Young, LLP, independent registered public accounting firm.
31.1**	—	Sarbanes-Oxley Section 302 certification of F. William Grube.

180


Exhibit Number		Description
31.2**	—	Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.
32.1**	—	Section 1350 certification of F. William Grube and R. Patrick Murray, II.
100.INS***	—	XBRL Instance Document
101.SCH***	—	XBRL Taxonomy Extension Schema Document
101.CAL***	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB***	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE***	—	XBRL Taxonomy Extension Presentation Linkbase Document

*	Identifies management contract and compensatory plan arrangements.

**	Filed herewith.

***

XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

181

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,
		Chief Executive Officer, Director and Vice Chairman of the Board of Calumet GP, LLC (Principal Executive Officer)

Date: February 29, 2012

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	Chief Executive Officer, Director and Vice Chairman of the Board of Calumet GP, LLC (Principal Executive Officer)	Date: February 29, 2012

/s/ Jennifer G. Straumins Jennifer G. Straumins	President and Chief Operating Officer of Calumet GP, LLC	Date: February 29, 2012

/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: February 29, 2012

/s/ Fred M. Fehsenfeld, Jr. Fred M. Fehsenfeld, Jr.	Director and Chairman of the Board of Calumet GP, LLC	Date: February 29, 2012

/s/ James S. Carter James S. Carter	Director of Calumet GP, LLC	Date: February 29, 2012

/s/ William S. Fehsenfeld William S. Fehsenfeld	Director of Calumet GP, LLC	Date: February 29, 2012

/s/ Robert E. Funk Robert E. Funk	Director of Calumet GP, LLC	Date: February 29, 2012

/s/ Nicholas J. Rutigliano Nicholas J. Rutigliano	Director of Calumet GP, LLC	Date: February 29, 2012

/s/ George C. Morris III George C. Morris III	Director of Calumet GP, LLC	Date: February 29, 2012

182

Index to Exhibits


Exhibit Number		Description
2.1	—	Asset Purchase Agreement, dated as of July 25, 2011, between Calumet Specialty Products Partners, L.P. and Murphy Oil Corporation (incorporated by reference to Exhibit 2.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 4, 2011 (File No 000-51734)).
3.1	—	Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.2	—	Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
3.3	—	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No 000-51734)).
3.4	—	Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No 000-51734)).
3.5	—	Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.6	—	Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
4.1	—	Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Quarterly Report on Form 10-Q filed with the Commission on November 4, 2010 (File No 000-51734).
4.2	—	Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association (as successor by merger to Wilmington Trust FSB), as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).
4.3**	—	First Supplemental Indenture to the Indenture dated April 21, 2011, dated October 7, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association (as successor by merger to Wilmington Trust FSB), as trustee.
4.4**	—	Second Supplemental Indenture to the Indenture dated April 21, 2011, dated February 15, 2012, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association (as successor by merger to Wilmington Trust FSB), as trustee.
4.5	—	Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No. 000-51734)).
4.6	—	Indenture, dated September 19, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on September 21, 2011 (File No. 000-51734)).

183


Exhibit Number		Description
4.7**	—	First Supplemental Indenture to the Indenture dated as of September 19, 2011, dated February 15, 2012, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee.
4.8	—	Registration Rights Agreement, dated September 19, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on September 21, 2011 (File No. 000-51734)).
10.1	—	Noncompetition Agreement, dated January 3, 2008, between ConocoPhillips Company and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
10.2	—	Noncompetition Agreement, dated January 3, 2008, between M.E. Zukerman Specialty Oil Corporation and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Commission on January 9, 2008 (File No 000-51734)).
10.3	—	LVT Unit Agreement, effective January 1, 2008, between ConocoPhillips Company and Calumet Penreco, LLC (incorporated by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.4	—	LVT Feedstock Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.5	—	HDW Diesel Sale and Purchase Agreement, effective January 1, 2008, between ConocoPhillips Company, as Seller and Calumet Penreco, LLC, as Buyer (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K filed with the Commission on March 4, 2008 (File No 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.6	—	Amended Crude Oil Sale Contract, effective April 1, 2008, between Plains Marketing, L.P. and Calumet Shreveport Fuels, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on March 20, 2008 (File No 000-51734)).
10.7	—	Crude Oil Supply Agreement, dated as of April 30, 2008 and effective May 1, 2008, between Calumet Lubricants Co., Limited Partnership, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on May 6, 2008(File No 000-51734)).
10.8	—	Amendment No. 1 to Crude Oil Supply Agreement, dated as of November 25, 2008and effective October 1, 2008, between Calumet Lubricants Co., Limited Partnership, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on December 1, 2008 (File No 000-51734)).
10.9	—	Amendment No. 2 to Crude Oil Supply Agreement, dated as of April 20, 2009 and effective April 1, 2009, between Calumet Lubricants Co., Limited Partnership, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on April 22, 2009 (File No 000-51734)).
10.10	—	Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.23 to the Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No 000-51734).

184


Exhibit Number		Description
10.11	—	Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Lubricants Co., Limited Partnership., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.25 to the Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000- 51734)).
10.12	—	Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Lubricants Co., Limited Partnership and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.27 to the Partnership’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).
10.13	—	Crude Oil Supply Agreement, effective as of September 1, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on September 4, 2009 (File No 000-51734)).
10.14	—	Amendment No. 1 to Crude Oil Supply Agreement, dated as of September 30, 2009 and effective September 1, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the Commission on November 6, 2009 (File No 000-51734)).
10.15		Amendment No. 2 to Crude Oil Supply Agreement, dated as of December 3, 2009 and effective November 1, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on December 3, 2009 (File No 000-51734)).
10.16	—	Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.22 to the Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No 000-51734).
10.17	—	Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.24 to the Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000-51734)).
10.18	—	Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Shreveport Fuels, LLC and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.27 to the Partnership’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).
10.19*	—	Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan, dated December 18, 2008 and effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K) filed with the Commission on December 22, 2008 (File No 000-51734).
10.20*	—	Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No 000-51734)).
10.21*	—	F. William Grube Employment Contract (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
10.22	—	Omnibus Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Registration Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
10.23*	—	Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement on Form S-1 (File No. 333-128880)) filed with the Commission on November 16, 2005.

185


Exhibit Number		Description
10.24*	—	Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009 (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K filed with the Commission on March 4, 2009 (File No. 000-517347).
10.25*	—	Reaffirmation Agreement, General Release and Covenant Not to Sue, dated December 22, 2010 and effective as of December 29, 2010, between Calumet GP, LLC and Allan A. Moyes III (incorporated by reference to Exhibit 10.26 to the Current Report on Form 8-K filed with the Commission on January 4, 2011 (File No 000- 51734)).
10.26	—	Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)).
10.27**	—	First Amendment to Amended and Restated Credit Agreement, dated December 28, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders and Bank of America, N.A., as Agent.
10.28	—	Collateral Trust Agreement, as amended, dated as of April 21, 2011, among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 10-Q filed with the SEC on August 8, 2011 (File No 000-51734)).
10.29	—	Amendment No. 2 to Collateral Trust Agreement, effective as of September 30, 2011, by and among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on October 6, 2011 (File No. 000-51734)).
10.30**	—	Crude Oil Purchase Agreement effective as of October 1, 2011, by and between BP Products North America Inc. and Calumet Superior, LLC. Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
12.1**	—	Statement regarding computation of ratios.
21.1**	—	List of Subsidiaries of Calumet Specialty Products Partners, L.P.
23.1**	—	Consent of Ernst & Young, LLP, independent registered public accounting firm.
31.1**	—	Sarbanes-Oxley Section 302 certification of F. William Grube.
31.2**	—	Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.
32.1**	—	Section 1350 certification of F. William Grube and R. Patrick Murray, II.
100.INS***	—	XBRL Instance Document
101.SCH***	—	XBRL Taxonomy Extension Schema Document
101.CAL***	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB***	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE***	—	XBRL Taxonomy Extension Presentation Linkbase Document

*	Identifies management contract and compensatory plan arrangements.

**	Filed herewith.

***

186