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, 2012
	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 LLC

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

NONE.

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

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 þ	Accelerated filer ¨	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 was approximately $937.1 million on June 29, 2012, based on $23.78 per unit, the closing price of the common units as reported on the NASDAQ Global Select Market on such date.

On February 28, 2013, there were 63,279,778 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

NONE.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

FORM 10-K — 2012 ANNUAL REPORT

Table of Contents

		Page
PART I
Items 1 and 2.	Business and Properties	3
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	43
Item 3.	Legal Proceedings	43
Item 4.	Mine Safety Disclosures	43
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	44
Item 6.	Selected Financial Data	45
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	72
Item 8.	Financial Statements and Supplementary Data	74
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	131
Item 9A.	Controls and Procedures	131
Item 9B.	Other Information	131
PART III
Item 10.	Directors, Executive Officers of Our General Partner and Corporate Governance	132
Item 11.	Executive and Director Compensation	136
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	159
Item 13.	Certain Relationships and Related Transactions and Director Independence	161
Item 14.	Principal Accounting Fees and Services	164
PART IV
Item 15.	Exhibits	165

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Annual Report”) includes certain “forward-looking statements.” 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 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 and (iii) 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.

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PART I

Items 1 and 2. Business and Properties

Overview

We are a leading independent producer of high-quality, specialty hydrocarbon products and fuel products in North America. We are headquartered in Indianapolis, Indiana and own facilities primarily located in Louisiana, Wisconsin, Montana, Texas and Pennsylvania. We own and lease additional blending and storage 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, waxes and asphalt. 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. We also blend and market specialty products through our brand Royal Purple. 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, 2012, approximately 47.9% of our sales and 60.1% of our gross profit were generated from our specialty products segment and approximately 52.1% of our sales and 39.9% of our gross profit were generated from our fuel products segment.

Our Primary Operating Assets

Our primary operating assets consist of:

Refinery/Facility	Location	Date Acquired	Throughput Capacity in barrels per day (“bpd”)	Products
Shreveport	Louisiana	2001	60,000	Specialty lubricating oils and waxes, gasoline, diesel and jet fuel
Superior	Wisconsin	2011	45,000	Gasoline, diesel, asphalt and heavy fuel oils
San Antonio	Texas	2013	14,500	Jet fuel, diesel, other fuel products and specialty solvents
Cotton Valley	Louisiana	1995	13,500	Specialty solvents that are used principally in the manufacture of paints, cleaners, automotive products and drilling fluids
Montana	Montana	2012	10,000	Gasoline, diesel, jet fuel and asphalt
Princeton	Louisiana	1990	10,000	Specialty lubricating oils, including process oils, base oils, transformer oils and refrigeration oils
Karns City	Pennsylvania	2008	5,500	White mineral oils, solvents, petrolatums, gelled hydrocarbons, cable fillers and natural petroleum sulfonates
Dickinson	Texas	2008	1,300	White mineral oils, compressor lubricants and natural petroleum sulfonates
Royal Purple	Texas	2012	N/A	Specialty products including industrial lubricating oils, gear oils and motor oils

Storage, Distribution and Logistics Assets.    We own and operate product 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

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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 2,700 leased railcars to receive crude oil or distribute our products throughout the U.S. and Canada. In total, we have approximately 12.2 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 47.9% of our sales and 60.1% of our gross profit in 2012 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. In our fuel products segment, which accounted for 52.1% of our sales and 39.9% of our gross profit in 2012, we seek to mitigate our exposure to fuel products margin volatility by maintaining a longer-term fuel products hedging program. In addition, our recent acquisitions of various refineries located in different geographical locations provides for diversity of cash flows based on the refining margin environment in each such region. 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, such as the enhancement at our Superior refinery completed in November 2012, which enables the refinery to ship crude oil by railcar to our other facilities as well as third parties. 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. We also continue to focus on optimizing current operations through energy savings initiatives, product quality enhancements and product yield improvements.

• 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 each of our specialty products and fuel products segments. In addition, we may pursue selected acquisitions in new geographic or product areas to the extent we perceive similar opportunities. For example, since 2011 we have completed the following acquisitions that we believe significantly enhance and diversify our existing specialty products and fuel products segments:

◦ TruSouth Oil, LLC - a specialty petroleum packaging and distribution company acquired in January 2012.

◦ Louisiana, Missouri facility - an aviation and refrigerant synthetic lubricants business of Hercules Incorporated acquired in January 2012.

◦ Royal Purple, Inc. - a leading independent formulator and marketer of specialty synthetic lubricants acquired in July 2012.

◦ Montana Refining Company, Inc. - a refinery that produces and sells gasoline, diesel, jet fuel and asphalt products acquired in October 2012.

◦ San Antonio, Texas refinery - a refinery that produces and sells jet fuel, diesel, other fuel products and specialty solvents acquired in January 2013.

See “—Recent Acquisitions” below for additional information regarding these acquisitions.

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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 3,500 specialty products. We believe that our ability to provide our customers with a more diverse selection of products than most of our competitors 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 4,900 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, 2012, 2011 and 2010.

• 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 fuel products refineries have the capability to make ultra-low sulfur diesel and gasoline that meet 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. 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

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) and a manufacturing facility located in Louisiana, Missouri from Hercules Incorporated, a subsidiary of Ashland, Inc., for aggregate consideration of approximately $19.6 million (“Missouri Acquisition”). The acquisition was financed with borrowings under our revolving credit facility and cash on hand.

TruSouth Oil

On January 6, 2012, we completed the acquisition of TruSouth Oil, LLC, a specialty petroleum packaging and distribution company located in Shreveport, Louisiana (“TruSouth”) for aggregate consideration of approximately $26.8 million (“TruSouth Acquisition”), 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.

Royal Purple

On July 3, 2012, we completed the acquisition of Royal Purple, Inc. (“Royal Purple”), a Texas corporation which was converted into a Delaware limited liability company at closing, for aggregate consideration of approximately $331.2 million, net of cash acquired (“Royal Purple Acquisition”). Royal Purple is a leading independent formulator and marketer of premium industrial and consumer synthetic lubricants to a diverse customer base across several large markets including oil and gas, chemicals and refining, power generation, manufacturing and transportation, food and drug manufacturing and automotive aftermarket. The Royal Purple Acquisition was financed with net proceeds of $262.6 million from our June 2012 private placement of 9 5/8% senior notes due August 1, 2020 and cash on hand. We believe the Royal Purple Acquisition increases our position in the specialty lubricants markets, expands our geographic reach, increases our asset diversity and enhances our specialty products segment.

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Montana

On October 1, 2012, we completed the acquisition from Connacher Oil and Gas Limited (“Connacher”) of all the shares of common stock of Montana Refining Company, Inc., which was converted into a Delaware limited liability company, Calumet Montana Refining, LLC (“Montana”), at closing, and an insignificant affiliated company for aggregate consideration of approximately $191.6 million, net of cash acquired, including an estimated $27.6 million of income taxes due to the conversion to a Delaware limited liability company and excluding certain purchase price adjustments (“Montana Acquisition”). Montana produces gasoline, diesel, jet fuel and asphalt, which are marketed primarily into local markets in Washington, Montana, Idaho and Alberta, Canada. The Montana Acquisition was funded primarily with cash on hand with the balance through borrowings under our revolving credit facility. We believe the Montana Acquisition further diversifies our crude oil feedstock slate, operating asset base and geographical presence.

San Antonio

On January 2, 2013, we completed the acquisition of the San Antonio, Texas refinery and associated crude oil pipeline, crude oil terminal, other operating and logistics assets and inventories (“San Antonio”) of NuStar Refining, LLC and NuStar Logistics, L.P., both wholly owned subsidiaries of NuStar Energy L.P., for aggregate consideration of approximately $115.7 million, including approximately $15.0 million for inventories acquired at closing, subject to customary purchase price adjustments (the “San Antonio Acquisition”). San Antonio produces jet fuel, diesel, other fuel products and specialty solvents. The San Antonio Acquisition was funded primarily with borrowings under our revolving credit facility with the balance through cash on hand. We believe the San Antonio Acquisition further diversifies our crude oil feedstock slate, operating asset base and geographical presence. Please see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Cash Flows from Operating, Investing and Financing Activities” for additional information regarding the repayment of these revolving credit facility borrowings.

Ongoing Acquisition Activities

Consistent with our business growth strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. These acquisition efforts may involve participation by us in processes that have been made public and involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only potential buyer or one of a limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets and operations which, if acquired, could have a material effect on our financial condition and results of operations and require special financing.

We typically do not announce a transaction until after we have executed a definitive acquisition agreement. However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of an acquisition until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential acquisition can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive acquisition agreement will be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition efforts will be successful. Although we expect the acquisitions we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized.

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 28, 2013, we had 63,279,778 common units and 1,291,424 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

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 the results of operations at our Superior refinery commencing October 1, 2011, Missouri facility commencing January 3, 2012, TruSouth facility commencing January 6, 2012, Royal Purple facility commencing July 3, 2012 and Montana refinery commencing October 1, 2012.

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	Year Ended December 31,				Year Ended December 31,
	2012	2011	% Change		2011	2010	% Change
	(In bpd)				(In bpd)
Total sales volume (1)	97,789	66,134	47.9	%	66,134	55,668	18.8	%
Total feedstock runs (2)	97,600	69,295	40.8	%	69,295	55,957	23.8	%
Facility production: (3)
Specialty products:
Lubricating oils	14,524	14,427	0.7	%	14,427	13,697	5.3	%
Solvents	9,332	10,508	(11.2	)%	10,508	9,347	12.4	%
Waxes	1,280	1,269	0.9	%	1,269	1,220	4.0	%
Packaged and synthetic specialty products	1,351	—	—		—	—	—
Fuels	669	556	20.3	%	556	1,050	(47.0	)%
Asphalt and other by-products	14,219	10,090	40.9	%	10,090	6,907	46.1	%
Total specialty products	41,375	36,850	12.3	%	36,850	32,221	14.4	%
Fuel products:
Gasoline	24,394	13,409	81.9	%	13,409	8,754	53.2	%
Diesel	22,438	14,721	52.4	%	14,721	10,800	36.3	%
Jet fuel	4,325	4,520	(4.3	)%	4,520	5,004	(9.7	)%
Heavy fuel oils and other	3,640	1,409	158.3	%	1,409	535	163.4	%
Total fuel products	54,797	34,059	60.9	%	34,059	25,093	35.7	%
Total facility production (3)	96,172	70,909	35.6	%	70,909	57,314	23.7	%

 ____________________

(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 includes 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) 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. 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.

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	Year Ended December 31,
	2012				2011				2010
	(In thousands)
Sales of specialty products:
Lubricating oils	$	1,007,928	22	%	$	947,798	30	%	$	759,701	35	%
Solvents	491,114		11	%	495,934		16	%	396,894		18	%
Waxes	142,765		3	%	143,111		5	%	124,964		6	%
Packaged and synthetic specialty products (1)	161,673		3	%	—		—	%	—		—	%
Fuels (2)	2,029		—	%	3,432		—	%	5,507		—	%
Asphalt and other by-products (3)	426,093		9	%	217,351		7	%	121,806		5	%
Total	2,231,602		48	%	1,807,626		58	%	1,408,872		64	%
Sales of fuel products:
Gasoline	1,174,859		25	%	619,630		20	%	304,544		14	%
Diesel	941,047		20	%	513,334		16	%	330,756		15	%
Jet fuel	183,953		4	%	148,036		5	%	135,796		6	%
Heavy fuel oils and other (4)	125,821		3	%	46,297		1	%	10,784		1	%
Total	2,425,680		52	%	1,327,297		42	%	781,880		36	%
Consolidated sales	$	4,657,282	100	%	$	3,134,923	100	%	$	2,190,752	100	%

 ____________________

(1) Represents packaged and synthetic specialty products at the Royal Purple, TruSouth and Missouri facilities.

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

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

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

Please read Note 14 “Segments and Related Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this 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 (“Shreveport”), 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, asphalt and by-products.

The Shreveport refinery consists of 17 major processing units including hydrotreating, catalytic reforming and dewaxing units with 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, adding a second reactor to the high pressure hydrotreater, resuming production of gasoline, diesel and other fuel products and adding 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,
	2012	2011	2010
	(In bpd)
Crude oil throughput capacity	60,000	60,000	60,000
Total feedstock runs (1) (2)	39,831	39,910	36,409
Total refinery production (2) (3)	39,825	39,910	36,395

(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 and Princeton refineries.

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For more information about the shutdown of the ExxonMobil pipeline, which impacted feedstock runs at the refinery during 2012, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

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

(3) Total refinery production includes certain interplant feedstock supplied to our Cotton Valley and Princeton refineries 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 identification number fuel credits (“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; however, the pipeline has been shutdown since April 28, 2012. The enhancement project at our Superior refinery completed in November 2012 enables the Superior refinery to receive crude oil by railcar and subsequently ship crude oil by railcar to our Shreveport refinery. Crude oil is also purchased from various suppliers, including local producers, who deliver crude oil to the Shreveport refinery via tank truck.

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 U.S. 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, in Superior, Wisconsin (“Superior”). The Superior refinery currently has aggregate crude oil throughput capacity of 45,000 bpd and processes light and heavy crude oil from the Bakken shale oil formation in North Dakota and western Canada into fuel products and asphalt.

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 production at our Superior refinery since its acquisition on September 30, 2011.

	Superior Refinery
	Year Ended December 31, 2012	Three Months Ended December 31, 2011
	(In bpd)
Crude oil throughput capacity	45,000	45,000
Total feedstock runs (1) (2)	34,609	35,335
Total refinery production (2)	34,742	35,335

(1) Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Superior refinery.

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

The 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 and heavy fuel oils. 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 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 sold through the Superior refinery truck rack, several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through our Duluth terminal. The Superior wholesale fuel business also sells gasoline wholesale to SPUR branded gas stations located throughout the Upper Midwest (including Minnesota, Wisconsin and Michigan), which are owned and operated by independent franchisees. The Superior refinery ships finished fuel products and asphalt by railcar and truck service. Asphalt products produced at the Superior refinery are sold through our terminals in Rhinelander and Crookston 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, North Dakota, South Dakota and Utah.

The Superior refinery receives crude oil via pipeline and railcar. The Enbridge Pipeline System (the “Enbridge Pipeline”) delivers crude oil to the Superior refinery and is adjacent to one of the Enbridge Pipeline’s first crude oil holding facilities after crossing the Canadian border into the U.S., providing reliable access to high quality crude oil from the Bakken shale oil formation in North Dakota and from western Canada. The refinery receives approximately 63% 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, please read the information provided under Note 5 “Commitments and Contingencies” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report. In November 2012, the Superior refinery completed an enhancement project which enables the refinery to receive crude oil by railcar and subsequently ship crude oil by railcar to our Shreveport refinery as well as other third parties.

San Antonio Refinery

The San Antonio refinery, located on a 32-acre site in San Antonio, Texas, has aggregate crude oil throughput capacity of 14,500 bpd and processes light crude oil from south Texas, including the Eagle Ford Shale formation, into a variety of transportation fuels, feedstocks and specialty products. The San Antonio refinery consists of five major processing units including hydrotreating, catalytic reforming and solvents distillation with approximately 162,000 barrels of storage capacity in 57 tanks and related loading and unloading facilities and utilities.

Currently, the San Antonio refinery produces jet fuel, diesel, gasoline, other fuel products and specialty solvents. The San Antonio refinery is compliant with federal regulations for ultra-low sulfur diesel. The San Antonio refinery ships products by railcar and truck. Product sales are primarily made through spot agreements and short-term contracts. The San Antonio refinery purchases crude oil and intermediate products from various suppliers and receives crude oil by pipeline originating from its crude oil terminal in Elmendorf, Texas (“Elmendorf”), providing reliable access to high quality crude oil from Texas, primarily the Eagle Ford Shale. The Elmendorf terminal has aggregate storage capacity of approximately 188,000 barrels.

Cotton Valley Refinery

The Cotton Valley refinery, located on a 77-acre site in Cotton Valley, Louisiana (“Cotton Valley”), currently has aggregate crude oil throughput capacity of 13,500 bpd, hydrotreating capacity of 6,200 bpd and processes crude oil into specialty solvents 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.

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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. 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,
	2012	2011	2010
	(In bpd)
Crude oil throughput capacity	13,500	13,500	13,500
Total feedstock runs (1) (2)	5,487	5,806	5,510
Total refinery production (2) (3)	7,550	7,951	7,229

(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 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, 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.

Montana Refinery

The Montana refinery, located on an 86-acre site in Great Falls, Montana, currently has aggregate crude oil throughput capacity of 10,000 bpd and processes light and heavy crude oil from Canada into fuel and asphalt products.

The Montana refinery consists of 13 major processing units including hydrotreating, catalytic reforming, fluid catalytic cracking and alkylation units with approximately 939,000 barrels of storage capacity in 71 tanks and related loading and unloading facilities and utilities. The following table sets forth historical information about production at the Montana refinery since our acquisition of the refinery on October 1, 2012.

	Montana Refinery
	Three Months Ended December 31, 2012
	(In bpd)
Crude oil throughput capacity	10,000
Total feedstock runs (1) (2)	10,169
Total refinery production (2)	10,170

(1) Total feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our Montana refinery from October 1, 2012 through December 31, 2012.

(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, 2012 through December 31, 2012. 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.

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Currently, the Montana refinery produces gasoline, diesel, jet fuel and asphalt products. The Montana 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 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 Montana refinery ships finished fuel and asphalt products by railcar and truck service. Finished fuel and asphalt products sales are primarily made through spot agreements and short-term contracts.

The Montana refinery purchases crude oil from various suppliers and receives crude oil by pipeline through the Front Range Pipeline (“Front Range”) via the Bow River Pipeline in Canada, providing reliable access to high quality crude oil from western Canada.

Princeton Refinery

The Princeton refinery, located on a 208-acre site in Princeton, Louisiana (“Princeton”), currently 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 further processed or blended for coating and roofing product applications at the Princeton refinery or transported to the Shreveport refinery for further 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,
	2012	2011	2010
	(In bpd)
Crude oil throughput capacity	10,000	10,000	10,000
Total feedstock runs (1)	6,914	6,844	6,096
Total refinery production (1) (2)	6,971	6,895	6,138

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

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

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, road paving and emulsions for road paving and specialty applications.

The Princeton refinery receives crude oil via tank truck, railcar and the Plains pipeline system. Its crude oil supply primarily originates from east Texas and north Louisiana, which is purchased directly from third-party suppliers under month-to-month evergreen supply contracts and on the spot market. The Princeton refinery ships its finished products throughout the U.S. via both truck and railcar service.

Royal Purple Facility

The Royal Purple facility, located on a 23-acre site in Porter, Texas, blends and packages high performance industrial and retail synthetic lubricants for use primarily in industrial, automotive, marine, motorcycle and consumer applications. The Royal Purple facility’s processing capability includes blending and packaging on 10 production lines. In addition, the facility has approximately 30,500 barrels of storage capacity in 91 tanks and related loading and unloading facilities and utilities. The facility receives its base oil feedstocks and additive chemicals by truck under supply agreements or spot agreements with various suppliers.

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The Royal Purple facility is designed with the latest automated batch processing technology and design to maximize blending accuracy and flexibility to meet customer needs. The packaging operations utilize both in-house packaging equipment and outsourced packaging services for specific products.

Karns City and Dickinson Facilities and Other Processing Agreements

The Karns City facility, located on a 225-acre site in Karns City, Pennsylvania (“Karns City”), has aggregate base oil throughput capacity of 5,500 bpd and processes 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. In addition, the facility has approximately 817,000 barrels of storage capacity in 250 tanks and related loading and unloading facilities and utilities.

The Dickinson facility, located on a 28-acre site in Dickinson, Texas (“Dickinson”), has aggregate base oil throughput capacity of 1,300 bpd and processes 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 facilities each receive its base oil feedstocks by railcar and truck under supply agreements or spot purchases with various suppliers, the most significant of which is a long-term supply agreement with Phillips 66. Please read “— Crude Oil and Feedstock Supply” below for further discussion of the long-term supply agreement with Phillips 66.

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

	Combined Karns City, Dickinson and Other Facilities
	Year Ended December 31,
	2012	2011	2010
	(in bpd)
Feedstock throughput capacity (1)	11,300	11,300	11,300
Total feedstock runs (2) (3)	7,025	7,823	7,927
Total production (3)	7,021	7,803	7,917

(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. For more information regarding our purchase commitments related to these supply and/or processing agreements, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Commitments” for additional information.

(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.

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 and 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 by railcar 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 90 tanks having aggregate storage capacity of approximately 150,000 barrels, as well as blending equipment for producing engine oil additives and tackifiers.

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 from this terminal is sold to customers in the Upper Midwest region of the U.S. The terminal includes a tank farm with four tanks with aggregate storage capacity of approximately 166,000 barrels.

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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 from this terminal is sold to customers in the Upper Midwest region 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 refined fuel products from the Superior refinery by the Magellan pipeline and receives ethanol and biodiesel products by truck and includes seven tanks with aggregate storage capacity of approximately 200,000 barrels. 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 2,700 railcars leased from various lessors. This fleet of railcars enables us to receive and ship crude oil and distribute various specialty products and fuel 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 Texas, north Louisiana, North Dakota and Canada. Historically, the Shreveport refinery has received 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. However, the ExxonMobil pipeline has been shutdown since April 28, 2012, and as a result the Shreveport refinery received a portion of its crude oil requirements from other suppliers. For more information about the shutdown of the ExxonMobil pipeline, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 2012 Update.” The Superior refinery receives crude oil though the Enbridge Pipeline. The Superior refinery is adjacent to the first U.S. destination point for the Enbridge Pipeline after the U.S.-Canadian border, providing reliable access to crude oils from the Bakken shale oil formation in North Dakota and from western Canada. Further, in November 2012 we completed an expansion project at our Superior refinery, which enables the refinery to ship crude oil by railcar to our Shreveport refinery as well as third parties. The Montana refinery receives crude oil through the Front Range Pipeline via the Bow River Pipeline in Canada, providing reliable access to crude oil from western Canada. The San Antonio refinery receives crude oil through a pipeline connected to its Elmendorf terminal, providing reliable access to crude oil from the Eagle Ford Shale.

In 2012, subsidiaries of Plains supplied us with approximately 39.9% of our total crude oil supplies under term contracts and month-to-month evergreen crude oil supply contracts. In 2012, BP supplied us with approximately 25.1% of our total crude oil supplies under the BP Purchase Agreement. 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 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, please read the information provided under Note 5 “Commitments and Contingencies” 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 crude oil suppliers. For example, our contracts with Plains are currently month-to-month, terminable upon 90 days’ notice. In April 2012, we amended and restated the BP Purchase Agreement, which has an initial term of one year ending April 1, 2013, and 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 Co., L.P. (“Legacy Resources”) effective May 31, 2011, we have one remaining crude oil supply agreement with Legacy Resources 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,

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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 Phillips 66, with remaining terms ranging from one to five 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, waxes, packaged and synthetic specialty products, asphalt and other products, 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 a representative sample of the diversity of end-use applications for the products we produce:

Representative Sample of End Use Applications by Product¹ 

Lubricating Oils	Solvents	Waxes	Packaged and Synthetic Specialty Products	Asphalt & Other By-Products	Fuels & Fuel Related
15%	10%	1%	1%	16%	57%
• Hydraulic oils • Passenger car motor oils • Railroad engine oils • Cutting oils • Compressor oils • Metalworking fluids • Transformer 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 • Water treatment • Paint and coatings • Stains	• Paraffin waxes • FDA compliant products • Candles • Adhesives • Crayons • Floor care • PVC • Paint strippers • Skin & hair care • Timber treatment • Waterproofing • Pharmaceuticals • Cosmetics	• Refrigeration compressor oils • Commercial and military jet engine oil • Aviation hydraulic oils • High performance small engine fuels • Two cycle and four stroke engine oils • High performance passenger car oils • High performance industrial lubricants • High temperature chain lubricants • Charcoal lighter fluids • Engine treatment additives	• Roofing • Paving	• Gasoline • Diesel • Jet fuel • Marine diesel fuel • Biodiesel • Ethanol • Ethanol free fuels • 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, 2012 and includes the results of operations at our Missouri, TruSouth, Royal Purple and Montana operations commencing January 3, 2012, January 6, 2012, July 3, 2012 and October 1, 2012, respectively. Except for the listed fuel products and certain products sold by our Royal Purple and TruSouth facilities, 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.

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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 2012, approximately 36.6% of our specialty products sales were shipped in our fleet of approximately 2,700 leased railcars, approximately 61.7% of our specialty products sales were shipped in trucks owned and operated by several different third-party carriers and the remaining 1.7% were shipped via water transportation. For shipments outside of North America, which accounted for less than 10% of our consolidated sales in 2012, we ship via 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 U.S. Of the nearly 150 refineries currently in operation in the U.S., a large number of the refineries are fuel products producers; however, only a few compete with us in our local markets.

Gulf Coast Market (PADD 3)

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, located approximately 15 miles from the Shreveport refinery, as well as from our own Shreveport refinery terminal.

Gasoline, diesel and jet fuel from the Shreveport refinery is sold primarily into the Louisiana, Texas and Arkansas markets, and any excess volumes are sold 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 U.S. Department of Defense, 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 for approximately 3,900 bpd of jet fuel. This contract is effective until September 2013 and is bid annually.

Fuel products produced at our San Antonio refinery are sold locally in Texas. Additionally, the San Antonio refinery produces commercial and specialty jet fuel that can be marketed to the U.S. Department of Defense or sold locally as Jet-A fuel. We have a sales contract with the U.S. Department of Defense for approximately 550 bpd of jet fuel. This contract is effective until March 2014 with one year renewal increments through March 2017 at the option of the U.S. Department of Defense.

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.

Upper Midwest Market (PADD 2)

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 sells 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.

Northwest Market (PADD 4)

Fuel products produced at our Montana refinery can be sold locally and in Idaho and Canada via tank and railcar. Seasonally, the Montana refinery transports fuel products to terminals in Washington.

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Customers

Specialty Products.    We have a diverse customer base for our specialty products, with approximately 4,900 active accounts. Many of our customers are long-term customers who use our products in specialty applications, which after an approval process ranging from six months to two years. 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, 2012, 2011 and 2010.

Fuel Products.    We have a diverse customer base for our fuel products, with approximately 330 active accounts. Our diverse customer base includes wholesale distributors and retail chains. We are able to sell the majority of the fuel products we produce at the Shreveport refinery to the local markets of Louisiana, Texas and Arkansas. 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 through the Magellan pipeline. The majority of our fuel products produced at our Montana refinery are sold to local markets in Montana and Idaho as well as in Canada. Fuel products produced at our San Antonio refinery are sold to local markets in Texas. No single customer of our fuel products segment represented 10% or greater of consolidated sales in each of the three years ended December 31, 2012, 2011 and 2010.

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, Phillips 66, Petro-Canada, HollyFrontier 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, ExxonMobil Chemical and Phillips 66.

Packaged and Synthetic Specialty Products.    Our primary competitors in retail packaged and synthetic specialty products include ExxonMobil (Mobil 1), Ashland, Inc. (Valvoline) and BP Lubricants, USA (Castrol). Our primary competitors in industrial packaged and synthetic specialty products include ExxonMobil, Shell and Chevron.

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, Northern Tier Energy, Inc., ExxonMobil, Valero Energy Corporation, Phillips 66 and Cenex.

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.

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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 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.

On December 23, 2010, we entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering our Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations prior to December 31, 2010. Among other things we agreed to complete beneficial environmental programs and implement emissions reduction projects at our Shreveport, Cotton Valley and Princeton refineries, on an agreed-upon schedule. As of December 31, 2012, we have incurred approximately $4.2 million in expenditures and we estimate additional expenditures of approximately $2.0 million to $6.0 million of capital expenditures and expenditures related to additional personnel and environmental studies over the next three years as a result of the implementation of those requirements. 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.”

In connection with the Montana Acquisition which closed on October 1, 2012, we became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and Montana Department of Environmental Quality (“MDEQ”). The material obligations imposed by the Montana Consent Decree have been completed. Periodic reporting is the primary current obligation under the Montana Consent Decree. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previous Hazardous Waste Permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. We believe that all such contamination is subject to the indemnification of Montana Refining Company, Inc. by Holly Corporation (“Holly”) for pre-existing conditions. We believe we are indemnified by Holly under that certain asset purchase agreement between Holly and Connacher, and we became a party to such indemnification rights to through the share purchase agreement between us and Connacher. Holly is responsible for existing environmental conditions at the Montana refinery and has been reimbursing Connacher for remedial actions subject to the indemnification.

In connection with the Superior Acquisition, we became a party to an existing consent decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to our Superior refinery. Under the Superior 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 $3.0 million to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform required tasks under the Superior 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 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 federal 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

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additional costs, which could be substantial. During 2012 and 2011, we incurred approximately $2.4 million and $2.3 million, respectively, in costs related to installing process equipment pursuant to the fuel content regulations.

On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to our Superior refinery. This finding is in response to information provided to the EPA by us in response to an information request. The EPA alleges that the efficiency of the flares our Superior refinery is lower than regulatory requirements. We are contesting the allegations and attended an informal conference with the EPA held September 12, 2012. We do not believe that the resolution of these allegations will have a material adverse effect on our financial results or operations.

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 federal 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 federal 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 federal Clean Air Act and similar state and local laws.

The federal 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”). Additionally, the EPA promulgated the Mobile Source Air Toxics II (“MSAT II”) standards that require reduced benzene levels in refined products. The Shreveport, Superior, Montana and San Antonio 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 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. We cannot currently predict the future prices of RINs Credits or waiver credits, but the costs to obtain the necessary number of RINs Credits and waiver credits could be material.

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 RFS II, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. While the minimum volume of renewable fuels that must be blended with refined petroleum fuels is currently set, existing laws and regulations could change and require increases in such volume. Any such increase in volume displaces volume of our Shreveport, Superior, Montana and San Antonio refineries’ product pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions. 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

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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, establishing Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit program requiring reviews for GHG emissions from certain large stationary sources. 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, the EPA entered a settlement agreement with environmental groups requiring the agency to propose by December 10, 2011 GHG New Source Performance Standards (“NPNS”) for refineries and to finalize these rules by November 15, 2012. To date, the EPA has not completed those rulemakings and we do not know when they will be completed. 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 hazardous and non-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 non-hazardous 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.

In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on June 1, 2012, the EPA issued final amendments to the NSPS for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. We are currently evaluating the effect that the NSPS rule may have on our operations.

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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 $0.4 million and $0.3 million in 2012 and 2011, 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 federal 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 federal 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 to 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, 2012, we have incurred approximately $0.7 million of capital expenditures and expect to incur between $1.0 million and $4.0 million of capital expenditures during 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 the 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.

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In addition, we are indemnified by Murphy Oil for specified environmental liabilities arising from the operations of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior 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.

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.” We believe that all properties are suitable for their intended purpose, are being efficiently utilized and provide adequate capacity to meet demand for the next several years.

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Property	Business Segments	Acres	Owned / Leased	Location
Shreveport refinery	Fuels and Specialty	240	Owned	Shreveport, Louisiana
Superior refinery and terminal	Fuels and Specialty	675	Owned	Superior, Wisconsin
Montana refinery	Fuels and Specialty	86	Owned	Great Falls, Montana
San Antonio refinery	Fuels	32	Owned	San Antonio, Texas
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 terminal	Specialty	18	Owned	Rhinelander, Wisconsin
Crookston terminal	Specialty	19	Owned	Crookston, Minnesota
Missouri facility	Specialty	22	Owned	Louisiana, Missouri
TruSouth facility	Specialty	10	Leased	Shreveport, Louisiana
Royal Purple facility	Specialty	23	Owned	Porter, Texas
Elmendorf terminal	Fuels	8	Owned	Elmendorf, Texas
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, railcars, equipment, land and precious metals.

Office Facilities

In addition to our refineries and terminals discussed above, we occupy the following square feet of office space, all of which are under leases:

Location	Square Feet
Indianapolis, Indiana	36,566
El Dorado, Arkansas	1,600
Louisiana, Missouri	4,600
Kingwood, Texas	2,466
San Antonio, Texas	41,000

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 28, 2013, our general partner employs approximately 1,250 people who provide direct support to our operations. Of these employees, approximately 580 are covered by collective bargaining agreements. Employees at the following locations are covered by the following separate collective bargaining agreements:

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Facility/ Refinery	Union	Expiration Date
Superior	International Union of Operating Engineers	June 30, 2017
Cotton Valley	International Union of Operating Engineers	March 31, 2013
Princeton	International Union of Operating Engineers	October 31, 2014
Dickinson	International Union of Operating Engineers	March 31, 2013
Shreveport	United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union	April 30, 2013
Missouri	United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union	April 30, 2014
Karns City	United Steel, Paper and Forestry, Rubber, Manufacturing, Energy Allied-Industrial and Service Workers International Union	January 31, 2015
Montana	United Steel, Paper and Forestry, Rubber, Manufacturing, Energy Allied-Industrial and Service Workers International Union	January 31, 2015

None of the employees at the San Antonio refinery, TruSouth facility, Royal Purple facility or at the Burnham, Rhinelander, Crookston, Duluth or Elmendorf 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.

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. We make available, free of charge on our website, our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These documents are located on our website at http://www.calumetspecialty.com — by selecting the “Investor Relations” link and then selecting the “SEC Filings” link. We also make available, free of charge on our website, our Charters for the Audit, Compensation and Conflicts Committees, Related Party Transactions Policy and Code of Business Conduct and Ethics. These documents are located on our website at http://www.calumetspecialty.com — by selecting the “Investor Relations” link and then selecting the “Corporate Governance” link.

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.

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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:

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

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

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

• the marketing of alternative and competing products;

• the extent of government regulation;

• results of our hedging activities; and

• overall economic and local market conditions.

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

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

• our debt service requirements;

• fluctuations in our working capital needs;

• our ability to borrow funds and access capital markets;

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

• 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 $40.47 per barrel to a low of $14.42 per barrel during 2012 and averaged $26.34 per barrel during 2012 compared to an average of $25.41 in 2011 and $9.90 in 2010.

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 quickly enough 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

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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. Historically, we have utilized 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, excluding our crude oil basis swaps, 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, Western Canadian Select 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 2020 Notes (as defined under Note 6 “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report) 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:

• sell assets, including equity interests in our subsidiaries;

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

• incur or guarantee additional indebtedness or issue preferred units;

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• create or incur certain liens;

• make certain acquisitions and investments;

• redeem or repay other debt or make other restricted payments;

• enter into transactions with affiliates;

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

• create unrestricted subsidiaries;

• enter into sale and leaseback transactions;

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

• engage in certain business activities.

Our revolving credit facility also contains a springing financial covenant which provides that, if availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) the revolving credit agreement commitments then in effect and (ii) $46.4 million, then we 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.

Our existing indebtedness imposes, and any future indebtedness may impose, a number of covenants on us regarding collateral maintenance and insurance maintenance. As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with the covenants and restrictions contained in 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. Among other things, in the event of any default on our indebtedness, our debt holders and lenders:

• will not be required to lend any additional amounts to us;

• could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

• could elect to require that all obligations accrue interest at the default rate, if such rate has not already been imposed;

• may have the ability to require us to apply all of our available cash to repay these borrowings;

• may prevent us from making debt service payments under our other agreements, any of which could result in an event of default under our other financing arrangements; or

• in the case of our revolving credit facility, foreclose on the collateral pledged pursuant to the terms of the revolving credit facility.

If an acceleration of our debt occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if new financing were available, it may be on terms that are less attractive to us than our then existing indebtedness or it may not be on terms that are acceptable to us.

If our existing indebtedness were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are secured by a first priority lien on our cash, accounts receivable, inventory and certain other personal property and our obligations under our master derivative contracts are secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements), and if we are unable to repay our indebtedness under the revolving credit facility or master derivative contracts, the lenders under our revolving credit facility and the counterparties to our master derivative contracts 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,” “—Short Term Liquidity,” “—Long-Term Financing,” and “—Master Derivative Contracts” for additional information regarding our long-term debt.

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

We had approximately $880.5 million of outstanding indebtedness as of December 31, 2012 and availability for borrowings of $355.1 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:

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

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

• we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payments of our debt obligations, including the 2019 Notes and 2020 Notes; and

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

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions 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 effect 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 or other feedstocks for our facilities, lease certain precious metals for use in our refinery operations and enter into derivative instruments 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.

A failure in our information technology infrastructure or applications could negatively affect our business.

We have begun implementing a new enterprise resource planning (“ERP”), system to further enhance operating efficiencies and provide more effective management of our business operations. The new ERP system is being deployed for use throughout our company in a number of “go live” phases, the first of which occurred during the first quarter of 2013 with company-wide deployment expected to be completed by the end of 2013. Implementing a new ERP system is costly and involves risks inherent in the conversion to a new computer system, including loss of information, disruption to our normal operations, changes in accounting procedures and internal control over financial reporting, as well as problems achieving

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accuracy in the conversion of electronic data. Failure to properly or adequately address these issues could result in increased costs, the diversion of management’s and employees’ attention and resources and could materially adversely affect our operating results, internal controls over financial reporting and ability to manage our business effectively. While the ERP system is intended to further improve and enhance our information systems, large scale implementation of a new information system exposes us to the risks of starting up the new system and integrating that system with our existing systems and processes, including possible disruption of our financial reporting, which could lead to a failure to make required filings under the federal securities laws on a timely basis.

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 facilities 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 primarily in Texas, north Louisiana, North Dakota and Canada. In 2012, subsidiaries of Plains supplied us with approximately 39.9% of our total crude oil supplies under term contracts and month-to-month evergreen crude oil supply contracts. In 2012, BP supplied us with approximately 25.1% of our total crude oil supplies under the BP Purchase Agreement. In addition, the Superior refinery receives up to 10,000 bpd of crude oil under the Murphy Crude Oil Supply Agreement. Each of our facilities 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 was amended and restated in April 2012 and has an initial term of one year ending April 1, 2013, will automatically renew for successive one-year terms unless terminated by either party upon 90 days’ notice.

We purchase all of the crude oil supply 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 sales, 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 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. Our Montana refinery receives crude oil through the Front Range pipeline system via the Bow River Pipeline in Canada. 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, earthquakes or hurricanes, government regulation, terrorism or other third-party 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. In addition, ExxonMobil shut down this pipeline on April 28, 2012 after a leak was discovered, and the portion of this pipeline serving our Shreveport refinery remains shutdown. Also, on June 20, 2012, excessive flooding caused our Superior refinery to reduce its run rate to approximately half its usual throughput for one day and shut down the portion of the Magellan pipeline that connects our Superior refinery to our Duluth terminal. The unavailability of any of these third-party pipelines for the transportation of crude oil or our refined fuel products, because of acts of God, accidents, earthquakes or hurricanes,

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government regulation, terrorism or other third-party events, could lead to disputes or litigation with certain of our suppliers or a decline in our sales, net income and cash available for distributions to our unitholders and payments of our debt obligations.

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 $1.91 and $3.90 per million British thermal unit, or MMBtu, in 2012 and between $2.99 and $4.85 per MMBtu in 2011. 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 16.2% and 19.6% of our total operating expenses included in cost of sales for the years ended December 31, 2012 and 2011, 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 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, pipeline rupture or spill, 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 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. For example, we are currently investigating and remediating, in some cases pursuant to government order, soil and groundwater contamination at our Montana refinery arising from a predecessor operators’ handling of petroleum hydrocarbons and wastes. Our costs in pursuing these investigatory and remedial activities are subject to reimbursement under a contractual indemnification we received from our predecessor operator in the share purchase agreement transferring ownership of this refinery. We expect that our costs in completing these investigatory and remedial activities will be reimbursed under the contractual indemnification. Joint and several strict liability may be incurred in connection with releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities. Neither the owners of our general partner nor their

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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 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, terminals, 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 or operators of our facilities. Numerous governmental authorities, such as the EPA, OSHA and state agencies, such as the LDEQ and the 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 or corrective actions, 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. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on September 12, 2012, the EPA issued final amendments to the NSPS for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. We are currently evaluating the effect that the NSPS rule may have on our refinery operations. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced but we may incur increased operating costs and capital expenditures to comply, which could be material. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, our results of operations and cash flows could suffer. 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.

Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our results of operations and financial condition, and our ability to make distributions to our unitholders.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has issued Renewable Fuels Standards (“RFS”) implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under RFS, the volume of renewable fuels that obligate refineries like the Shreveport, Superior, Montana and San Antonio refineries, for example, to blend into their finished petroleum fuels increases annually over time until 2022. To the extent we exceed the minimum requirements of MSAT II standards in our operations, we have the option to sell renewable identification number credits (“RINs Credits”) and have the option to purchase RINs Credits if we operate the refineries in a manner that does not meet these minimum requirements. We cannot currently predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs Credits and waiver credits could be material. On October 13, 2010, the EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007, and on January 21, 2011, EPA extended the maximum allowable ethanol content of 15% to apply to cars and light trucks manufactured since 2001. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Moreover, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our Shreveport, Superior, Montana and San Antonio refineries’ fuel products pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions.

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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 the Superior Acquisition, Missouri Acquisition, TruSouth Acquisition, Royal Purple Acquisition, Montana Acquisition and San Antonio Acquisition, our most recent acquisitions, involve potential risks, including, among other things:

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

• a significant increase in our indebtedness and working capital requirements;

• an inability to timely and effectively integrate the operations of recently acquired businesses or assets, particularly those in new geographic areas or in new lines of business;

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

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

• customer or key employee losses at the acquired businesses; and

• 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

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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 our unitholders and payments of our debt obligations could be reduced.

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:

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

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

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

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

• competitor actions; and

• availability of raw materials.

We 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 Shreveport, Superior, Montana, Princeton, Cotton Valley, Karns City, Dickinson and Missouri facilities are employed under collective bargaining agreements that expire in April 2013, June 2017, January 2015, October 2014, March 2013, January 2015, March 2013 and April 2014, 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

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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 Louisiana, Wisconsin, Montana and Texas. 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 refined products.

In 2009, the EPA adopted rules for establishing a reporting program for emissions of carbon dioxide, methane and other GHG from specified large GHG emissions sources in the U.S., including refineries, and subsequently expanded the scope of this rule to include the reporting of GHG emissions from onshore oil and natural gas processing, transmission, storage and distribution facilities. Operators of covered sources in the U.S. must annually monitor and report these GHG emissions to EPA and certain state agencies. Our refineries and certain of our other facilities are subject to the federal GHG reporting requirements because of combustion GHG emissions and potential fugitive emissions that exceed reporting thresholds. While our compliance with this reporting program has increased our operating costs, we presently do not believe that these increased costs have a material adverse effect on our results of operations.

Following its determination in December 2009 that emissions of GHG present a danger to public health and the environment, the EPA promulgated regulations in 2010 establishing Title V and PSD, permitting requirements for large sources of GHG that apply to certain of our facilities, including our refineries, which are potential major sources of GHG emissions. In the absence of any control requirements for GHG for our facilities that would need to be incorporated into existing Title V permits, we believe the impact of these permitting requirements on our facilities will not be material. However, we may be required to install “best available control technology” to limit emissions of GHG from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHG. Best available control technology is determined on a case-by-case basis by the relevant permitting agency to date, whether EPA or state. PSD permits with GHG emissions limitations have generally required efficient combustion requirements on sources that burn large volumes of fossil fuels rather than post-combustion GHG capture requirements. If the EPA imposes efficient combustion requirements, we do not anticipate that they will have a material adverse effect on the cost of our operations. Moreover, as part of a settlement in December 2010 with certain environmental groups derived out of legal challenges seeking judicial review of an EPA final rule on standards of performance for petroleum refineries, the EPA agreed to propose new source performance standards for GHG emissions from petroleum refineries by December 10, 2011. While no such standards have been proposed by the EPA to date, we expect the agency to pursue this rulemaking in 2013. Depending on the nature of the requirements imposed by the EPA as part of this rulemaking, we could encounter increased operating costs and capital expenditures that could be significant.

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHG, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions. Two of the more significant non-federal GHG programs are the Regional Greenhouse Gas Initiative, or “RGGI,” and California’s cap-and-trade program. RGGI, which includes a number of states in the northeastern U.S., implemented a cap-and-trade program in 2009. At present, this program only applies to utility power plants. None of our facilities are affected by RGGI. California’s cap-and-trade program will enter into force in January 2013 and will impose

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compliance obligations upon certain industrial GHG emitters. At present, California is evaluating a formal linkage with Quebec’s cap-and-trade program under the WCI. We do not operate in California and do not expect that our operations will be impacted by the implementation of California’s cap-and-trade program.

If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform will include a carbon tax. A carbon tax could impose additional direct costs on our operations and reduce demand for refined products. The ultimate impact of any carbon tax on our operations would further depend upon whether a carbon tax supplanted the other federal GHG regulations to which we are currently subject or is administered as an additional program.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. 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, droughts, and floods and other climate events that could have an adverse effect on our assets and operations.

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 enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Act. 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. The position limits rule was vacated by the United States District Court for the District of Colombia in September 2012 although the CFTC recently has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to predict when this will be accomplished and when the compliance date for those regulations will commence. The Act also may 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 and the schedule for effectiveness of those regulations is uncertain at this time. The Act also may 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 Act 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 Act 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 Act 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 Act 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.

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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, 2012, 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, 2020 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, the indentures governing our 2019 Notes and 2020 Notes and our Collateral Trust Agreement. In addition, an event of default under our revolving credit agreement would likely constitute an event of default under our master derivatives contracts and a crude oil purchase agreement with BP (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 2020 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 a first priority lien on our cash, 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, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements). 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, the indentures governing our 2019 Notes and 2020 Notes or our Collateral Trust Agreement.

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

At February 28, 2013, the families of our chairman, chief executive officer and vice chairman, The Heritage Group and certain of their affiliates own a 28.7% limited partner interest in us and own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to other unitholders’ detriment.

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At February 28, 2013, the families of our chairman, chief executive officer and vice chairman, the Heritage Group, and certain of their affiliates own a 28.7% 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:

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

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

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

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

• our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a capital expenditure for acquisitions or capital improvements, which does not. This determination can affect the amount of cash that is available for distribution to our unitholders and payments of our debt obligations;

• 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

• 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 U.S. 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:

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

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

• Generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms

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no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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

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

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

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

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

The unitholders are unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 ²/3% of all outstanding units voting together as a single class is required to remove the general partner. At February 28, 2013, the owners of our general partner and certain of their affiliates own 28.7% 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

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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, the indentures governing our 2019 Notes and 2020 Notes 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 28, 2013, our general partner and its affiliates own approximately 28.7% 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

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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 U.S. 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, were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

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.

Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

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If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the expectation for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

Unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from that income.

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

We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the 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 currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination 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.

Tax gain or loss on the disposition of our 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 realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income result in a decrease in such unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to our unitholders if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation and deductions and certain other items. 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.

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

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes, 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. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

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

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.

We have historically conducted portions of our operations through a subsidiary that is treated as a corporation for U.S. federal income tax purposes, and is therefore subject to corporate-level income taxes and may conduct additional activities in subsidiaries treated as a corporation in the future.

We have historically conducted portions of our operations in which we market finished petroleum products to certain customers through a subsidiary that was 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 will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

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 our 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

42

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.

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

Because there is no tax concept of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We own assets and conduct business in 44 states. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in any state in which we now or may conduct business in the future. Further, they may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is the responsibility of our unitholders to file all U.S. federal, foreign, state and local tax returns.

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 5 “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.

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PART II

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

Market Information

Our common units are quoted and traded on the NASDAQ Global 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.

	Low		High		Cash Distribution per Unit (1)
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
2012:
First quarter	$	20.00	$	27.50	$	0.56
Second quarter	$	20.76	$	27.74	$	0.59
Third quarter	$	24.01	$	32.02	$	0.62
Fourth quarter	$	27.53	$	33.96	$	0.65

(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 28, 2013, there were approximately 30 unitholders of record of our common units. The actual number of unitholders is greater than the number of holders of record. As of February 28, 2013, there were 63,279,778 common units outstanding. The last reported sale price of our common units by NASDAQ on February 28, 2013 was $38.36.

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; and

• 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

44

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 revolving credit agreement and the indentures governing our 2019 and 2020 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, 2013, we paid a quarterly cash distribution of $0.65 per unit on all outstanding units totaling approximately $44.5 million for the quarter ended December 31, 2012 to all unitholders of record as of the close of business on February 4, 2013.

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 1,174,077 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 earned incentive distribution rights of approximately $5.4 million and $0.3 million during the years ended December 31, 2012 and December 31, 2011, respectively.

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, 2012, includes the operations acquired as part of the acquisitions of Penreco, Superior, Missouri, TruSouth, Royal Purple and Montana from their respective dates of acquisition, January 3, 2008, September 30, 2011, January 3, 2012, January 6, 2012, July 3, 2012 and October 1, 2012.

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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 U.S. generally accepted accounting principles (“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,
	2012			2011			2010			2009			2008
	(In thousands, except unit, per unit and operating data)
Summary of Operations Data:
Sales	$	4,657,282		$	3,134,923		$	2,190,752		$	1,846,600		$	2,488,994
Cost of sales	4,144,105			2,860,793			1,992,003			1,673,498			2,235,111
Gross profit	513,177			274,130			198,749			173,102			253,883
Operating costs and expenses:
Selling	41,556			12,237			8,436			9,389			10,986
General and administrative	60,904			38,599			26,788			23,181			23,281
Transportation	107,900			94,187			85,471			67,967			84,702
Taxes other than income taxes	9,073			5,661			4,601			3,839			4,598
Insurance recoveries	—			(8,698		)	—			—			—
Other	7,816			6,852			1,963			1,366			1,576
Operating income	285,928			125,292			71,490			67,360			128,740
Other income (expense):
Interest expense	(85,573		)	(48,747		)	(30,497		)	(33,573		)	(33,938		)
Debt extinguishment costs	—			(15,130		)	—			—			(898		)
Realized gain (loss) on derivative instruments	9,452			(7,909		)	(7,704		)	8,342			(58,833		)
Unrealized gain (loss) on derivative instruments	(3,787		)	(10,383		)	(15,843		)	23,736			3,454
Gain on sale of mineral rights	—			—			—			—			5,770
Other	470			842			(147		)	(3,929		)	399
Total other expense	(79,438		)	(81,327		)	(54,191		)	(5,424		)	(84,046		)
Income before income taxes	206,490			43,965			17,299			61,936			44,694
Income tax expense	753			929			598			151			257
Net income	$	205,737		$	43,036		$	16,701		$	61,785		$	44,437

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	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands, except unit, per unit and operating data)
Weighted average limited partner units outstanding:
Basic	55,559,000			42,599,000			35,334,720			32,372,000			32,232,000
Diluted	55,677,000			42,644,000			35,351,020			32,372,000			32,232,000
Limited partners’ interest basic net income per unit	$	3.51		$	0.98		$	0.46		$	1.87		$	1.35
Limited partners’ interest diluted net income per unit	$	3.50		$	0.98		$	0.46		$	1.87		$	1.35
Cash distributions declared per limited partner unit	$	2.30		$	1.94		$	1.83		$	1.80		$	1.98
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	986,875		$	842,101		$	612,433		$	629,275		$	659,684
Total assets	2,253,045			1,732,058			1,016,672			1,031,856			1,081,062
Accounts payable	333,416			302,826			171,565			106,926			90,177
Long-term debt	863,501			587,090			369,275			401,058			465,091
Total partners’ capital	889,793			728,900			398,279			485,347			473,212
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	380,108		$	63,778		$	134,143		$	100,854		$	130,341
Investing activities	(624,234		)	(460,424		)	(34,759		)	(22,714		)	(480,461		)
Financing activities	276,236			396,673			(99,396		)	(78,139		)	350,133
Other Financial Data:
EBITDA	$	383,732		$	170,851		$	108,083		$	157,244		$	135,396
Adjusted EBITDA	404,610			211,020			138,462			151,117			126,534
Distributable Cash Flow	281,125			127,158			76,202			98,667			78,153
Operating Data (bpd):
Total sales volume (1)	97,789			66,134			55,668			57,086			56,232
Total feedstock runs (2)	97,600			69,295			55,957			60,081			56,243
Total facility production (3)	96,172			70,909			57,314			58,792			55,330

(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 includes 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 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. 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.

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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 and analysts 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 and 2020 Notes (as defined in this Annual Report). We are required to report Consolidated Cash Flow to the holders of our 2019 Notes and 2020 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 (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

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	Year Ended December 31,
	2012			2011		2010		2009			2008
	(In thousands)
Reconciliation of Net income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income	$	205,737		$	43,036	$	16,701	$	61,785		$	44,437
Add:
Interest expense	85,573			48,747		30,497		33,573			33,938
Debt extinguishment costs	—			15,130		—		—			898
Depreciation and amortization	91,669			63,009		60,287		61,735			55,866
Income tax expense	753			929		598		151			257
EBITDA	$	383,732		$	170,851	$	108,083	$	157,244		$	135,396
Add:
Unrealized (gain) loss on derivatives	$	3,787		$	10,383	$	15,843	$	(23,736	)	$	(3,454	)
Realized gain (loss) on derivatives, not included in net income	(5,033		)	10,996		2,990		9,278			(8,055		)
Amortization of turnaround costs	13,356			11,384		10,006		7,256			2,468
Non-cash equity based compensation and other non-cash items	8,768			7,406		1,540		1,075			179
Adjusted EBITDA	$	404,610		$	211,020	$	138,462	$	151,117		$	126,534
Less:
Replacement capital expenditures (1)	28,341			23,862		24,345		15,508			6,304
Cash interest expense (2)	79,492			45,019		26,633		29,901			30,543
Turnaround costs	14,899			14,052		10,684		6,890			11,277
Income tax expense	753			929		598		151			257
Distributable Cash Flow	$	281,125		$	127,158	$	76,202	$	98,667		$	78,153

(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.

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	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash provided by operating activities:
Distributable Cash Flow	$	281,125		$	127,158		$	76,202		$	98,667		$	78,153
Add:
Replacement capital expenditures (1)	28,341			23,862			24,345			15,508			6,304
Cash interest expense (2)	79,492			45,019			26,633			29,901			30,543
Turnaround costs	14,899			14,052			10,684			6,890			11,277
Income tax expense	753			929			598			151			257
Adjusted EBITDA	$	404,610		$	211,020		$	138,462		$	151,117		$	126,534
Less:
Unrealized (gain) loss on derivative instruments	$	3,787		$	10,383		$	15,843		$	(23,736	)	$	(3,454	)
Realized gain (loss) on derivatives, not included in net income	(5,033		)	10,996			2,990			9,278			(8,055		)
Amortization of turnaround costs	13,356			11,384			10,006			7,256			2,468
Non-cash equity based compensation and other non-cash items	8,768			7,406			1,540			1,075			179
EBITDA	$	383,732		$	170,851		$	108,083		$	157,244		$	135,396
Add:
Unrealized (gain) loss on derivative instruments	3,787			10,383			15,843			(23,736		)	(3,454		)
Cash interest expense (2)	(79,492		)	(45,019		)	(26,633		)	(29,901		)	(30,543		)
Non-cash equity based compensation	6,512			4,895			1,540			1,075			179
Amortization of turnaround costs	13,356			11,384			10,006			7,256			2,468
Income tax expense	(753		)	(929		)	(598		)	(151		)	(257		)
Provision for doubtful accounts	22			380			74			(916		)	1,448
Debt extinguishment costs	—			(729		)	—			—			—
Changes in assets and liabilities:
Accounts receivable	34,609			(54,484		)	(35,267		)	(12,296		)	45,042
Inventories	17,898			(167,028		)	(9,860		)	(18,726		)	55,532
Other current assets	15,828			(425		)	4,669			(2,848		)	1,834
Turnaround costs	(14,899		)	(14,052		)	(10,684		)	(6,890		)	(11,277		)
Derivative activity	(5,033		)	11,742			2,990			8,531			41,757
Other noncurrent assets	(4,007		)	(426		)	(2,006		)	1			1,066
Accounts payable	11,859			131,261			64,639			16,579			(106,451		)
Accrued interest payable	13,026			7,350			100			(628		)	3,315
Accrued income taxes payable	(16,089		)	366			4			(195		)	(58		)
Other current liabilities	3,833			(2,439		)	11,271			587			(1,226		)
Other, including changes in non-current liabilities	(4,081		)	697			(28		)	5,868			(4,430		)
Net cash provided by operating activities	$	380,108		$	63,778		$	134,143		$	100,854		$	130,341

(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.

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

The historical consolidated financial statements included in this Annual Report 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, 2012, 2011 and 2010. 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 and fuel products in North America. We are headquartered in Indianapolis, Indiana and own facilities primarily located in Louisiana, Wisconsin, Montana, Texas 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, waxes and asphalt. 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. We also blend and market specialty products through our Royal Purple brand. 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.

2012 Update

For the years ended December 31, 2012 and 2011, 39.1% and 46.8%, respectively, of our sales volume and 60.1% and 94.4%, respectively, of our gross profit was generated from our specialty products segment while, for the same periods, 60.9% and 53.2%, respectively, of our sales volume and approximately 39.9% and 5.6%, respectively, of our gross profit was generated from our fuel products segment.

Generally, we continued to see strength in product demand in our specialty products segment in 2012, noting a slight softening in demand toward the end of 2012 due to some seasonality of product demand in the segment. Overall, we achieved a 23.6% increase in barrels of specialty products sold, including the impact of incremental sales from the Superior, Royal Purple, Montana, TruSouth and Missouri Acquisitions. Our specialty products segment generated a gross profit margin of 13.8% in 2012, as compared to a gross profit margin of 14.3% in 2011, as specialty products sales pricing slightly lagged fluctuations in crude oil prices.

Higher sales and production volume in our fuel products segment during 2012 allowed us to take advantage of higher market crack spreads. We achieved a 69.2% increase in barrels of fuel products sold in 2012 compared to 2011, driven primarily by incremental sales from the Superior and Montana refineries. Negatively impacting production levels during the second half of 2012 were reduced run rates at our Shreveport refinery resulting from the April 28, 2012 shutdown by ExxonMobil of a crude oil pipeline serving the refinery for a portion of its crude oil requirements. During the fourth quarter of 2012, the Shreveport refinery began receiving Bakken crude oil by rail from the Superior refinery to supplement the loss of crude oil related to the ExxonMobil pipeline shutdown and to take advantage of lower priced Bakken crude oil. The fuel products segment generated a gross profit margin of 8.4% in 2012 compared to 1.2% in 2011 despite the recognition of increased realized derivative losses of $55.2 million during 2012 compared to 2011 due to the strength of settled market crack spreads compared to our hedged crack spreads. As of December 31, 2012, we have entered 17.8 million barrels of crack spread derivatives for calendar years 2013 through 2015 at an average of $26.74 per barrel.

During 2012, the Western Canadian Select (“WCS”) heavy crude oil differential to NYMEX WTI averaged $21.98 per barrel below NYMEX WTI, an increase of $6.34 from 2011. During 2012, the Bakken light crude oil differential to NYMEX WTI averaged $5.74 per barrel below NYMEX WTI, an increase of $8.26 from 2011. Both the WCS and Bakken differentials to NYMEX WTI create an unhedged crude oil cost advantage for our Superior refinery.  During 2012, the Bow River heavy crude oil differential to NYMEX WTI averaged $19.88 per barrel below NYMEX WTI, an increase of $3.68 from 2011, creating an unhedged crude oil cost advantage for our Montana refinery. On the sales side, while Group 3 fuel product differentials to U.S. Gulf Coast were not quite as strong as in 2011, we saw continued increases throughout the second half of 2012 with the Group 3 diesel pricing differential to U.S. Gulf Coast diesel, for example, widening $0.30 per barrel compared to the average differential in the third quarter of 2012 and hitting a high of $16.32 per barrel in October 2012. As we currently use U.S. Gulf Coast fuel products swaps to hedge a portion of our Group 3 fuel products selling price exposure, we continue to benefit from this Group 3 pricing strength relative to U.S. Gulf Coast pricing. 

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Our 2012 total legacy facility production decreased by 1.9% year over year, excluding the impact of the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions, due primarily to decreased run rates at our Superior, Karns City and Dickinson facilities.

We remained active in the capital markets in 2012 by completing a public offering of common units in May 2012 which generated net proceeds (including our general partner’s contribution) of $149.7 million and completing in June 2012 a private placement offering of an aggregate of $275.0 million in senior unsecured notes due 2020 (“June 2012 Notes Offering”), which generated net proceeds of $262.6 million. We used the net proceeds from the June 2012 Notes Offering to fund a portion of the Royal Purple Acquisition.

We generated $380.1 million in cash flow from operations during 2012. We generated distributable cash flow (as defined in Part II, Item 6 “Non-GAAP Financial Measures”) of $281.1 million in 2012, an increase of $154.0 million over 2011 and paid distributions of $132.4 million to our unitholders in 2012, an increase of $49.7 million over 2011. 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) service our debt obligations, (iii) pay quarterly distributions to our unitholders and (iv) provide funding for general partnership purposes.

Acquisitions

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) and a manufacturing facility located in Louisiana, Missouri from Hercules Incorporated, a subsidiary of Ashland, Inc., for aggregate consideration of approximately $19.6 million. We believe the Missouri Acquisition provides greater diversity to our specialty products segment. The acquisition was financed with borrowings under our revolving credit facility and cash on hand.

TruSouth Oil

On January 6, 2012, we completed the acquisition of TruSouth Oil, LLC, a specialty petroleum packaging and distribution company located in Shreveport, Louisiana for aggregate consideration of approximately $26.8 million, which was financed with borrowings under our revolving credit facility. We believe the TruSouth Acquisition provides greater diversity to our specialty products segment. Please read Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence — TruSouth Acquisition” for further discussion of our acquisition of TruSouth.

Royal Purple

On July 3, 2012, we completed the acquisition of Royal Purple, Inc., a Texas corporation which was converted into a Delaware limited liability company at closing, for aggregate consideration of approximately $331.2 million, net of cash acquired. Royal Purple is a leading independent formulator and marketer of premium industrial and consumer synthetic lubricants to a diverse customer base across several large markets including oil and gas, chemicals and refining, power generation, manufacturing and transportation, food and drug manufacturing and automotive aftermarket. The Royal Purple Acquisition was financed with net proceeds of $262.6 million from our June 2012 Notes Offering and cash on hand. We believe the Royal Purple Acquisition increases our position in the specialty lubricants markets, expands our geographic reach, increases our asset diversity and enhances our specialty products segment.

Montana

On October 1, 2012, we completed the acquisition from Connacher of all the shares of common stock of Montana Refining Company, Inc., which was converted into a Delaware limited liability company, Calumet Montana Refining, LLC, at closing, and an insignificant affiliated company for aggregate consideration of approximately $191.6 million, net of cash acquired, including an estimated $27.6 million of income taxes due to the conversion to a Delaware limited liability company and excluding certain purchase price adjustments. Montana produces gasoline, diesel, jet fuel and asphalt which are marketed primarily into local markets in Washington, Montana, Idaho and Alberta, Canada. The Montana Acquisition was funded primarily with cash on hand with the balance through borrowings under our revolving credit facility. We believe the Montana Acquisition further diversifies our crude oil feedstock slate, operating asset base and geographical presence.

San Antonio

On January 2, 2013, we completed the acquisition of the San Antonio, Texas refinery, together with the associated crude oil pipeline, crude oil terminal, other operating and logistics assets and inventories of NuStar Refining, LLC and NuStar Logistics, L.P., both wholly owned subsidiaries of NuStar Energy L.P., for aggregate consideration of approximately $115.7 million, including approximately $15.0 million for inventories acquired at closing, subject to certain post-closing adjustments.

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San Antonio produces jet fuel, diesel, other fuel products and specialty solvents. The San Antonio Acquisition was funded primarily with borrowings under our revolving credit facility with the balance through cash on hand. We believe the San Antonio Acquisition further diversifies our crude oil feedstock slate, operating asset base and geographical presence.

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 products 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 derivative instruments 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, 2012, we have hedged refining margins, or crack spreads, on approximately 17.8 million barrels of fuel products through December 2015 at an average refining margin of $26.74 per barrel with average refining margins ranging from a low of $23.77 per barrel in the first quarter of 2013 to a high of $29.55 per barrel in the fourth quarter of 2013. Please refer to Note 7 under Item 8 “Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” for detailed information regarding our derivative instruments and our commodity price.

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 operating 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 or feedstocks we, or third parties, process, 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, Group 3, PADD 4 Billings, Montana or 3/2/1 and 2/1/1 market crack spreads 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, Superior, Wisconsin and Great Falls, Montana vicinities as compared to U.S. Gulf Coast, Group 3 and PADD 4 Billings, Montana postings, respectively.

In addition to the foregoing measures, we also monitor our selling and general and administrative expenditures.

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Results of Operations

The following table sets forth information about our combined operations. Facility production volume differs from sales volume due to changes in inventories and the sale of purchased fuel product blendstocks such as ethanol and biodiesel in our fuel products segment. The tables include the results of operations at our Superior refinery commencing October 1, 2011, Missouri facility commencing January 3, 2012, TruSouth facility commencing January 6, 2012, Royal Purple facility commencing July 3, 2012 and Montana refinery commencing October 1, 2012.

	Year Ended December 31,
	2012	2011	2010
	(In bpd)
Total sales volume (1)	97,789	66,134	55,668
Total feedstock runs (2)	97,600	69,295	55,957
Facility production: (3)
Specialty products:
Lubricating oils	14,524	14,427	13,697
Solvents	9,332	10,508	9,347
Waxes	1,280	1,269	1,220
Packaged and synthetic specialty products (4)	1,351	—	—
Fuels	669	556	1,050
Asphalt and other by-products	14,219	10,090	6,907
Total specialty products	41,375	36,850	32,221
Fuel products:
Gasoline	24,394	13,409	8,754
Diesel	22,438	14,721	10,800
Jet fuel	4,325	4,520	5,004
Heavy fuel oils and other	3,640	1,409	535
Total fuel products	54,797	34,059	25,093
Total facility production (3)	96,172	70,909	57,314

(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 includes 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 2012 compared to 2011 is due primarily to incremental sales of fuel products, asphalt and packaged and synthetic specialty products subsequent to the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions. 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 2012 compared to 2011 is due primarily to incremental feedstock runs from the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions. 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.

(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. 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.

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The increase in total facility production in 2012 over 2011 is due primarily to the operational items discussed above in footnote 2 of this table. 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.

(4) Represents packaged and synthetic specialty products from our Royal Purple, TruSouth and Missouri facilities.

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,
	2012			2011			2010
	(In thousands)
Sales	$	4,657,282		$	3,134,923		$	2,190,752
Cost of sales	4,144,105			2,860,793			1,992,003
Gross profit	513,177			274,130			198,749
Operating costs and expenses:
Selling	41,556			12,237			8,436
General and administrative	60,904			38,599			26,788
Transportation	107,900			94,187			85,471
Taxes other than income taxes	9,073			5,661			4,601
Insurance recoveries	—			(8,698		)	—
Other	7,816			6,852			1,963
Operating income	285,928			125,292			71,490
Other income (expense):
Interest expense	(85,573		)	(48,747		)	(30,497		)
Debt extinguishment costs	—			(15,130		)	—
Realized gain (loss) on derivative instruments	9,452			(7,909		)	(7,704		)
Unrealized loss on derivative instruments	(3,787		)	(10,383		)	(15,843		)
Other	470			842			(147		)
Total other expense	(79,438		)	(81,327		)	(54,191		)
Income before income taxes	206,490			43,965			17,299
Income tax expense	753			929			598
Net income	$	205,737		$	43,036		$	16,701
EBITDA	$	383,732		$	170,851		$	108,083
Adjusted EBITDA	$	404,610		$	211,020		$	138,462
Distributable Cash Flow	$	281,125		$	127,158		$	76,202

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Sales.    Sales increased$1,522.4 million, or 48.6%, to $4,657.3 million in 2012 from $3,134.9 million in 2011. The results of operations related to the Superior and Montana Acquisitions have been included in both segments since the dates of acquisition, September 30, 2011 and October 1, 2012, respectively. The results of operations related to the Missouri, TruSouth and Royal Purple Acquisitions have been included in the specialty products segment since the dates of acquisition, January 3, 2012, January 6, 2012 and July 3, 2012, respectively. Sales for each of our principal product categories in these periods were as follows:

	Year Ended December 31,
	2012			2011			% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	1,007,928		$	947,798		6.3	%
Solvents	491,114			495,934			(1.0	)%
Waxes	142,765			143,111			(0.2	)%
Packaged and synthetic specialty products (1)	161,673			—			—	%
Fuels (2)	2,029			3,432			(40.9	)%
Asphalt and by-products (3)	426,093			217,351			96.0	%
Total specialty products	$	2,231,602		$	1,807,626		23.5	%
Total specialty products sales volume (in barrels)	13,964,000			11,296,000			23.6	%
Average specialty products sales price per barrel	$	159.81		$	160.02		(0.1	)%
Fuel products:
Gasoline	$	1,213,247		$	649,098		86.9	%
Diesel	1,081,088			671,088			61.1	%
Jet fuel	211,360			172,565			22.5	%
Heavy fuel oils and other (4)	125,821			46,297			171.8	%
Hedging activities loss	(205,836		)	(211,751		)	(2.8	)%
Total fuel products	$	2,425,680		$	1,327,297		82.8	%
Total fuel products sales volume (in barrels)	21,729,000			12,843,000			69.2	%
Average fuel products sales price per barrel (excluding hedging activities)	$	121.11		$	119.84		1.1	%
Average fuel products sales price per barrel (including hedging activities loss)	$	111.63		$	103.35		8.0	%
Total sales	$	4,657,282		$	3,134,923		48.6	%
Total sales volume (in barrels)	35,693,000			24,139,000			47.9	%

(1) Represents packaged and synthetic specialty products from the Royal Purple, TruSouth and Missouri facilities.

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

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

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

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The components of the $424.0 million specialty products segment sales increase in 2012 were as follows:

	Dollar Change
	(Dollars in thousands)
Acquisitions	$	376,238
Sales price	34,555
Volume	13,183
Total specialty products segment sales increase	$	423,976

Specialty products segment sales for 2012increased$424.0 million, or 23.5%, as a result of acquisitions, higher sales prices and increased volumes from our legacy operations. The acquisitions of Superior in 2011 and TruSouth, Missouri, Royal Purple and Montana in 2012 increased sales by $376.2 million, which was substantially all related to packaged and synthetic specialty products and asphalt. Calumet’s legacy operations’ sales increased by $34.6 million due to higher average selling prices of 1.9% per barrel driven by higher asphalt prices as prices of lubricants, solvents and waxes remained consistent in the aggregate while average crude oil costs per barrel decreased 1.5%. Calumet’s legacy operations' sales volumes increased 0.7% as compared to the same period in 2011, which resulted in a $13.2 million increase in sales. The increase in sales volume is due primarily to increased lubricating oils sales volumes due to market conditions.

The components of the $1,098.4 million fuel products segment sales increase in 2012 were as follows:

	Dollar Change
	(Dollars in thousands)
Acquisitions	$	978,126
Sales price	18,451
Volume	95,891
Hedging activities	5,915
Total fuels products sales segment increase	$	1,098,383

Fuel products segment sales for 2012increased$1,098.4 million, or 82.8%, due primarily to acquisitions, increased volumes from our legacy operations and higher sales prices. The acquisitions of Superior in 2011 and Montana in 2012 increased sales by $978.1 million. Calumet’s legacy operations’ sales volumes increased 6.2% due to higher run rates of fuel products which were impacted by a turnaround at the Shreveport refinery in 2011. Calumet’s legacy operations’ average selling price per barrel (excluding the impact of those realized hedging losses reflected in sales) increased $1.35, or 1.1%, resulting in a $18.5 million increase in sales, compared to a 6.7% decrease in the average price of crude oil per barrel.

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Gross Profit.    Gross profit increased$239.0 million, or 87.2%, to $513.2 million in 2012 from $274.1 million in 2011. Gross profit for our specialty and fuel products segments was as follows:

	Year Ended December 31,
	2012			2011			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products:
Gross profit	$	308,629		$	258,648		19.3	%
Percentage of sales	13.8		%	14.3		%
Specialty products gross profit per barrel	$	22.10		$	22.90		(3.5	)%
Fuel products:
Gross profit excluding hedging activities	$	360,510		$	116,288		210.0	%
Hedging activities	$	(155,962	)	$	(100,806	)	54.7	%
Gross profit	$	204,548		$	15,482		1,221.2	%
Percentage of sales	8.4		%	1.2		%
Fuel products gross profit per barrel (excluding hedging activities)	$	16.59		$	9.05		83.3	%
Fuel products gross profit per barrel (including hedging activities)	$	9.41		$	1.21		677.7	%
Total gross profit	$	513,177		$	274,130		87.2	%
Percentage of sales	11.0		%	8.7		%

The components of the $50.0 million specialty products segment gross profit increase in 2012 were as follows:

	Dollar Change			% of Sales
	(Dollars in thousands)
2011 reported gross profit	$	258,648		14.3	%
Acquisitions	16,326			(1.9	)%
Sales price	34,555			1.5	%
Volume	3,174			—	%
Cost of materials	(27,812		)	(1.2	)%
Operating costs	23,738			1.1	%
2012 reported gross profit	$	308,629		13.8	%

The increase in specialty products segment gross profit of $50.0 million year over year was due primarily to the acquisitions of Superior, Missouri, TruSouth, Royal Purple and Montana, which contributed $16.3 million of gross profit and reduced gross profit as a percentage of sales due to increased mix of lower margin asphalt sales. Sales price and cost of materials changes, net, increased gross profit by $6.7 million, or 0.3% of sales, as the average selling price per barrel of specialty products outpaced the average cost of crude oil per barrel by 3.4%, partially offset by higher other feedstock costs and the unfavorable impact of the liquidation of higher cost LIFO inventory layers of $1.2 million. Operating costs in our legacy operations decreased $23.7 million primarily due to lower natural gas prices and repair and maintenance costs.

The components of the $189.1 million fuel products segment gross profit increase in 2012 were as follows:

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	Dollar Change			% of Sales
	(Dollars in thousands)
2011 reported gross profit	$	15,482		1.2	%
Acquisitions	213,368			9.0	%
Sales price	18,451			0.8	%
Volume	15,999			—	%
Hedging activities	(55,156		)	(2.4	)%
Cost of materials	(4,234		)	(0.2	)%
Operating costs	638			—	%
2012 reported gross profit	$	204,548		8.4	%

The increase in fuel products segment gross profit of $189.1 million year over year was due primarily to the Superior and Montana acquisitions, which contributed $213.4 million (excluding hedging activities) and increased gross profit from our legacy operations driven by sales price and volume, partially offset by increased realized losses on derivatives of $55.2 million. Sales price and cost of material changes, net, increased gross profit by $14.2 million, or 0.6% of sales, as the average selling price per barrel for fuel products outpaced the average cost of crude oil per barrel by 7.8% due to widening crack spreads experienced in our markets partially offset by the unfavorable impact of the liquidation of higher cost LIFO inventory layers of $8.2 million. Operating costs in our legacy operations were comparable year over year. Calumet’s legacy operations experienced increased sales volume of 6.2% leading to a $16.0 million increase in gross profit primarily due to higher run rates of fuel products which were impacted by a turnaround at the Shreveport refinery in 2011.

Selling.Selling expenses increased$29.3 million, or 239.6%, to $41.6 million in 2012 from $12.2 million in 2011. This increase was due primarily to increased amortization expense of $13.8 million primarily related to the recording of intangible assets associated with the Missouri, TruSouth and Royal Purple Acquisitions and additional employee compensation costs from the TruSouth and Royal Purple Acquisitions, with no similar expenses in the prior year, and increased advertising expenses of $6.5 million.

General and administrative. General and administrative expenses increased$22.3 million, or 57.8%, to $60.9 million in 2012 from $38.6 million in 2011. The increase was due primarily to additional employee compensation costs from the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions with no similar expenses in the prior year, increased professional fees of $11.3 million as a result of acquisition activities and increased incentive compensation costs of $5.1 million, partially offset by a $7.2 million gain related to the curtailment of certain benefits in benefit plans covering employees at the Superior refinery.

Transportation.Transportation expenses increased$13.7 million, or 14.6%, to $107.9 million in 2012 from $94.2 million in 2011. This increase is due primarily to incremental transportation expenses related to sales from the Superior, Royal Purple and Montana Acquisitions and higher freight rates.

Insurance recoveries.    Insurance recoveries were $8.7 million for the 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. Insurance recoveries were used to repair the failed unit and for working capital needs. This claim related to both property damage and business interruption. Recoveries of $1.9 million related to property damage have been reflected within investing activities (with the remainder in operating activities) in the consolidated statements of cash flows.

Interest expense.Interest expenseincreased$36.8 million, or 75.5%, to $85.6 million in 2012 from $48.7 million in 2011. The increase is due primarily to additional outstanding long-term debt, namely the 2019 Notes issued to partially fund the Superior Acquisition and the 2020 Notes issued to partially fund the Royal Purple Acquisition.

Debt extinguishment costs.    Debt extinguishment costs were $15.1 million for the year ended December 31, 2011. The debt extinguishment costs were related to the extinguishment of the prior term loan in April 2011 using proceeds from the issuance of the 2019 Notes. Please read Note 6 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information.

Derivative activity. The following table details the impact of our derivative instruments on the consolidated statements of operations for 2012 and 2011.

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	Year Ended December 31,
	2012			2011
	(In thousands)
Derivative loss reflected in sales	$	(205,836	)	$	(211,751	)
Derivative gain reflected in cost of sales	51,751			108,433
Derivative loss reflected in gross profit	$	(154,085	)	$	(103,318	)
Realized gain (loss) on derivative instruments	$	9,452		$	(7,909	)
Unrealized loss on derivative instruments	(3,787		)	(10,383		)
Derivative loss reflected in interest expense	—			(702		)
Total derivative loss reflected in the consolidated statements of operations	$	(148,420	)	$	(122,312	)
Total loss on derivative settlements	$	(149,665	)	$	(100,932	)

Realized gain (loss) on derivative instruments.Realized gain (loss) on derivative instruments increased $17.4 million to a gain of $9.5 million in 2012 from a loss of $7.9 million in 2011. The change was due primarily to an increased realized gain of approximately $40.1 million related to settlements of derivative instruments used to economically hedge crack spreads at our Superior refinery that are not accounted for as hedges for accounting purposes and therefore are not reflected in gross profit. Partially offsetting this increased realized gain was an increased realized loss due to hedging ineffectiveness of approximately $19.0 million related to settlements of cash flow hedges and increased realized loss of $6.2 million related to natural gas and crude oil derivative settlements included in our specialty products segment but not designated as cash flow hedges.

Unrealized loss on derivative instruments.Unrealized loss on derivative instrumentsdecreased$6.6 million to $3.8 million in 2012 from $10.4 million in 2011. This change was due primarily to a decreased unrealized loss of $6.4 million on natural gas derivative instruments included in our specialty products segment but not designated as cash flow hedges and decreased unrealized loss ineffectiveness of approximately $4.4 million. Partially offsetting this decreased unrealized loss was an unrealized loss of approximately $3.4 million in 2012 related to crude oil basis swaps included in our fuel products segment which were not designated as cash flow hedges and an unrealized loss of approximately $2.9 million in 2012 related to derivative instruments used to economically hedge crack spreads at our Superior refinery that are not accounted for as hedges for accounting purposes.

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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 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	%
Packaged and synthetic specialty products	—			—			—	%
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	$	649,098		$	328,517		97.6	%
Diesel	671,088			368,111			82.3	%
Jet fuel	172,565			142,126			21.4	%
Heavy fuel oils and other	46,297			10,784			329.3	%
Hedging activities loss	(211,751		)	(67,658		)	213.0	%
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	%
Average fuel products sales price per barrel (including hedging activities)	$	103.35		$	81.85		26.3	%
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 2011increased$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 increased4.9% over 2010 due primarily to incremental asphalt sales volume associated with the Superior Acquisition, which closed on September 30, 2011. Excluding those incremental asphalt sales volumes 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 was due primarily to a 26.1%increase in the average cost of crude oil per barrel for 2011 as compared to 2010.

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Fuel products segment sales for 2011increased$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 those incremental sales volume associated with the Superior Acquisition, our fuels products sales volume increased7.5% 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 millionincrease 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:
Gross profit	$	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:
Gross profit (loss) excluding hedging activities	$	116,288		$	(2,656	)	4,478.3	%
Hedging activities	$	(100,806	)	$	13,989		(820.6	)%
Gross profit	$	15,482		$	11,333		36.6	%
Percentage of sales	1.2		%	1.4		%
Fuel products gross profit (loss) per barrel (excluding hedging activities)	$	9.05		$	(0.28	)	3,332.1	%
Fuel products gross profit per barrel (including hedging activities)	$	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.Selling expenses increased$3.8 million, or 45.1%, to $12.2 million in 2011 from $8.4 million in 2010. This increase is due primarily to increased overall salaries and wages of $1.1 million and increased advertising costs of $1.3 million.

General and administrative. General and administrative expenses increased$11.8 million, or 44.1%, to $38.6 million in 2011 from $26.8 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 and increased overall salaries and wages of $0.7 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.

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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 expenseincreased$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 using proceeds from the issuance of the 2019 Notes issued in April 2011. Please read Note 6 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information.

Derivative activity.    The following table details the impact of our derivative instruments on the consolidated statements of operations for 2011 and 2010.

	Year Ended December 31,
	2011			2010
	(In thousands)
Derivative loss reflected in sales	$	(211,751	)	$	(67,658	)
Derivative gain reflected in cost of sales	108,433			81,647
Derivative gain (loss) reflected in gross profit	$	(103,318	)	$	13,989
Realized loss on derivative instruments	$	(7,909	)	$	(7,704	)
Unrealized loss on derivative instruments	(10,383		)	(15,843		)
Derivative loss reflected in interest expense	(702		)	(2,885		)
Total derivative loss reflected in the consolidated statements of operations	$	(122,312	)	$	(12,443	)
Total gain (loss) on derivative settlements	$	(100,932	)	$	6,390

Realized loss on derivative instruments.Realized loss on derivative instrumentsincreased$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 loss on derivative instruments.Unrealized loss on derivative instrumentsdecreased$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.

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 unitholders and general partner, debt service, replacement and environmental capital expenditures, capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. We expect to fund future capital expenditures with current cash flow from operations and borrowings under our revolving credit facility. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and borrowing availability under our existing revolving credit facility and may require us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.

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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 credit facilities. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which would be funded by borrowings under our revolving credit facility. In addition, our cash flow from operations may be impacted by the timing of settlement of our derivative activities. Gains and losses from derivative instruments that qualify as effective cash flow hedges are deferred in accumulated other comprehensive income (loss), but may impact operating cash flow in the period settled.

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

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Net cash provided by operating activities	$	380,108		$	63,778		$	134,143
Net cash used in investing activities	$	(624,234	)	$	(460,424	)	$	(34,759	)
Net cash provided by (used in) financing activities	$	276,236		$	396,673		$	(99,396	)
Net increase (decrease) in cash and cash equivalents	$	32,110		$	27		$	(12	)

Operating Activities.    Operating activities provided cash of $380.1 million during 2012 compared to $63.8 million during 2011. The increase in cash provided by operating activities is due primarily to increased net income of $162.7 million and reduced working capital requirements in 2012 providing $49.4 million, including a reduction in working capital requirements for the Montana Acquisition since the date of closing on October 1, 2012, compared to 2011 working capital requirements using $89.0 million.

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. Partially offsetting the increase in net working capital requirements was increased net income of $26.3 million.

Investing Activities.    Cash used in investing activities increased to $624.2 million in 2012 compared to $460.4 million in 2011. The increase is due primarily to the aggregate purchase prices of the Missouri, TruSouth, Royal Purple and Montana Acquisitions, which closed in 2012, of $569.2 million compared to the purchase price of $413.2 million for the Superior Acquisition in 2011.

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 of $413.2 million, which included $183.6 million for purchased inventories, with no similar acquisition activities in the prior year.

Financing Activities.    Financing activities provided cash of $276.2 million during 2012 compared to $396.7 million during 2011. This change is due primarily to decreased net proceeds from the public offering of common units (including the general partner’s contribution) of $151.3 million, decreased net proceeds from the private placement of senior notes of $315.8 million and increased distributions to our unitholders of $49.7 million, partially offset by the repayment of the senior secured first lien term loan facility in April 2011 of $367.4 million, with no such similar activity in 2012.

Financing activities provided cash of $396.7 million during 2011 compared to using cash of $99.4 million during 2010. Financing activities in 2011 were attributable to the net proceeds from the February 2011 and September 2011 public offerings of common units of $294.7 million and net 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.

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Acquisitions

During 2012, we completed the Missouri, TruSouth, Royal Purple and Montana Acquisitions. Subsequent to 2012, we completed the San Antonio Acquisition. We believe the Missouri, TruSouth and Royal Purple Acquisitions increase our position in the specialty lubricants markets, expand our geographic reach, increase our asset diversify and enhance our specialty products segment. We believe the Montana and San Antonio Acquisitions further diversify our crude oil feedstock slate, operating asset base and geographical presence. Please read “— Acquisitions” for additional information on these acquisitions.

Joint Venture

On February 7, 2013, we entered into a joint venture agreement with MDU Resources Group, Inc. (“MDU”) to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture is called Dakota Prairie Refining, LLC. The refinery is expected to process 20,000 bpd of Bakken crude oil to serve product demand in the region. Construction of the refinery could begin late in the second quarter of 2013 with startup of the refinery expected late in the fourth quarter of 2014. The refinery’s total construction cost is estimated at approximately $300.0 million. The capitalization of the joint venture is expected to be funded through contributions of $150.0 million from MDU and $75.0 million from us and proceeds of $75.0 million from an unsecured syndicated term loan facility with the joint venture as the borrower. The term loan facility is expected to be funded prior to the end of the first quarter of 2013. Funding for the project will occur over the course of the construction period, with the majority of the direct funding by us and MDU expected in 2014. The joint venture will allocate profits on a 50%/50% basis to us and MDU. We will cover the debt service cost of the lower interest rate term loan facility pursuant to the joint venture agreement. The joint venture will be governed by a board of managers comprised of representatives from both us and MDU. MDU will provide a portion of the crude oil supply to the refinery, as well as natural gas and electricity utility services. We will provide refinery operations, crude oil procurement and refined product marketing expertise to the joint venture.

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,
	2012		2011		2010
	(In thousands)
Capital improvement expenditures	$	28,712	$	25,616	$	10,656
Replacement capital expenditures	12,891		13,397		14,700
Environmental capital expenditures	15,450		10,465		9,645
Total	$	57,053	$	49,478	$	35,001

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 increased in 2012 compared to 2011 due to incremental capital projects at the Superior refinery related to our crude oil loading project. In 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. Our environmental capital expenditures increased during 2012 as compared to 2011 due primarily to expenditures related to the Global Settlement with the LDEQ and OSHA compliance issues. Please read Note 5 of Part II Item 8 “Financial Statements—Commitments and Contingencies—Environmental” for additional information on the Global Settlement and OSHA compliance issues.

We estimate our replacement and environmental capital expenditures will be approximately $18.0 million per quarter in 2013. These estimated amounts for 2013 include a portion of the $2.0 million to $6.0 million in environmental projects to be spent over the next three 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.

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Additionally, we anticipate turnaround spending requirements will be approximately $57.0 million in 2013 related to scheduled turnarounds at our Superior and Montana refineries. We expect these expenditures will be funded primarily through cash flow from operations.

We have several capital improvement projects under consideration including capacity expansions at certain of our facilities, as well as planned investments such as the joint venture located in North Dakota with MDU. We currently estimate that these organic growth opportunities could lead to capital improvement expenditures over the next two years of approximately $300.0 million. Decisions to proceed on such projects are based on several factors, including, but not limited to, feasibility studies, cost estimates, availability of funding sources and, in certain cases, required approval of the board of directors of our general partner. Due to these factors, the estimated amount to be spent in 2013 on capital improvement projects is approximately $100.0 million to $200.0 million.

Debt and Credit Facilities

As of December 31, 2012, our primary debt and credit instruments consist of:

• an $850.0 million senior secured revolving credit facility maturing in June 2016, subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $680.0 million;

• $600.0 million of 9 ³/8% senior notes due 2019;

• $275.0 million of 9 ⁵/8% senior notes due 2020.

As of December 31, 2012, we believe we were in compliance with all covenants under the debt instruments in place at December 31, 2012 and have adequate liquidity to conduct our business.

Short Term Liquidity

As of December 31, 2012, our principal sources of short-term liquidity were (i) $355.1 million of availability under our revolving credit facility and (ii) $32.2 million of cash. Borrowings under our revolving credit facility can be used for, among other things, working capital, capital expenditures, and other lawful corporate purposes including acquisitions.

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, 2012, we had availability on our revolving credit facility of $355.1 million, based on a $577.5 million borrowing base, $222.4 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 lenders under our revolving credit facility have a first priority lien on our cash, accounts receivable, inventory and certain other personal property.

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 2012 were $68.0 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, 2012, availability for additional borrowings under our revolving credit facility was approximately $354.0 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. `

The revolving credit facility 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, 2012, this margin was 100 basis points for prime and 225 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.

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 either 0.375% or 0.50% per annum depending on the average daily available unused borrowing capacity for the preceding month. 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.

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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 cash and availability under the revolving credit facility totaling at least the greater of (i) 15% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) without giving effect to the LC Reserve (as defined in the credit agreement) and (b) the 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, 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.

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.

For additional information regarding our revolving credit facility, see Note 6 “Long-Term Debt” in Item 8 “Financial Statements and Supplementary Data.”

Long-Term Financing

In addition to our principal sources of short-term liquidity listed above, we can meet our cash requirements (other than distributions of cash from operations to our common unitholders) through the issuance of long-term notes or additional common units.

From time to time we issue long-term debt securities, often referred to as our senior notes. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations. As of December 31, 2012, we had $600.0 million in 2019 Notes and $275.0 million in 2020 Notes outstanding. As of December 31, 2011, we had $600.0 million in 2019 Notes outstanding.

The indentures governing the 2019 and 2020 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 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 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 or 2020 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indentures governing the 2019 or 2020 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 and 2020 Notes will have the right to require that we repurchase all or a portion of such holder’s 2019 and 2020 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.

To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives.

We are subject, however, to conditions in the equity and debt markets for our common units and long-term senior notes, and there can be no assurance we will be able or willing to access the public or private markets for our common units and/or senior notes in the future. If we are unable or unwilling to issue additional common units, we may be required to either restrict capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Furthermore, our ability to access the public and private debt markets is affected by our credit ratings. For additional information regarding our 2019 and 2020 Notes, see Note 6 “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data.”

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Master Derivative Contracts and Collateral Trust Agreement

Under our 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 have also issued to one counterparty a $25.0 million standby letter of credit under the revolving credit 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 with this counterparty. We had no additional letters of credit or cash margin posted with any hedging counterparty as of December 31, 2012. 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 our 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 $24.0 million subsequent to December 31, 2012 to a net liability of approximately $69.0 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.

Additionally, we have a collateral trust agreement (the “Collateral Trust Agreement”) which governs how secured hedging counterparties will share collateral pledged as security for the payment obligations owed by us to secured hedging counterparties under their respective master derivatives contracts. The Collateral Trust Agreement limits 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. There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, we have the ability to add secured hedging counterparties from time to time.

Equity Transactions

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.

On April 18, 2012, we declared a quarterly cash distribution of $0.56 per unit on all outstanding common units, or approximately $30.1 million (including our general partner’s incentive distribution rights) in aggregate, for the quarter ended March 31, 2012. The distribution was paid on May 15, 2012 to unitholders of record as of the close of business on May 4, 2012. This quarterly distribution of $0.56 per unit equates to $2.24 per unit, or approximately $120.5 million (including our general partner’s incentive distribution rights) in aggregate on an annualized basis.

On May 8, 2012, we completed a public offering of our common units in which we sold 6,000,000 common units to the underwriters of the offering at a price to the public of $25.50 per common unit. Our net proceeds from this offering (net of underwriting discounts, commissions and expenses but before our general partner’s capital contribution) were $146.6 million which were used to repay borrowings under our revolving credit facility. Underwriting discounts totaled $6.2 million. Our general partner contributed $3.1 million to maintain its 2% general partner interest.

On July 20, 2012, we declared a quarterly cash distribution of $0.59 per unit on all outstanding common units, or approximately $35.9 million (including our general partner’s incentive distribution rights) in aggregate, for the quarter ended June 30, 2012. The distribution was paid on August 14, 2012 to unitholders of record as of the close of business on August 3, 2012. This quarterly distribution of $0.59 per unit equates to $2.36 per unit, or approximately $143.6 million (including our general partner’s incentive distribution rights) in aggregate on an annualized basis.

On October 16, 2012, we declared a quarterly cash distribution of $0.62 per unit on all outstanding common units, or approximately $38.2 million (including our general partner’s incentive distribution rights) in aggregate, for the quarter ended September 30, 2012. The distribution was paid on November 14, 2012 to unitholders of record as of the close of business on November 2, 2012. This quarterly distribution of $0.62 per unit equates to $2.48 per unit, or approximately $152.8 million (including our general partner’s incentive distribution rights) in aggregate on an annualized basis.

On January 8, 2013, we completed a public offering of our common units in which we sold 5,750,000 common units, including the overallotment option of 750,000 common units, to the underwriters of the offering at a price to the public of $31.81 per common unit. The proceeds received by us from this offering (net of underwriting discounts, commissions and

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expenses but before our general partner’s capital contribution) were $175.2 million and were used to repay borrowings under our revolving credit facility and for general partnership purposes. Our general partner contributed $3.7 million to maintain its 2% general partner interest.

On January 14, 2013, we declared a quarterly cash distribution of $0.65 per unit on all outstanding common units, or approximately $44.5 million (including our general partner’s incentive distribution rights) in aggregate, for the quarter ended December 31, 2012. The distribution was paid on February 14, 2013 to unitholders of record as of the close of business on February 4, 2013. This quarterly distribution of $0.65 per unit equates to $2.60 per unit, or approximately $178.2 million (including our general partner’s incentive distribution rights), in aggregate on an annualized basis.

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 profitability and working capital requirements, which cause 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, 2012 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)	$	578,156	$	90,514	$	174,677	$	168,129	$	144,836
Operating lease obligations (2)	78,922		23,194		26,689		13,945		15,094
Letters of credit (3)	222,359		222,359		—		—		—
Purchase commitments (4)	1,158,474		999,146		158,749		579		—
Pension obligations	27,455		4,402		7,751		6,448		8,854
Employment agreements (5)	892		428		464		—		—
Financing Activities:
Capital lease obligations	5,512		771		726		683		3,332
Long-term debt obligations, excluding capital lease obligations	875,000		—		—		—		875,000
Total obligations	$	2,946,770	$	1,340,814	$	369,056	$	189,784	$	1,047,116

(1) Interest on long-term debt at contractual rates and maturities relates primarily to our 2019 and 2020 Notes, revolving credit facility fees and capital lease obligations.

(2) We have various operating leases primarily for railcars, the use of land, storage tanks, compressor stations, 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 Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, Phillips 66 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 $76.4

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million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of December 31, 2012. This amount is not included in the table above.

Off-Balance Sheet Arrangements

We did not enter into any material off-balance sheet debt or operating lease transactions during the fiscal year.

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Critical Accounting Policies and Estimates

Our discussion and analysis of results of operations and financial condition are based upon our consolidated financial statements for the years ended December 31, 2012, 2011 and 2010. 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 our normal billing and credit terms, all of our obligations related to the 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 our customers’ ability to pay. Individual accounts are written off against the allowance for doubtful accounts after all reasonable collection efforts have been exhausted.	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, 2012 would have affected net income by approximately $0.1 million for the year ended December 31, 2012.
Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Inventories
The cost of inventory is recorded 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. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.  j	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 $38.3 million and $87.6 million higher at December 31, 2012 and 2011, respectively. During the years ended December 31, 2012 and 2011, the Company recorded $8.1 million and $2.0 million of losses, respectively, in cost of sales in the consolidated statements of operations due to the lower of cost or market valuation. During the year ended December 31, 2012, we recorded $4.2 million of losses in cost of sales in the consolidated statements of operations due to the liquidation of higher cost inventory layers. During the year ended December 31, 2011, we recorded $5.2 million of gains in cost of sales in the consolidated statements of operations due to the liquidation of lower cost inventory layers. j 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, 2012 inventory values, our net income would have been negatively impacted by approximately $59.2 million.
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 $3.1 million and derivative liabilities of $48.0 million as of December 31, 2012, 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 gains and unrealized losses on derivative instruments of $9.5 million and $3.8 million, respectively, on our derivative instruments for the year ended December 31, 2012. The decrease in the fair market value of our outstanding derivative instruments from a net asset of $14.9 million as of December 31, 2011 to a net liability of $44.9 million as of December 31, 2012 was due primarily to increases in the forward market values of fuel products margins, or crack spreads, relative to our hedged products margins and settlement of derivatives in 2012 that resulted in realized losses. 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. In addition, we measure our investments associated with our non-contributory defined benefit plans (“Pension Plan”) on a recurring basis. As of December 31, 2012 our investments associated with our Pension Plan primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded, (iii) a commingled fund and (iv) a balanced fund. The mutual and balanced 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. Less than 10.0% of our assets and 95.5% of our liabilities measured at fair value are classified as Level 3 in the fair value hierarchy as of December 31, 2012.	Our derivative instruments are reported in the accompanying consolidated financial statements at fair value and 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 Baa2 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 and natural gas 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, 2012 our asset was reduced by approximately $0.1 million and our liability was reduced by approximately $0.2 million. 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. 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, we have categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative instruments we hold.   Our weighted-average expected rate of return on pension assets was 4.71% at the end of 2012. The weighted-average discount rate was 3.83% for the pension benefit obligations and 0.26% for the other post retirement benefit obligations as of December 31, 2012. Changes in pension and other post retirement 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.	We have not made any material changes in the accounting methodology we use to establish our derivative estimates or pension asset valuations during the past three fiscal years. We have consistently applied these valuation techniques in all periods presented and believe we obtained the most accurate information available for the types of derivative instruments and pension assets we hold. We believe that the fair values of our derivative instruments may diverge materially from the amounts currently recorded at 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, 2012:
			In millions
		Crude oil swaps	$	17.8
		Crude oil basis swaps	$	0.9
		Diesel swaps	$	(12.3	)
		Jet fuel swaps	$	(3.8	)
		Gasoline swaps	$	(1.7	)
			$	0.9
		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 $0.3 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 $3.2 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 $0.7 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 11 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.

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”.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Derivative Instruments

We are exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in our fuel products segment) and natural gas. We use various strategies to reduce our exposure to commodity price risk. We do not attempt to eliminate all of our risk due to the cost of such actions are believed to be too high in relation to the risk posed to our future cash flows, earnings and liquidity. The strategies to reduce our risk utilize both physical forward contracts and financially settled derivative instruments such as swaps, futures and options to attempt to reduce our exposure with respect to:

• crude oil purchases;

• refined product sales;

• natural gas purchases; and

• fluctuations in the value of crude oil between geographic regions and in between the different types of crude oil such as NYMEX WTI, Light Louisiana Sour (“LLS”) and WCS.

As of December 31, 2012, we have entered into swap contracts on forecasted purchases from 2013 through 2015 for 17,818,500 barrels of NYMEX WTI crude oil and forecasted sales of 1,725,000 barrels of U.S. Gulf Coast conventional gasoline, 12,320,500 barrels of U.S. Gulf Coast ultra-low sulfur diesel and 3,773,000 barrels of U.S. Gulf Coast jet fuel. These derivative instruments, on a combined basis, were entered into to hedge a portion of our gross profit in our fuels products segment. Please read Note 7 — “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 instruments, and a further discussion of our hedging policies.

We also enter into basis swap contracts that improve the effectiveness of our crude oil swap contracts by locking in the spread between NYMEX WTI and the crude oil that we are actually purchasing for use by our refineries. As of December 31, 2012, we had 912,000 barrels of crude oil basis swap contracts locking in the differential between NYMEX WTI and WCS crude oil. Please read Note 7 — “Derivatives” in the notes to our consolidated financial statements under Item 8 “Financial Statements and Supplementary Data” for additional information.

The following tables provide a summary of the implied crack spreads for the crude oil, diesel, jet fuel and gasoline swaps, as well as our WCS crude oil versus NYMEX WTI crude oil basis swaps as of December 31, 2012 in our fuels products segment which we disclose in Note 7 — “Derivatives” in the notes to our consolidated financial statements under Item 8 “Financial Statements and Supplementary Data”.

Swap Contracts by Expiration Dates	Barrels	BPD	Implied Crack Spread ($/Bbl)
First Quarter 2013	2,295,000	25,500	$	23.77
Second Quarter 2013	2,366,000	26,000	27.77
Third Quarter 2013	1,794,000	19,500	28.11
Fourth Quarter 2013	1,472,000	16,000	29.55
Calendar Year 2014	5,110,000	14,000	26.70
Calendar Year 2015	4,781,500	13,100	26.32
Totals	17,818,500
Average price			$	26.74

Our derivative instruments and overall fuel products hedging positions are monitored regularly by our risk management committee, which includes our executive officers. The risk management committee reviews market information and our hedging positions regularly to determine if additional derivatives activity is required. A summary of derivative positions and a summary of hedging strategy are presented to our general partner’s board of directors quarterly.

The following table illustrates how a change in market price (holding all other variables constant and excluding the impact of our current hedges) would affect our sales and cost of sales in the consolidated statements of operations.

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	Sales		Cost of Sales
	Year Ended December 31,		Year Ended December 31,
	2012	2011	2012	2011
	(In millions)
Fuel Products:
$1.00 change in per barrel price of crude oil (1)			$21.7	$12.8
$1.00 change in per barrel selling price of gasoline, diesel and jet fuel (1)	$21.7	$12.8
Specialty Products:
$1.00 change in per barrel price of crude oil (1)			$14.0	$11.3
$0.50 change in MMBtu (one million British Thermal Units) of natural gas (2)			$5.2	$4.9

(1)     Based on our 2012 and 2011 sales volumes.

(2) Based on our results for the years ended December 31, 2012 and 2011.

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 11 — “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

We have no variable rate debt and no interest rate swaps outstanding as of December 31, 2012. For our fixed rate 2019 and 2020 Notes, changes in interest rates will generally affect the fair value, but not our interest expense or cash flows. The following table provides information about the fair value of our debt instruments.

	December 31, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
Financial Instrument:
2019 Notes	$	658.8	$	587.6	$	591.8	$	586.3
2020 Notes	$	301.8	$	270.4	$	—	$	—

We have an $850.0 million revolving credit facility as of December 31, 2012 and 2011, with borrowings bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. Borrowings under this facility are variable and at the time of borrowing we assess whether to enter into an interest rate swap to fix the rate or not at that time. We had no borrowings outstanding under this facility as of December 31, 2012 and 2011.

Foreign Currency Risk

We have minimal exposure to foreign currency risk and as such the cost of hedging this risk is viewed to be in excess of the benefit of further reductions in our exposure to foreign currency exchange rate fluctuations.

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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 Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, LLC, which are included in the Company’s 2012 consolidated financial statements and constituted $599,909,000 of the Company’s total assets as of December 31, 2012 and $266,103,000 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 Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, LLC.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012, 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, 2012.

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

March 1, 2013

/s/ R. Patrick Murray, II

R. Patrick Murray, II

Senior Vice President, Chief Financial Officer and

Secretary of Calumet GP, LLC

March 1, 2013

74

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, 2012, 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 Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, LLC., which are included in the 2012 consolidated financial statements of Calumet Specialty Products Partners, L.P. and constituted $599,909,000 of total assets as of December 31, 2012 and $266,103,000 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 Missouri, LLC, TruSouth Oil, LLC, Royal Purple, LLC and Calumet Montana Refining, 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, 2012, 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, 2012 and 2011 and the related statements of operations and comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2012 of Calumet Specialty Products Partners, L.P. and our report dated March 1, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Indianapolis, Indiana

March 1, 2013

75

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, 2012 and 2011, and the related consolidated statements of operations and comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Indianapolis, Indiana

March 1, 2013

76

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

	Year Ended December 31,
	2012			2011
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	32,174		$	64
Accounts receivable:
Trade, less allowance for doubtful accounts of $1,150 and $925, respectively	219,314			208,928
Other	7,469			3,137
	226,783			212,065
Inventories	553,574			497,740
Derivative assets	3,088			58,502
Prepaid expenses and other current assets	10,368			8,179
Deposits	7,959			2,094
Total current assets	833,946			778,644
Property, plant and equipment, net	986,875			842,101
Goodwill	187,013			48,335
Other intangible assets, net	197,083			22,675
Other noncurrent assets, net	48,128			40,303
Total assets	$	2,253,045		$	1,732,058
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	333,416		$	302,826
Accrued interest payable	23,526			10,500
Accrued salaries, wages and benefits	20,067			13,481
Accrued income taxes payable	27,577			452
Other taxes payable	13,676			12,616
Other current liabilities	8,397			4,600
Current portion of long-term debt	771			551
Derivative liabilities	47,968			43,581
Total current liabilities	475,398			388,607
Pension and postretirement benefit obligations	23,999			26,957
Other long-term liabilities	1,125			1,055
Long-term debt, less current portion	862,730			586,539
Total liabilities	1,363,252			1,003,158
Commitments and contingencies
Partners’ capital:
Limited partners’ interest (57,529,778 units and 51,529,778 units, issued and outstanding at December 31, 2012 and 2011, respectively)	884,805			666,471
General partner’s interest	30,467			23,902
Accumulated other comprehensive income (loss)	(25,479		)	38,527
Total partners’ capital	889,793			728,900
Total liabilities and partners’ capital	$	2,253,045		$	1,732,058

See accompanying notes to consolidated financial statements.

77

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2012			2011			2010
	(In thousands, except per unit data)
Sales	$	4,657,282		$	3,134,923		$	2,190,752
Cost of sales	4,144,105			2,860,793			1,992,003
Gross profit	513,177			274,130			198,749
Operating costs and expenses:
Selling	41,556			12,237			8,436
General and administrative	60,904			38,599			26,788
Transportation	107,900			94,187			85,471
Taxes other than income taxes	9,073			5,661			4,601
Insurance recoveries	—			(8,698		)	—
Other	7,816			6,852			1,963
Operating income	285,928			125,292			71,490
Other income (expense):
Interest expense	(85,573		)	(48,747		)	(30,497		)
Debt extinguishment costs	—			(15,130		)	—
Realized gain (loss) on derivative instruments	9,452			(7,909		)	(7,704		)
Unrealized loss on derivative instruments	(3,787		)	(10,383		)	(15,843		)
Other	470			842			(147		)
Total other expense	(79,438		)	(81,327		)	(54,191		)
Income before income taxes	206,490			43,965			17,299
Income tax expense	753			929			598
Net income	$	205,737		$	43,036		$	16,701
Allocation of net income:
Net income	$	205,737		$	43,036		$	16,701
Less:
General partner’s interest in net income	4,115			861			334
General partner’s incentive distribution rights	5,433			322			—
Non-vested share based payments	1,199			—			—
Net income available to limited partners	194,990			41,853			16,367
Weighted average limited partner units outstanding:
Basic	55,559			42,599			35,335
Diluted	55,677			42,644			35,351
Limited partners’ interest basic net income per unit	$	3.51		$	0.98		$	0.46
Limited partners’ interest diluted net income per unit	$	3.50		$	0.98		$	0.46
Cash distributions declared per limited partner unit	$	2.30		$	1.94		$	1.83

See accompanying notes to consolidated financial statements.

78

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Net income	$	205,737		$	43,036		$	16,701
Other comprehensive loss:
Cash flow hedges:
Cash flow hedge (income) loss reclassified to net income	154,085			104,020			(11,104		)
Change in fair value of cash flow hedges	(215,132		)	(34,160		)	(29,015		)
Defined benefit pension and retiree health benefit plans	(2,959		)	(3,714		)	(144		)
Total other comprehensive income (loss)	(64,006		)	66,146			(40,263		)
Comprehensive income (loss) attributable to partners’ capital	$	141,731		$	109,182		$	(23,562	)

See accompanying notes to consolidated financial statements.

79

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	Accumulated  Other Comprehensive Income (Loss)			Partners’ Capital									Total
				General Partner			Limited Partners
							Common			Subordinated
	(In thousands)
Balance at January 1, 2010	$	12,644		$	19,087		$	418,902		$	34,714		$	485,347
Other comprehensive loss	(40,263		)	—			—			—			(40,263		)
Net income	—			334			10,305			6,062			16,701
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
Other comprehensive income	66,146			—			—			—			66,146
Net income	—			1,183			41,853			—			43,036
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
Other comprehensive loss	(64,006		)	—			—			—			(64,006		)
Net income	—			9,548			196,189			—			205,737
Units repurchased for phantom unit grants	—			—			(2,110		)	—			(2,110		)
Issuance of phantom units	—			—			1,648			—			1,648
Amortization of vested phantom units	—			—			2,344			—			2,344
Proceeds from public offering of common units, net	—			—			146,558			—			146,558
Contributions from Calumet GP, LLC	—			3,122			—			—			3,122
Distributions to partners	—			(6,105		)	(126,295		)	—			(132,400		)
Balance at December 31, 2012	$	(25,479	)	$	30,467		$	884,805		$	—		$	889,793

See accompanying notes to consolidated financial statements.

80

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Operating activities
Net income	$	205,737		$	43,036		$	16,701
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	91,669			63,009			60,287
Amortization of turnaround costs	13,356			11,384			10,006
Non-cash interest expense	6,081			3,728			3,864
Non-cash debt extinguishment costs	—			14,401			—
Provision for doubtful accounts	22			380			74
Unrealized (gain) loss on derivative instruments	3,787			10,383			15,843
Loss on disposal of fixed assets	2,488			1,525			239
Non-cash equity based compensation	6,512			4,895			1,540
Other non-cash activities	1,070			74			142
Changes in assets and liabilities:
Accounts receivable	34,609			(54,484		)	(35,267		)
Inventories	17,898			(167,028		)	(9,860		)
Prepaid expenses and other current assets	21,680			(425		)	(98		)
Derivative activity	(5,033		)	11,742			2,990
Turnaround costs	(14,899		)	(14,052		)	(10,684		)
Deposits	(5,852		)	—			4,767
Other assets	(4,007		)	(426		)	(2,006		)
Accounts payable	11,859			131,261			64,639
Accrued interest payable	13,026			7,350			100
Accrued salaries, wages and benefits	1,039			4,066			1,189
Accrued income taxes payable	(16,089		)	366			4
Other taxes payable	862			5,528			(381		)
Other liabilities	1,932			(12,033		)	10,463
Pension and postretirement benefit obligations	(7,639		)	(902		)	(409		)
Net cash provided by operating activities	380,108			63,778			134,143
Investing activities
Additions to property, plant and equipment	(57,053		)	(49,478		)	(35,001		)
Proceeds from insurance recoveries — equipment	—			1,942			—
Cash paid for acquisitions, net of cash acquired	(569,191		)	(413,173		)	—
Proceeds from sale of property, plant and equipment	2,010			285			242
Net cash used in investing activities	(624,234		)	(460,424		)	(34,759		)
Financing activities
Proceeds from borrowings — revolving credit facility	1,558,323			1,598,680			1,015,485
Repayments of borrowings — revolving credit facility	(1,558,323		)	(1,609,512		)	(1,044,553		)
Repayments of borrowings — term loan credit facility	—			(367,385		)	(3,850		)
Payments on capital lease obligations	(1,499		)	(1,069		)	(1,302		)
Proceeds from public offerings of common units, net	146,558			294,702			793
Proceeds from senior notes offerings	270,187			586,000			—
Debt issuance costs	(7,622		)	(27,666		)	—
Contributions from Calumet GP, LLC	3,122			6,286			18
Units repurchased for phantom unit grants	(2,110		)	(620		)	(248		)
Distributions to partners	(132,400		)	(82,743		)	(65,739		)
Net cash provided by (used in) financing activities	276,236			396,673			(99,396		)
Net increase (decrease) in cash and cash equivalents	32,110			27			(12		)
Cash and cash equivalents at beginning of year	64			37			49
Cash and cash equivalents at end of year	$	32,174		$	64		$	37
Supplemental disclosure of cash flow information
Interest paid, net of capitalized interest	$	66,223		$	37,856		$	26,389
Income taxes paid	$	718		$	568		$	188
Supplemental disclosure of noncash financing and investing activities
Equipment acquired under capital lease	$	5,771		$	—		$	—

See accompanying notes to consolidated financial statements.

81

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, 2012, the Company had 57,529,778 limited partner common units and 1,174,077 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses. The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, asphalt, waxes and fuel and fuel related products including gasoline, diesel, jet fuel and heavy fuel oils. The Company owns facilities located in Shreveport, Louisiana (“Shreveport” and “TruSouth”); Superior, Wisconsin (“Superior”); Great Falls, Montana (“Montana”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”); Dickinson, Texas (“Dickinson”); Louisiana, Missouri (“Missouri”) and Porter, Texas (“Royal Purple”) 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, TruSouth Oil, LLC, Calumet Montana Refining, LLC, S&S International Mining Enterprises, Inc., Royal Purple, 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 inventory is recorded 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. The replacement cost of these inventories, based on current market values, would have been $38,295 and $87,635 higher as of December 31, 2012 and 2011, respectively.

Inventories consist of the following:

	December 31,
	2012		2011
Raw materials	$	85,399	$	105,802
Work in process	119,526		91,763
Finished goods	348,649		300,175
	$	553,574	$	497,740

82

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. During the year ended December 31, 2012, the Company recorded $4,206 of losses in cost of sales in the consolidated statements of operations due to the liquidation of higher cost inventory layers. During the years ended December 31, 2011 and 2010 the Company recorded $5,166 and $13,661, respectively, of gains in cost of sales in the consolidated statements of operations due to the liquidation of lower cost inventory layers.

In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. During the years ended December 31, 2012, 2011 and 2010 the Company recorded $8,124, $1,976 and $76 of losses in cost of sales in the consolidated statements of operations due to the lower of cost or market valuation.

Accounts Receivable

The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are carried at their face amounts and are generally due within 30 days 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. Individual accounts are written off against the allowance for doubtful accounts after all reasonable collection efforts have been exhausted. The activity in the allowance for doubtful accounts was as follows:

	December 31,
	2012			2011			2010
Beginning balance	$	925		$	633		$	801
Provision	362			380			(61		)
Recoveries	17			—			—
Write-offs, net	(154		)	(88		)	(107		)
Ending balance	$	1,150		$	925		$	633

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.

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

	December 31,
	2012			2011
Land	$	11,229		$	8,857
Buildings and improvements (10 to 40 years)	28,063			19,729
Machinery and equipment (10 to 20 years)	1,172,970			1,012,318
Furniture and fixtures (5 to 10 years)	7,624			5,732
Assets under capital leases (1 to 4 years)	11,071			4,201
Construction-in-progress	53,790			22,945
	1,284,747			1,073,782
Less accumulated depreciation	(297,872		)	(231,681		)
	$	986,875		$	842,101

83

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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

During 2012, 2011 and 2010, the Company incurred $86,327, $49,339 and $30,886, respectively, of interest expense of which $754, $592 and $389, respectively, was capitalized as a component of property, plant and equipment.

The Company has not recorded an asset retirement obligation as of December 31, 2012 or 2011 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.

During the years ended December 31, 2012, 2011 and 2010, the Company recorded $74,292, $55,536 and $51,365, respectively, of depreciation expense on its property, plant and equipment. Depreciation expense included $1,030, $1,050 and $1,050 for the years ended 2012, 2011 and 2010, respectively, related to the Company’s capital lease assets.

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, 2012 and 2011, the Company has $15,007 and $6,037, respectively, of unamortized capitalized software costs. During the years ended December 31, 2012, 2011 and 2010, the Company recorded $967, $416, and $262, respectively, of amortization expense on capitalized computer software.

Goodwill

Goodwill represents the excess of purchase price over fair value of the net assets acquired in the acquisitions of Penreco on January 3, 2008, Missouri on January 3, 2012, TruSouth on January 6, 2012, Royal Purple on July 3, 2012 and Montana on October 1, 2012. See Note 3 for more information. 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 (“ASU 2011-08”) which amends the rules for testing goodwill for impairment. Under ASU 2011-08, 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.

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 judgment 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 its reporting units are greater than their carrying amounts. No impairment was recognized in 2012, 2011 or 2010.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Other Intangible Assets

Other intangible assets consist of tangible assets associated with supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements that were acquired in the acquisition of Penreco on January 3, 2008, the Missouri Acquisition on January 3, 2012, the TruSouth Acquisition on January 6, 2012 and the Royal Purple Acquisition on July 3, 2012. The majority of these assets are being amortized using discounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships are being amortized using the discounted estimated future cash flows method based upon assumed rates of annual customer attrition. For more information, refer to Note 4.

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.

During 2012, the Company recorded a write-down related to unutilized fixed assets within its specialty products segment. The non-cash charge of $1,640 was recorded in other operating costs and expenses on the consolidated statements of operations.

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 the 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.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Generally, tax returns remain subject to examination by taxing authorities for three years. The Company had no unrecognized tax benefits as of December 31, 2012 and 2011.

Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Company’s partnership agreement. Individual partners have different investment basis 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 Company is not readily available.

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 7.

Other Noncurrent Assets

Other noncurrent assets include deferred debt issuance costs and turnaround costs. Deferred debt issuance costs were $29,414 and $26,374 as of December 31, 2012 and 2011, 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 $6,578 and $1,996 at December 31, 2012 and 2011, respectively.

Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $14,346 and $12,471 as of December 31, 2012 and 2011, 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 $17,813 and $12,538 at December 31, 2012 and 2011, 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 the Company’s partnership agreement.

Unit Based Compensation

For unit based compensation awards granted, compensation expense is recognized in the Company’s consolidated financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The unit based compensation awards vest over a period not exceeding four years. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.

Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). Liability Awards are recorded in accrued salaries, wages and benefits based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense.

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 $107,900, $94,187 and $85,471, respectively, for the years ended December 31, 2012, 2011, and 2010, in transportation expense in the consolidated statements of operations, the majority of which is billed to customers.

Advertising Expenses

The Company expenses advertising costs as incurred which totaled $8,232, $1,699 and $443 in 2012, 2011 and 2010, respectively.

New Accounting Pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the 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 was effective for the first reporting period (including interim periods) beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on the Company’s 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 amended current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income (loss) as part of the statement of partners’ capital. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income (loss) which contains two sections, net income and other comprehensive income (loss), 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 (loss) by component in both the statement in which net income is presented and the statement in which other comprehensive income (loss) 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, were effective for fiscal years (including interim periods) beginning after December 15, 2011 and are to be applied retrospectively, with early adoption permitted. The Company elected to present the components of comprehensive loss in two separate but consecutive financial statements, namely the consolidated statements of operations and the consolidated statements of comprehensive income (loss).

In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)—Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the balance sheet. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet Topic(210)—Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies the scope of the setting disclosures and addresses any unintended consequences. Amendments to ASU 2011-11, as superseded by ASU 2013-01, are effective for the first reporting period (including interim periods) beginning after January 1, 2013 and should be applied retrospectively for any period presented. The Company is in the process of evaluating the impact of the adoption of ASU 2011-11 and ASU 2013-01 on its financial statements.

In July 2012, the FASB issued ASU No. 2012-02, Intangibles (Topic 350)—Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). ASU 2012-02 permits an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is more than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset exceeds its

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

carrying amount, quantitative impairment testing is not required. However, if an entity concludes otherwise, quantitative impairment testing is required. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The adoption of ASU 2012-02 did not have a material impact on the Company’s consolidated financial statements.

In October 2012, the FASB issued ASU No. 2012-04, Technical Corrections and Improvements (“ASU 2012-04”). ASU 2012-04 covers a wide range of topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. ASU 2012-04 is effective for fiscal periods beginning after December 15, 2012. The Company is in the process of evaluating the impact of the adoption of ASU 2012-04 on its financial statements.    

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220)—Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires entities to report either on the statement of operations or disclose in the footnotes to the consolidated financial statements the effects on earnings from items that are reclassified out of comprehensive income. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. ASU 2013-02 is effective prospectively for the first reporting period after December 15, 2012 with early adoption permitted. The adoption of ASU 2013-02 will not have a material impact on the Company’s consolidated financial statements.

3. Acquisitions

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 but excluding the over-allotment option exercised), (ii) net proceeds of $180,296 from the Company’s September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings under the Company’s revolving credit facility. The Company acquired the following assets:

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

• 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.

The Superior refinery produces gasoline, diesel, asphalt and heavy fuel oils 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. 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 general and administrative expenses in the consolidated statements of operations.

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

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

	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

Missouri Acquisition

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., including a manufacturing facility located in Louisiana, Missouri for aggregate consideration of approximately $19,575 (“Missouri Acquisition”). The Missouri Acquisition was financed with borrowings under the Company’s revolving credit facility and cash on hand. The Company believes the Missouri Acquisition provides greater diversity to its specialty products segment. The assets acquired and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Missouri Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $505 which are reflected in general and administrative expenses in the consolidated statements of operations.

The Company recorded $1,478 of goodwill as a result of the Missouri Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired is as follows:

	Allocation of Purchase Price
Inventories	$	2,775
Property, plant and equipment	9,955
Goodwill	1,478
Other intangible assets	5,367
Total purchase price	$	19,575

The component of the intangible asset listed in the table above as of January 3, 2012, based upon a third party appraisal, was as follows:

	Amount		Life (Years)
Customer relationships	$	5,367	20

TruSouth Acquisition

On January 6, 2012, the Company completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC (“TruSouth”), a specialty petroleum packaging and distribution company located in Shreveport, Louisiana for aggregate consideration of approximately $26,827, net of cash acquired (“TruSouth Acquisition”). The TruSouth Acquisition 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. The Company believes the TruSouth Acquisition provides greater diversity to its specialty products segment. The assets acquired and liabilities assumed have been included in the Company’s consolidated balance sheets and results of operations have been included in the Company’s consolidated statements of operations since the date of acquisition. In connection with the TruSouth Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of $179 which are reflected in general and administrative expenses in the consolidated statements of operations.

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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 $392 of goodwill as a result of the TruSouth Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:

	Allocation of Purchase Price
Accounts receivable	$	5,217
Inventories	7,976
Prepaid expenses and other current assets	272
Property, plant and equipment	17,682
Goodwill	392
Other intangible assets	2,545
Accounts payable	(2,672		)
Accrued salaries, wages and benefits	(151		)
Other current liabilities	(918		)
Long-term debt	(3,516		)
Total purchase price, net of cash acquired	$	26,827

The components of intangible assets listed in the table above as of January 6, 2012, based upon a third party appraisal, were as follows:

	Amount		Life (Years)
Customer relationships	$	1,775	16
Tradenames	675		9
Non-competition agreements	95		2
Total	$	2,545
Weighted average amortization period			14

Royal Purple Acquisition

On July 3, 2012, the Company completed the acquisition of Royal Purple, Inc. (“Royal Purple”), a Texas corporation which was converted into a Delaware limited liability company at closing, for aggregate consideration of approximately $331,239, net of cash acquired (“Royal Purple Acquisition”). Royal Purple is a leading independent formulator and marketer of premium industrial and consumer lubricants to a diverse customer base across several large markets including oil and gas, chemicals and refining, power generation, manufacturing and transportation, food and drug manufacturing and automotive aftermarket. The Royal Purple Acquisition was financed with net proceeds of $262,565 from the Company’s June 2012 private placement of 9 5/8% senior notes due August 1, 2020 and cash on hand. The Company believes the Royal Purple Acquisition increases its position in the specialty lubricants market, expands its geographic reach, increases its asset diversity and enhances its specialty products segment. The assets acquired and liabilities assumed and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Royal Purple Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $426 which are reflected in general and administrative expenses in the consolidated statements of operations.

The Company recorded $109,165 of goodwill as a result of the Royal Purple Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment.

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

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

	Allocation of Purchase Price
Accounts receivable	$	15,159
Inventories	19,299
Prepaid expenses and other current assets	236
Deposits	13
Property, plant and equipment	10,579
Goodwill	109,165
Other intangible assets	183,398
Accounts payable	(3,804		)
Accrued salaries, wages and benefits	(1,698		)
Other taxes payable	(198		)
Other current liabilities	(910		)
Total purchase price, net of cash acquired	$	331,239

The components of intangible assets listed in the table above as of July 3, 2012, based upon a third party appraisal, were as follows:

	Amount		Life (Years)
Customer relationships	$	118,683	20
Tradenames - Royal Purple retail	14,790		Indefinite
Tradenames	5,746		10
Trade secrets	44,179		12
Total	$	183,398
Weighted average amortization period			18

Montana Acquisition

On October 1, 2012, the Company completed the acquisition from Connacher Oil and Gas Limited (“Connacher”) of all the shares of common stock of Montana Refining Company, Inc. (“Montana”) and an insignificant affiliated company for aggregate consideration of approximately $191,550, net of cash acquired and excluding certain purchase price adjustments (“Montana Acquisition”). Montana produces gasoline, diesel, jet fuel and asphalt, which are marketed primarily into local markets in Washington, Montana, Idaho and Alberta, Canada. The Montana Acquisition was funded primarily with cash on hand with the balance through borrowings under the Company’s revolving credit facility. The Company believes the Montana Acquisition further diversifies its crude oil feedstock slate, operating asset base and geographic presence. The assets acquired and liabilities assumed and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Montana Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $3,267 which are reflected in general and administrative expenses in the consolidated statements of operations.

Immediately after closing the Montana Acquisition, the Company converted Montana Refining Company, Inc. into a Delaware limited liability company, Calumet Montana Refining, LLC. This conversion resulted in the recognition of a current income tax liability, with an expected payment of income taxes in early 2013, of approximately $27,643, which was offset by the derecognition of a deferred tax liability for a comparable amount which was assumed in connection with the acquisition.

The Company recorded $27,643 of goodwill as a result of the Montana Acquisition, all of which was recorded within the Company’s fuel products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its fuel products segment.

The Montana Acquisition purchase price allocation has not yet been finalized due to the timing of the closing of the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

necessary to complete the analysis is obtained. The preliminary allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:

	Allocation of Purchase Price
Accounts receivable	$	28,973
Inventories	43,682
Prepaid expenses and other current assets	23,105
Deposits	256
Property, plant and equipment	125,472
Goodwill	27,643
Other noncurrent assets, net	327
Accounts payable	(8,402		)
Accrued salaries, wages and benefits	(1,448		)
Deferred income tax liability	(27,643		)
Accrued income taxes payable	(15,571		)
Other taxes payable	(3,015		)
Other current liabilities	(107		)
Pension and postretirement benefit obligations	$	(1,722	)
Total purchase price, net of cash acquired	$	191,550

Results of Sales and Earnings

The following financial information reflects the results of sales and operating income of the Superior Acquisition that are included in the consolidated statements of operations for the year ended December 31, 2011 and the results of sales and operating income of the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions that are included in the consolidated statements of operations for the year ended December 31, 2012:

	Year Ended December 31,
	2012		2011
Sales	$	1,670,899	$	341,152
Operating income	$	186,406	$	17,963

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of the Company as if the Superior, Royal Purple and Montana Acquisitions had taken place on January 1, 2011.

	Year Ended December 31,
	2012		2011
Sales	$	5,064,795	$	4,804,528
Net income	$	234,601	$	103,114
Limited partners’ interest net income per unit — basic	$	3.86	$	1.75
Limited partners’ interest net income per unit — diluted	$	3.85	$	1.75

The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Superior, Royal Purple and Montana Acquisitions. 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.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

For the year ended December 31, 2012, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2020 Notes (defined below). The unaudited pro forma financial information reflects adjustments to increase amortization expense by $10,864 as a result of recording Royal Purple’s intangible assets.

For the year ended December 31, 2011, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2019 Notes and 2020 Notes (defined below), amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund a portion of the Superior and Montana Acquisitions and the repayment of borrowings under the prior term loan from the net proceeds of the 2019 Notes issued in April 2011. The unaudited pro forma financial information also reflects adjustments to increase amortization expense by $20,300 as a result of recording Royal Purple’s intangible assets.

Fair Value Measurements of Acquisitions

The fair value of the property, plant and equipment and intangible assets from acquisitions are based upon the discounted cash flow method that involves inputs that are not observable in the market (Level 3). Goodwill assigned represents the amount of consideration transferred in excess of the fair value assigned to individual assets acquired and liabilities assumed. 

4. Goodwill and Other Intangible Assets

Changes in goodwill balances are as follows:

	Year Ended December 31,
	2012						2011
	Specialty		Fuel				Specialty		Fuel
	Products		Products		Total		Products		Products		Total
Beginning balance:	$	48,335	$	—	$	48,335	$	48,335	$	—	$	48,335
Acquisitions	111,035		27,643		138,678		—		—		—
Accumulated impairment losses	—		—		—		—		—		—
Ending balance:	$	159,370	$	27,643	$	187,013	$	48,335	$	—	$	48,335

Other intangible assets consist of the following:

	Weighted Average Life (Years)	December 31, 2012					December 31, 2011
		Gross Amount		Accumulated Amortization			Gross Amount		Accumulated Amortization
Customer relationships	20	$	154,307	$	(22,612	)	$	28,482	$	(12,936	)
Supplier agreements	4	21,519		(21,519		)	21,519		(19,926		)
Tradenames - Royal Purple Retail	Indefinite	14,790		—			—		—
Tradenames	9	6,421		(550		)	—		—
Trade secrets	12	44,179		(3,116		)	—		—
Patents	12	1,573		(1,112		)	1,573		(966		)
Non-competition agreements	5	5,827		(5,780		)	5,732		(4,182		)
Distributor agreements	3	2,019		(2,019		)	2,019		(2,019		)
Royalty agreements	19	4,499		(1,343		)	4,499		(1,120		)
	16	$	255,134	$	(58,051	)	$	63,824	$	(41,149	)

Supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements are being amortized to properly match expense with the discounted estimated future cash flows over the terms of the related agreements. Agreements with terms allowing for the potential extension of such agreements are being amortized based on the initial term only. Customer relationships are being amortized using discounted estimated future cash flows based upon assumed rates of annual customer attrition. For the years ended December 31, 2012, 2011 and 2010, the Company recorded amortization expense of intangible assets of $16,902, $6,991 and $8,810, respectively.

The Company estimates that amortization of intangible assets for the next five years will be as follows:

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Year	Amortization Amount
2013	$	25,401
2014	$	24,297
2015	$	22,165
2016	$	20,217
2017	$	17,669
2018	$	14,904

5. Commitments and Contingencies

Operating Leases

The Company has various operating leases for the use of land, storage tanks, 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, 2012, 2011, and 2010 was $26,934, $20,490 and $17,104, respectively.

As of December 31, 2012, 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
2013	$	23,194
2014	14,937
2015	11,752
2016	7,946
2017	5,999
Thereafter	15,094
Total	$	78,922

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.

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 supplies the Superior refinery with a portion 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. In April 2012, the Company amended and restated the BP Purchase Agreement, which has an initial term of one year ending April 1, 2013, and 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. 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.

Certain other feedstocks are purchased under long-term supply contracts. The Company also purchases finished products from Houston Refining. 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. In addition, 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. The annual purchase commitment under these agreements is approximately $162,916.

As of December 31, 2012, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows:

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Year	Commitment
2013	$	999,146
2014	157,812
2015	937
2016	579
2017	—
Thereafter	—
Total	$	1,158,474

In connection with the Company’s acquisition of Penreco on January 3, 2008, the Company entered into a feedstock purchase agreement with Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, Phillips 66 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 $76,355 of feedstock for the LVT unit in each fiscal year of the term of the contract, expiring January 1, 2018, based on pricing estimates as of December 31, 2012. This amount is not included in the table above.

Labor Matters

The Company has approximately 580 employees covered by various collective bargaining agreements, or approximately 48.7% of its total workforce of approximately 1,190 employees. These agreements have expiration dates of March 31, 2013, April 30, 2013, April 30, 2014, October 31, 2014, January 31, 2015 and June 30, 2017. The Company has approximately 230 employees, or approximately 19.3% 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”), the Louisiana Department of Environmental Quality (“LDEQ”), the Wisconsin Department of Natural Resources (“WDNR”), the Montana Department of Environmental Quality (“MDEQ”), the Texas Commission on Environmental Quality (“TCEQ”), the Internal Revenue Service, various state and local departments of revenue and the federal Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.

Insurance Recoveries

During the second quarter 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 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.

95

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

In connection with the Montana Acquisition (see Note 3), the Company became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and MDEQ. The material obligations imposed by the Montana Consent Decree have been completed. Periodic reporting is the primary current obligation under the Montana Consent Decree. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previous Hazardous Waste Permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. The Company believes that all such contamination is subject to the indemnification of Montana Refining Company, Inc. by Holly Corporation (“Holly”) for pre-existing conditions. The Company is indemnified by Holly under the asset purchase agreement between Holly and Connacher, which the Company became a party to such indemnification rights through the share purchase agreement between the Company and Connacher. Holly is responsible for existing environmental conditions at the Montana refinery, and previously had been reimbursing Connacher for remedial actions subject to the indemnification.

Also, in connection with the Superior Acquisition, the Company became a party to an existing consent decree (“Superior Consent Decree”) with the EPA and the WDNR that applies, in part, to its Superior refinery. Under the Superior 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 the WDNR. The Company currently estimates costs of approximately $3,000 to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform required tasks under the Superior 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 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 federal 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 will result in the Company incurring additional costs, which could be substantial. During 2012 and 2011, the Company incurred approximately $2,379 and $2,270, respectively, of costs related to installing process equipment pursuant to the EPA fuel content regulations.

On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and attended an informal conference with the EPA held September 12, 2012. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial results or operations.

In addition, the Company is indemnified by Murphy Oil for specified environmental liabilities arising from the operations of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior 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 under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations prior to December 31, 2010. Among other things the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During 2012 and 2011, the Company incurred approximately $4,200 and $4,000, respectively, of expenditures and estimates additional expenditures of approximately $2,000 to $6,000 of capital expenditures and expenditures related to additional personnel and environmental studies over the next three years as a result of the implementation those requirements. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget, and the Company does not expect any additional

96

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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.

In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require the Company to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on June 1, 2012, the EPA issued final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. The Company is currently evaluating the effect that the NSPS rule may have on the Company’s refinery operations.

Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. Additionally, the Company incurred approximately $395, $338 and $541 in 2012, 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. 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.

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, 2012 and December 31, 2011, the Company incurred approximately $728 and $4,075, respectively, of capital expenditures and expects to incur between $1,000 and $4,000 of capital expenditures in 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.

97

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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, 2012 and December 31, 2011, the Company had outstanding standby letters of credit of $222,359 and $230,040, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 6 for additional information regarding the Company’s revolving credit facility. The maximum amount of letters of credit the Company could issue at December 31, 2012 and 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 in effect ($850,000 at December 31, 2012 and December 31, 2011).

As of December 31, 2012 and December 31, 2011, the Company had availability to issue letters of credit of $355,091 and $340,715, respectively, under its revolving credit facility. As discussed in Note 6, as of December 31, 2012 and 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.

6. Long-Term Debt

Long-term debt consisted of the following:

	December 31, 2012			December 31, 2011
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 9.91% for the year ended December 31, 2012	600,000			600,000
Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012	275,000			—
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	5,512			786
Less unamortized discounts	(17,011		)	(13,696		)
Total long-term debt	863,501			587,090
Less current portion of long-term debt	771			551
	$	862,730		$	586,539

9 5/8% Senior Notes

On June 29, 2012, in connection with the Royal Purple Acquisition, the Company issued and sold $275,000 in aggregate principal amount of 9 5/8% of senior notes due August 1, 2020 (the “2020 Notes”) in a private placement pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 98.25 percent of par. The 2020 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $262,565, net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Royal Purple Acquisition. Refer to Note 3 for additional information regarding the Royal Purple Acquisition.

Interest on the 2020 Notes is paid semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2013. The 2020 Notes will mature on August 1, 2020, unless redeemed prior to maturity. The 2020 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (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 2020 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 indenture governing the 2020 Notes. Since all Company’s operating subsidiaries guarantee the 2020 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.

98

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

At any time prior to August 1, 2015, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.625% 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 2020 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 August 1, 2016, the Company may on any one or more occasions redeem all or a part of the 2020 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 2020 Notes, if redeemed during the twelve-month period beginning on August 1 of the years indicated below:

Year	Percentage
2016	104.813	%
2017	102.406	%
2018 and at any time thereafter	100.000	%

Prior to August 1, 2016, the Company may on any one or more occasions redeem all or part of the 2020 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2020 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

The indenture governing the 2020 Notes contains covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2020 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2020 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 2020 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 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.

On June 29, 2012, in connection with the issuance and sale of the 2020 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2020 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC, so that holders of the 2020 Notes can offer to exchange the 2020 Notes for registered notes having substantially the same terms as the 2020 Notes and evidencing the same indebtedness as the 2020 Notes. The Company must use reasonable best efforts to cause the exchange offer registration statement to become effective by June 28, 2013 and remain effective until 180 days after the closing of the exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2020 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2020 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

9 3/8% 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 9 3/8% 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.

99

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

On September 19, 2011, in connection with the Superior Acquisition, the Company issued and sold $200,000 in aggregate principal amount of 9 3/8% 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. 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.”

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 the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (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 both Moody’s Investors Service, Inc. and 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.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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

The Company has an $850,000 senior secured revolving credit facility, which is its primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility 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, 2012, the margin was 100 basis points for prime and 225 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s 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
≥ 66%	1.00%	2.25%
≥ 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 either 0.375% or 0.50% per annum depending on the average daily available unused borrowing capacity for the preceding month. 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, 2012 under the revolving credit facility was $577,450. As of December 31, 2012, the Company had no outstanding borrowings under the revolving credit facility, leaving $355,091 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

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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.

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 has also issued to one counterparty a $25,000 standby letter of credit under the revolving credit facility. 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, 2012 and 2011. The Company’s master derivatives contracts and Collateral Trust Agreement (as defined below) 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.

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 from time to time.

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 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.

Maturities of Long-Term Debt

As of December 31, 2012, maturities of the Company’s long-term debt are as follows:

Year	Maturity
2013	$	771
2014	423
2015	303
2016	328
2017	355
Thereafter	878,332
Total	$	880,512

Capital Lease Obligations

The Company has a capital lease obligation for catalysts used in refining processes which will expire in 2013. In connection with the TruSouth Acquisition, the Company recorded $5,771 of capital leases for a building and equipment that will expire in 2027 and 2018, respectively. Assets recorded under these capital lease obligations are included in property, plant

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

and equipment and consist of $11,071 and $4,201 as of December 31, 2012 and 2011, respectively. As of December 31, 2012 and 2011, the Company had recorded $4,251 and $3,221, respectively, in accumulated depreciation for these capital lease assets.

As of December 31, 2012, the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows:

Year	Capital Leases
2013	$	1,189
2014	805
2015	661
2016	661
2017	661
Thereafter	4,789
Total minimum lease payments	8,766
Less amount representing interest	3,254
Capital lease obligations	5,512
Less obligations due within one year	771
Long-term capital lease obligations	$	4,741

7. Derivatives

The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment) and natural gas. The Company uses various strategies to reduce the exposure to commodity price risk. The Company does not attempt to eliminate all of the Company’s risk due to the cost of such actions are believed to be too high in relation to the risk posed to the Company’s future cash flows, earnings and liquidity. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments such as swaps, futures and options to attempt to reduce the Company’s exposure with respect to:

• crude oil purchases;

• refined product sales;

• natural gas purchases; and

• fluctuations in the value of crude oil between geographic regions and in between the different types of crude oil such as NYMEX WTI, Light Louisiana Sour (“LLS”) and Western Canadian Select (“WCS”).

The Company does not hold or issue derivative instruments for trading purposes.

The Company recognizes all derivative instruments at their fair values (see Note 8) as either current assets or current 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 no longer qualifying it for hedge accounting. The Company recorded the following derivative assets and liabilities at their fair values as of December 31, 2012 and 2011:

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

	Derivative Assets						Derivative Liabilities
	December 31, 2012			December 31, 2011			December 31, 2012			December 31, 2011
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	10,517		$	83,919		$	(26,743	)	$	56,041
Gasoline swaps	273			(20,605		)	2,086			(1,596		)
Diesel swaps	(7,871		)	(4,561		)	(10,331		)	(22,586		)
Jet fuel swaps	169			1,077			(2,298		)	(72,537		)
Total derivative instruments designated as hedges	3,088			59,830			(37,286		)	(40,678		)
Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps	—			—			(10,725		)	—
Crude oil basis swaps	—			—			(3,363		)	—
Gasoline swaps	—			—			(2,171		)	—
Diesel swaps	—			—			3,928			—
Specialty products segment: (1)
Crude oil swaps	—			—			1,649			—
Natural gas swaps (2)	—			(1,328		)	—			(1,892		)
Interest rate swaps: (3)	—			—			—			(1,011		)
Total derivative instruments not designated as hedges	—			(1,328		)	(10,682		)	(2,903		)
Total derivative instruments	$	3,088		$	58,502		$	(47,968	)	$	(43,581	)

(1) 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.

(2) The Company periodically enters into 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 for the interest payments under the previous term loan facility are no longer designated as cash flow hedges.

The Company accounts for certain derivatives hedging purchases of crude oil, sales of gasoline, diesel and jet fuel 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. Periodically, the Company may enter into crude oil or fuel product basis swaps to more effectively hedge its crude oil purchases.  These derivatives can be combined with a swap contract in order to create a more effective hedge.  The Company has entered into crude oil basis swaps for 2013 that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract.

To the extent a derivative instrument designated as a hedge 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. Hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to unrealized gain (loss) on derivative

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

instruments in the consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously accumulated in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments.

Effective January 1, 2012, hedge accounting was discontinued prospectively for certain crude oil derivative instruments when it was determined that they were no longer highly effective in offsetting changes in the cash flows associated with crude oil purchases at the Company’s Superior refinery due to the volatility in crude oil pricing differentials between heavy crude oil and NYMEX WTI. Effective April 1, 2012, hedge accounting was discontinued prospectively for certain gasoline and diesel derivative instruments associated with gasoline and diesel sales at the Company’s Superior refinery. The discontinuance of hedge accounting on these derivative instruments has caused the Company to recognize derivative gains of $40,096 in realized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012. The discontinuance of hedge accounting on these derivative instruments caused the Company to recognize derivative losses $2,933 in unrealized loss on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012.

The amount reclassified from accumulated other comprehensive income (loss) into earnings, as a result of the discontinuance of hedge accounting for certain jet fuel products derivative instruments because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, has caused the Company to recognize derivative losses of $1,719 in realized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012.

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 has resulted, 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 cash flows.

The Company recorded the following amounts in its consolidated balance sheets, consolidated statements of operations, consolidated statements of other comprehensive income (loss) and its consolidated statements of partners’ capital as of, and for the years ended December 31, 2012 and 2011 related to its derivative instruments that were designated as cash flow hedges:

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

	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 Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)
	Year Ended December 31,						Location of (Gain) Loss	Year Ended December 31,						Location of Gain (Loss)	Year Ended December 31,
Type of Derivative	2012			2011				2012			2011				2012			2011
Fuel products segment:
Crude oil swaps	$	(99,960	)	$	133,060		Cost of sales	$	(49,874	)	$	(110,945	)	Unrealized/Realized	$	99,672		$	(8,159	)
Gasoline swaps	(15,981		)	(38,289		)	Sales	38,388			29,468			Unrealized/Realized	(52,038		)	(1,850		)
Diesel swaps	(59,260		)	(53,622		)	Sales	62,966			79,810			Unrealized/Realized	(10,518		)	(573		)
Jet fuel swaps	(39,931		)	(77,288		)	Sales	104,482			102,473			Unrealized/Realized	(123		)	(2,715		)
Specialty products segment:
Crude oil swaps	—			—			Cost of sales	(1,877		)	2,512			Unrealized/Realized	—			—
Natural gas swaps	—			—			Cost of sales	—			—			Unrealized/Realized	—			—
Interest rate swaps:	—			1,979			Interest  expense	—			702			Unrealized/Realized	—			—
Total	$	(215,132	)	$	(34,160	)		$	154,085		$	104,020			$	36,993		$	(13,297	)

The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2012 and 2011 related to its derivative instruments not designated as cash flow hedges:

	Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivatives Year Ended December 31,						Amount of Gain (Loss) Recognized in Unrealized Loss on Derivatives Year Ended December 31,
Type of Derivative	2012			2011			2012			2011
Fuel products segment:
Crude oil swaps	$	(30,488	)	$	—		$	(39,967	)	$	—
Crude oil basis swaps	2,066			—			(3,363		)	—
Gasoline swaps	22,110			—			519			—
Diesel swaps	10,895			—			8,912			—
Jet fuel swaps	(1,719		)	—			—			—
Jet fuel collars	—			(746		)	—			726
Specialty products segment:
Crude oil swaps	—			932			1,649			(662		)
Natural gas swaps	(5,442		)	(171		)	3,221			(3,221		)
Interest rate swaps:	(732		)	(2,124		)	1,011			271
Total	$	(3,310	)	$	(2,109	)	$	(28,018	)	$	(2,886	)

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 derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of December 31, 2012, the Company had two counterparties, for which the derivatives held were net assets, totaling $3,088.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa2 and A- by Moody’s and S&P, respectively. In the event of default, the Company potentially would 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, 2012 or December 31, 2011. 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, 2012 and 2011, the Company had provided its counterparties with no collateral except for a $25,000 letter of credit 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, 2012 and 2011, there was a net liability of $7,515 and a net asset of $3,561, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, certain 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 cash flow hedges classified in accumulated other comprehensive loss was $13,953 as of December 31, 2012. The effective portion of the cash flow hedges classified in accumulated other comprehensive income was $47,094 as of December 31, 2011. Absent a change in the fair market value of the underlying transactions, the following other comprehensive income (loss) at December 31, 2012 will be reclassified to earnings by December 31, 2015 with balances being recognized as follows:

Year	Accumulated Other Comprehensive Income (Loss)
2013	$	(7,755	)
2014	(7,789		)
2015	1,591
Total	$	(13,953	)

Based on fair values as of December 31, 2012, the Company expects to reclassify $7,755 of net losses on derivative instruments from accumulated other comprehensive loss 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 dates of settlements.

Crude Oil Swap Contracts — Specialty Products Segment

As of December 31, 2012, the Company had purchased a crude oil swap for 200,000 bbls in the second quarter of 2012 related to future crude oil purchases in its specialty products segment, which is not designated as a cash flow hedge. The Company subsequently sold a crude oil derivative swap in the third quarter of 2012, and the net impact of these two derivatives is a net gain of $1,649 that has been recorded to unrealized loss in the consolidated statements of operations for the year ended December 31, 2012. This gain will be realized in January 2013 upon settlement and will be recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations.

At December 31, 2011, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Natural Gas Swap Contracts

At December 31, 2012, the Company did not have any natural gas derivatives related to natural gas purchases in its specialty products segment.

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

Crude Oil Contracts — Fuel Products Segment

Crude Oil Swap Contracts

At December 31, 2012, 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 2013	1,665,000	18,500	$	101.67
Second Quarter 2013	1,911,000	21,000	100.22
Third Quarter 2013	1,426,000	15,500	95.62
Fourth Quarter 2013	1,104,000	12,000	93.41
Calendar Year 2014	5,110,000	14,000	89.47
Calendar Year 2015	4,781,500	13,100	89.49
Totals	15,997,500
Average price			$	92.85

At December 31, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as cash flow hedges.

Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Swap ($/Bbl)
First Quarter 2013	630,000	7,000	$	101.34
Second Quarter 2013	455,000	5,000	98.56
Third Quarter 2013	368,000	4,000	96.58
Fourth Quarter 2013	368,000	4,000	96.58
Totals	1,821,000
Average price			$	98.72

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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, 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

Crude Oil Basis Swap Contracts

In April, July and December 2012, the Company entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between Canadian heavy crude oil and NYMEX WTI crude oil. At December 31, 2012, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as cash flow hedges.

Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Differential to NYMEX WTI ($/Bbl)
First Quarter 2013	180,000	2,000	$	(23.75	)
Second Quarter 2013	364,000	4,000	(27.38		)
Third Quarter 2013	184,000	2,000	(23.75		)
Fourth Quarter 2013	184,000	2,000	(23.75		)
Totals	912,000
Average differential			$	(25.20	)

At December 31, 2011, the Company had no derivatives related to crude oil basis swaps in its fuel products segment.

Fuel Products Swap Contracts

Diesel Swap Contracts

At December 31, 2012, 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)
Second Quarter 2013	546,000	6,000	$	122.74
Third Quarter 2013	874,000	9,500	122.23
Fourth Quarter 2013	828,000	9,000	120.82
Calendar Year 2014	3,835,000	10,507	116.00
Calendar Year 2015	4,781,500	13,100	115.81
Totals	10,864,500
Average price			$	117.13

At December 31, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Diesel Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
First Quarter 2013	540,000	6,000	$	130.57
Second Quarter 2013	364,000	4,000	126.82
Third Quarter 2013	276,000	3,000	124.17
Fourth Quarter 2013	276,000	3,000	124.17
Totals	1,456,000
Average price			$	127.20

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

Jet Fuel Swap Contracts

At December 31, 2012, 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 2013	1,035,000	11,500	$	127.39
Second Quarter 2013	819,000	9,000	129.20
Third Quarter 2013	368,000	4,000	125.13
Fourth Quarter 2013	276,000	3,000	122.36
Calendar Year 2014	1,275,000	3,493	116.64
Totals	3,773,000
Average price			$	123.56

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

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Gasoline Swap Contracts

At December 31, 2012, 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 2013	630,000	7,000	$	113.59
Second Quarter 2013	546,000	6,000	116.32
Third Quarter 2013	184,000	2,000	114.73
Totals	1,360,000
Average price			$	114.84

At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.

Gasoline Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
First Quarter 2013	90,000	1,000	$	105.50
Second Quarter 2013	91,000	1,000	105.50
Third Quarter 2013	92,000	1,000	105.50
Fourth Quarter 2013	92,000	1,000	105.50
Totals	365,000
Average price			$	105.50

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

Interest Rate Swap Contracts

The Company has no variable rate debt and no interest rate swaps outstanding as of December 31, 2012. For the Company’s fixed rate 2019 and 2020 Notes, changes in interest rates will generally affect the fair value, but not the Company’s interest expense or cash flows.

8. Fair Value Measurements

The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:

• Level 1—inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities

• Level 2—inputs include other than quoted prices in active markets that are either directly or indirectly observable

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

• Level 3—inputs include 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.

Recurring Fair Value Measurements

Derivative Assets and Liabilities

Derivative instruments are reported in the accompanying consolidated financial statements at fair value. 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 Baa2 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, crude oil basis, gasoline, diesel, jet fuel, natural gas and interest rate swaps 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, 2012, the Company’s asset was reduced by $100 and liability was reduced by approximately $185. As a result of applying the CDS at December 31, 2011, the Company’s asset was reduced by $1,297 and the liability was reduced by approximately $165.

Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for crude oil, crude oil basis, gasoline, jet fuel, diesel, natural gas and interest rate swaps, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. 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. See Note 7 for further information on derivative instruments.

Pension Assets    

Pension assets are reported at fair value using quoted market prices in the accompanying consolidated financial statements. The Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded, (iii) a commingled fund and (iv) a balanced fund. The mutual and balanced funds are publicly 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 quarter end. See Note 11 for further information on pension assets.

Liability Awards

The fair values of the Company’s Liability Awards are updated each balance sheet date based on the closing unit price on the balance sheet date. See Note 10 for further information on Liability Awards.

Hierarchy of Recurring Fair Value Measurements

The Company’s recurring assets and liabilities measured at fair value at December 31, 2012 and December 31, 2011 were as follows:

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

	December 31, 2012											December 31, 2011
	Level 1			Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets:
Derivative assets:
Crude oil swaps	—			—		10,517			10,517			—		—		83,919			83,919
Gasoline swaps	—			—		273			273			—		—		(20,605		)	(20,605		)
Diesel swaps	—			—		(7,871		)	(7,871		)	—		—		(4,561		)	(4,561		)
Jet fuel swaps	—			—		169			169			—		—		1,077			1,077
Natural gas swaps	—			—		—			—			—		—		(1,328		)	(1,328		)
Total derivative assets	—			—		3,088			3,088			—		—		58,502			58,502
Pension plan investments	38,835			2,731		—			41,566			33,580		2,462		—			36,042
Total recurring assets at fair value	$	38,835		$	2,731	$	3,088		$	44,654		$	33,580	$	2,462	$	58,502		$	94,544
Liabilities:
Derivative liabilities:
Crude oil swaps	$	—		$	—	$	(35,819	)	(35,819		)	$	—	$	—	$	56,041		$	56,041
Crude oil basis swaps	—			—		(3,363		)	(3,363		)	—		—		—			—
Gasoline swaps	—			—		(85		)	(85		)	—		—		(1,596		)	(1,596		)
Diesel swaps	—			—		(6,403		)	(6,403		)	—		—		(22,586		)	(22,586		)
Jet fuel swaps	—			—		(2,298		)	(2,298		)	—		—		(72,537		)	(72,537		)
Natural gas swaps	—			—		—			—			—		—		(1,892		)	(1,892		)
Interest rate swaps	—			—		—			—			—		—		(1,011		)	(1,011		)
Total derivative liabilities	—			—		(47,968		)	(47,968		)	—		—		(43,581		)	(43,581		)
Liability Awards	$	(2,239	)	$	—	$	—		$	(2,239	)	—		—		—			—
Total recurring liabilities at fair value	$	(2,239	)	$	—	$	(47,968	)	$	(50,207	)	$	—	$	—	$	(43,581	)	$	(43,581	)

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the year ended December 31, 2012 and 2011:

	Derivative Instruments, Net
	For the Year Ended December 31,
	2012			2011
Fair value at January 1,	$	14,921		$	(32,814	)
Realized (gain) loss on derivative instruments	(9,452		)	7,909
Unrealized loss on derivative instruments	(3,787		)	(10,383		)
Change in fair value of cash flow hedges	(215,132		)	(34,160		)
Settlements	168,570			84,369
Transfers in (out) of Level 3	—			—
Fair value at December 31,	$	(44,880	)	$	14,921
Total loss included in net income attributable to changes in unrealized loss relating to financial assets and liabilities held as of December 31,	$	(3,787	)	$	(10,383	)

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 instruments are recorded in earnings in realized gain (loss)

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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 7 for further information on derivative instruments.

Nonrecurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. Refer to Note 3 for the fair values of assets acquired and liabilities assumed in connection with the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions.

The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. 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. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 4 for further information on goodwill.

The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived and indefinite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 4 for further information on long-lived assets.

Estimated Fair Value of Financial Instruments

Cash

The carrying values of cash are considered to be representative of their respective fair values.

Debt

The estimated fair value of long-term debt at December 31, 2012 consists primarily of the 2019 Notes and 2020 Notes. The estimated fair value of long-term debt at December 31, 2011 consists primarily of the 2019 Notes. The fair values of the Company’s 2019 Notes were based upon using quoted market prices in an active market and are classified as Level 1. The fair values of the Company’s 2020 Notes were based upon directly observable inputs and are classified as Level 2. The carrying value of borrowings, if any, under the Company’s revolving credit facility approximates its fair value as determined by discounted cash flows and is classified as Level 3. Capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 6 for further information on long-term debt.

The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at December 31, 2012 and December 31, 2011 were as follows:

	December 31, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial Instrument:
2019 Notes	$	658,795	$	587,602	$	591,750	$	586,304
2020 Notes	$	301,813	$	270,387	$	—	$	—
Capital lease and other obligations	$	5,512	$	5,512	$	786	$	786

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

9. Partners’ Capital

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

On February 24, 2011, the Company completed 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.

On May 8, 2012, the Company completed a public offering of its common units in which it sold 6,000,000 common units to the underwriters of the offering at a price to the public of $25.50 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 $146,558 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $6,180. The Company’s general partner contributed $3,122 to maintain its 2% general partner interest.

Of the 57,529,778 common units outstanding at December 31, 2012, 39,397,092 common units were held by the public, with the remaining 18,132,686 common units held by the Company’s affiliates.

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 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Any holder, other than the general partner or the general partner’s affiliates, that owns 20% or more of any class of units outstanding, cannot vote on any matter.

• 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.

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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 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 and 2020 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 (i) a $70,000 basket for the 2019 Notes and (ii) a $120,000 for the 2020 Notes, 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, 2012, 2011 and 2010, the Company made distributions of $132,400, $82,743 and $65,739, respectively, to its partners. For the years ended December 31, 2012, 2011 and 2010, the general partner was allocated $5,433, $322 and $0, respectively, in incentive distribution rights.

10. 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 the Company’s general partner have been granted phantom units under the terms of the Plan as part of their director compensation package related to fiscal years 2010, 2011 and 2012. 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, 2012 and 2011, 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 during the performance period, 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 have DERs on these phantom units from the date of grant.

The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and 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.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

Liability Awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units. Phantom unit Liability Awards are recorded in accrued salaries, wages and benefits in the consolidated balance sheets based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense within general and administrative expense in the consolidated statements of operations.

A summary of the Company’s nonvested phantom units as of December 31, 2012, and the changes during the years ended December 31, 2012, 2011 and 2010, are presented below:

	Number of Phantom Units		Weighted-Average Grant Date Fair Value
Non-vested at January 1, 2010	57,493		$	12.42
Granted	138,490		20.11
Vested	(90,491	)	18.05
Forfeited	—		—
Non-vested at December 31, 2010	105,492		$	17.68
Granted	640,875		20.26
Vested	(183,671	)	20.29
Forfeited	—		—
Non-vested at December 31, 2011	562,696		$	19.77
Granted	616,997		26.69
Vested	(286,976	)	21.16
Forfeited	(56,790	)	20.00
Non-vested at December 31, 2012	835,927		$	27.57

For the years ended December 31, 2012, 2011 and 2010, compensation expense of $4,583, $3,027 and $784, respectively, was recognized in the consolidated statements of operations related to vested phantom unit grants, including $2,239 attributable to Liability Awards for the year ended December 31, 2012. As of December 31, 2012 and 2011, there was a total of $23,044 and $11,124, respectively of unrecognized compensation costs related to nonvested phantom unit grants, including $16,139 attributable to Liability Awards for the year ended December 31, 2012. 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, 2012 and 2011, was $6,083 and $3,727, respectively.

11. Employee Benefit Plans

The Company has two domestic defined contribution plans administered by its general partner for (i) all full-time employees that are eligible to participate in the plan (“Calumet 401k Plan”) and (ii) all Montana union employees that are eligible to participate in the plan (“Montana 401k Plan”). Participants in the Calumet 401k Plan 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% of eligible compensation contribution by the participant up to 4% and 50% of each additional 1% eligible compensation contribution up to 6%, for a maximum contribution by the Company of 5% of eligible compensation contributions per participant. Participants in the Montana 401k Plan are allowed to contribute pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% contribution by the participant up to 6% for a maximum contribution. The Company’s matching contributions expenses were $3,224, $2,343 and $1,948 for 2012, 2011 and 2010, respectively. The plans also include a profit-sharing component for eligible employees. 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 $2,511, $1,448 and $1,331 for 2012, 2011 and 2010, respectively.

The Company has domestic noncontributory defined benefit plans for 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”), (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”) or (iii) were former employees of Montana Refining

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(Dollars in thousands, except per unit data)

Company, Inc. and who became employees of the Company as a result of the Montana Acquisition on October 1, 2012 (the “Montana Pension Plan” and together with the Penreco Pension Plan and the Superior Pension Plan, the “Pension Plan”).

Under the Penreco Pension Plan and Superior Pension Plan benefits are based primarily on years of service for USW and IUOE represented employees and the employee’s final 60 months’ average compensation for salaried employees. Under the Montana Pension plan benefits are based primarily on years of service and the employees’ 36 months’ highest 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 balanced fund, a commingled fund and cash and cash equivalents.

The Company also has domestic contributory defined benefit post retirement 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.”

In 2009, the Company amended the Penreco Pension Plan, which curtailed Penreco employees from accumulating additional benefits subsequent to December 31, 2009.

Effective July 1, 2012, the Company amended the Superior Pension Plan and Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012. For the year ended December 31, 2012, the Company recorded a $218 curtailment gain related to the Superior Pension Plan and a $6,983 curtailment gain related to the Superior Other Plan, all of which is recorded in general and administrative expense in the consolidated statements of operations. All information presented below has been adjusted for this curtailment.

Effective October 1, 2012, the date of the Montana Acquisition, the Company amended the Montana Pension Plan, which curtailed only the Montana salaried employees from accumulating additional benefits subsequent to October 31, 2012. All information presented below has been adjusted for these curtailments.

During 2012, the Company made contributions of $3,076 to its Pension Plan and $29 to its Other Plan. The Company expects to make contributions in 2013 of approximately $4,402 to its Pension Plan and $59 to its Other Plan.

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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,
	2012						2011
	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	$	55,265		$	7,734		$	24,761		$	446
Projected benefit obligation attributable to acquisitions	4,900			—			26,218			6,477
Service cost	1,130			287			296			114
Interest cost	2,376			185			1,638			96
Plan curtailments	(3,685		)	(7,873		)	—			—
Benefits paid	(2,607		)	(80		)	(1,162		)	(81		)
Actuarial loss	7,897			106			3,554			624
Administrative expense	(40		)	—			(40		)	—
Plan amendments	—			(81		)	—			—
Employee contributions	—			51			—			58
Benefit obligation at end of year	$	65,236		$	329		$	55,265		$	7,734
Change in plan assets:
Fair value of plan assets at beginning of year	$	36,042		$	—		$	16,039		$	—
Fair value of pension assets attributable to acquisitions	3,178			—			17,718			—
Benefit payments	(2,607		)	(80		)	(1,162		)	(81		)
Actual return on assets	1,917			—			1,568			—
Administrative expense	(40		)	—			(40		)	—
Employee contributions	—			51			—			58
Employer contribution	3,076			29			1,919			23
Fair value of plan assets at end of year	$	41,566		$	—		$	36,042		$	—
Funded status — benefit obligation in excess of plan assets	$	(23,670	)	$	(329	)	$	(19,223	)	$	(7,734	)
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	$	(23,670	)	$	(329	)	$	(19,223	)	$	(7,734	)
Prior service credit	—			(240		)	—			(275		)
Unrecognized net actuarial loss (gain)	11,927			(161		)	8,289			553
Accumulated other comprehensive (income) loss	11,927			(401		)	8,289			278
Net amount recognized at end of year	$	(11,743	)	$	(730	)	$	(10,934	)	$	(7,456	)

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(Dollars in thousands, except per unit data)

The accumulated benefit obligation for the Pension Plan was $63,429 and $52,543 as of December 31, 2012 and 2011, respectively. The accumulated benefit obligation for the Pension Plan was more than plan assets by $21,863 and $16,501 as of December 31, 2012 and 2011, respectively. Selected information for the Company’s Pension Plan with an accumulated benefit obligation in excess of plan assets were as follows:

	Year Ended December 31,
	2012		2011
Projected benefit obligation	$	65,236	$	55,265
Accumulated benefit obligation	$	63,429	$	52,543
Fair value of plan assets	$	41,566	$	36,042

The components of net periodic pension cost and other post retirement benefits cost 2012, 2011 and 2010 were as follows:

	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011			2010
Service cost	$	1,130		$	296		$	84		$	287		$	114		$	—
Interest cost	2,376			1,638			1,336			185			96			23
Expected return on assets	(1,704		)	(1,347		)	(1,034		)	—			—			—
Amortization of net (gain) loss	578			281			274			(7		)	(2		)	(3		)
Amortization of prior service cost	—			—			—			(39		)	(35		)	(35		)
Curtailment gain recognized	(218		)	—			—			(6,983		)	—			—
Settlement gain recognized	—			—			—			(141		)	—			—
Net periodic pension cost	$	2,162		$	868		$	660		$	(6,698	)	$	173		$	(15	)

The components of changes recognized in other comprehensive income for the Pension Plan and Other Plan for 2012, 2011 and 2010 were as follows:

	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011		2010
Changes in plan assets and benefit obligations recognized in other comprehensive income:
Net loss	$	4,216		$	3,334		$	695		$	106		$	624	$	30
New prior service cost	—			—						(81		)	—		(345		)
Amounts recognized as a component of net periodic benefit cost:
Amortization or settlement recognition of net (loss) gain	(578		)	(281		)	(274		)	(820		)	2		3
Amortization or curtailment recognition of prior service credit	—			—			—			116			35		35
Total recognized in other comprehensive loss (income)	$	3,638		$	3,053		$	421		$	(679	)	$	661	$	(277	)
Total recognized in net periodic benefit and other comprehensive loss (income)	$	5,800		$	3,921		$	1,081		$	(7,377	)	$	834	$	(292	)

The portion relating to the Pension Plan and Other Plan classified in accumulated other comprehensive loss is $11,526 and $8,567 as of December 31, 2012 and 2011, respectively. In 2013, the estimated amount that will be amortized from accumulated other comprehensive income includes a loss of $817 for the Pension Plan. Also in 2013, the estimated amounts

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(Dollars in thousands, except per unit data)

that will be amortized from accumulated other comprehensive income include a gain of $8 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, 2012 and 2011 were as follows:

	Benefit Obligations Assumptions
	2012		2011
Pension Plan:
Discount rate	3.83	%	4.59	%
Rate of compensation increase for Penreco Pension Plan	N/A		N/A
Rate of compensation increase for Superior Pension Plan	N/A		3.75	%
Rate of compensation increase for Montana Pension Plan	3.00	%	N/A
Other Plan:
Discount rate for Penreco Other Plan	3.33	%	4.04	%
Discount rate for Superior Other Plan	N/A		4.65	%
Immediate trend rate for Penreco Other Plan (1)	7.70	%	8.00	%
Immediate trend rate for Superior Other Plan (2)	N/A		8.00	%
Ultimate trend rate for Penreco Other Plan (1)	4.50	%	4.50	%
Ultimate trend rate for Superior Other Plan (2)	N/A		4.50	%
Year that the rate reaches ultimate trend rate for Penreco Other Plan (1)	2029		2029
Year that the rate reaches ultimate trend rate for Superior Other Plan (2)	N/A		2029

(1) For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% in 2029 for the Penreco Other Plan and remain at that level thereafter.

(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% in 2029 for the Superior Other Plan and remain at that level thereafter. Effective July 1, 2012, the Company amended the Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012.

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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, 2012 and 2011 were as follows:

	Net Periodic Benefit Cost Assumptions
	2012		2011		2010
Pension Plan:
Discount rate for Penreco Pension Plan	4.63	%	5.50	%	6.04	%
Discount rate for Superior Pension Plan	4.55	%	4.71	%	N/A
Discount rate for Montana Pension Plan	3.89	%	N/A		N/A
Expected return on plan assets for Penreco Pension Plan (1)	6.00	%	6.50	%	7.50	%
Expected return on plan assets for Superior Pension Plan (1)	3.00	%	6.50	%	N/A
Expected return on plan assets for Montana Pension Plan (1)	6.00	%	N/A		N/A
Rate of compensation increase for Penreco Pension Plan	N/A		N/A		N/A
Rate of compensation increase for Superior Pension Plan	3.75	%	3.75	%	N/A
Rate of compensation increase for Montana Pension Plan	3.00	%	N/A		N/A
Other Plan:
Discount rate for Penreco Other Plan	4.04	%	4.54	%	5.55	%
Discount rate for Superior Other Plan	4.65	%	4.82	%	N/A
Immediate trend rate (2)	8.00	%	8.20	%	8.40	%
Ultimate trend rate for Penreco Other Plan (2)	4.50	%	4.50	%	4.50	%
Ultimate trend rate for Superior Other Plan (2)	4.50	%	5.00	%	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)	2029		2020		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 2012. 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.

An increase or decrease by one percentage point in the assumed healthcare cost trend rates would have the following effect on the post retirement benefit obligation and service and interest cost components of benefit costs for the Other Plan as of December 31, 2012:

	1% Point Increase		1% Point Decrease
Increase (decrease) in:
Effect on total of service and interest cost components of benefit costs	$	110	$	(85	)
Effect on post retirement benefit obligation	$	5	$	(4	)

Investment Policy

The Company’s 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 the Company’s 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 the Company’s investment objectives, ensure risk control, and limit concentrations.

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(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, 2012 and 2011 by asset category, are as follows:

	2012		2011
	Pension Benefits		Pension Benefits
Cash and cash equivalents (1)	47	%	62	%
Equity	14	%	11	%
Foreign equities	5	%	2	%
Fixed income	20	%	18	%
Balanced fund	7	%	—	%
Commingled fund	7	%	7	%
	100	%	100	%

(1) The Superior Pension Plan assets are included in cash and cash equivalents and such assets will be invested in 2013 based upon the current investment policy.

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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, (iii) a commingled fund and (iv) a balanced fund. The mutual and balanced 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 8 for the definition of Levels 1, 2 and 3. The Company’s Pension Plan assets measured at fair value at December 31, 2012 and 2011 were as follows:

	Fair Value of Pension Assets at December 31,
	2012				2011
	Level 1		Level 2		Level 1		Level 2
Cash and cash equivalents	$	19,295	$	—	$	22,243	$	—
Equity	5,900		—		4,000		—
Foreign equities	2,268		—		691		—
Commingled fund	—		2,731		—		2,462
Balanced fund	2,961		—		—		—
Fixed income	8,411		—		6,646		—
	$	38,835	$	2,731	$	33,580	$	2,462

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2012:

	Pension Benefits		Other Post Retirement Employee Benefits
2013	$	2,402	$	59
2014	2,504		44
2015	2,608		41
2016	2,720		25
2017	2,813		16
2018 to 2022	16,355		72
Total	$	29,402	$	257

12. Earnings per Unit

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended December 31, 2012, 2011 and 2010:

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(Dollars in thousands, except per unit data)

	Year Ended December 31,
	2012		2011		2010
	(In thousands, except unit data)
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	205,737	$	43,036	$	16,701
General partner’s interest in net income	4,115		861		334
General partner’s incentive distribution rights	5,433		322		—
Nonvested share based payments	1,199		—		—
Net income available to limited partners	$	194,990	$	41,853	$	16,367
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average limited partner units outstanding	55,559		42,599		35,335
Effect of dilutive securities:
Participating securities — phantom units	118		45		16
Diluted weighted average limited partner units outstanding	55,677		42,644		35,351
Limited partners’ interest basic net income per unit	$	3.51	$	0.98	$	0.46
Limited partners’ interest diluted net income per unit	$	3.50	$	0.98	$	0.46

13. Transactions with Related Parties

During the years ended December 31, 2012, 2011 and 2010, the Company had product sales to related parties owned by a limited partner of $9,309, $16,500 and $4,727, respectively. Trade accounts and other receivables from related parties at December 31, 2012 and 2011 were $139 and $1,818, 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”) and director’s and officers’ liability insurance premiums discussed below, during the years ended December 31, 2012, 2011 and 2010 of $7,181, $1,768 and $1,480, respectively. Accounts payable to related parties, excluding accounts payable related to the Legacy Resources agreements discussed below, at December 31, 2012 and 2011 were $2,230 and $1,393, 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 the Company’s 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 Resources (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 Resources, 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, 2012 and 2011 and 2010, the Company had crude oil purchases of $1,120, $229,793 and $591,777, respectively, from Legacy Resources. Accounts payable to Legacy Resources at December 31, 2012 and 2011 were $96 and $574, respectively.

Nicholas J. Rutigliano, a member of the board of directors of the Company’s general partner, founded and is the president of Tobias Insurance Group, Inc. (“Tobias”), a commercial insurance brokerage business that has historically placed the Company’s directors’ and officers’ liability insurance. The total premiums paid to Tobias by the Company for the years ended December 31, 2012, 2011 and 2010 were $510, $566 and $638, 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, 2012, 2011 and 2010.

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(Dollars in thousands, except per unit data)

14. Segments and Related Information

a. Segment Reporting

The Company has two reportable segments: specialty products and fuel products. The specialty products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants, asphalt and other by-products. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The specialty products segment also blends and markets through the Company’s brand Royal Purple. 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, Canada, Idaho, Iowa, Louisiana, Michigan, Minnesota, Montana, North Dakota, South Dakota, 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 and Montana Acquisitions have been included since the date of acquisition, September 30, 2011 and October 1, 2012, respectively. The assets and results of operations from such assets acquired as a result of the Missouri, TruSouth and Royal Purple Acquisitions have been included in the specialty products segment since their dates of acquisition, January 3, 2012, January 6, 2012 and July 3, 2012, respectively.

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(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 in Note 2. 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, 2012	Specialty Products		Fuel Products			Combined Segments		Eliminations			Consolidated Total
Sales:
External customers	$	2,231,602	$	2,425,680		$	4,657,282	$	—		$	4,657,282
Intersegment sales	1,153,095		73,545			1,226,640		(1,226,640		)	—
Total sales	$	3,384,697	$	2,499,225		$	5,883,922	$	(1,226,640	)	$	4,657,282
Depreciation and amortization	84,648		20,377			105,025		—			105,025
Operating income	125,710		160,218			285,928		—			285,928
Reconciling items to net income:
Interest expense											(85,573		)
Gain on derivative instruments											5,665
Other											470
Income tax expense											(753		)
Net income											$	205,737
Capital expenditures	$	41,686	$	15,367		$	57,053	$	—		$	57,053
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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

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		)
Loss on derivative instruments											(23,547		)
Other											(147		)
Income tax expense											(598		)
Net income											$	16,701
Capital expenditures	$	35,001	$	—		$	35,001	$	—		$	35,001

	December 31,
	2012		2011
Segment assets:
Specialty products	$	1,569,796	$	1,159,040
Fuel products	683,249		573,018
Total assets	$	2,253,045	$	1,732,058

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2012, 2011 and 2010. All of the Company’s long-lived assets are domestically located.

c. Product Information

The Company offers specialty products primarily in six general categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products, fuels and asphalt and other 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,
	2012				2011				2010
Specialty products:
Lubricating oils	$	1,007,928	22	%	$	947,798	30	%	$	759,701	35	%
Solvents	491,114		11	%	495,934		16	%	396,894		18	%
Waxes	142,765		3	%	143,111		5	%	124,964		6	%
Packaged and synthetic specialty products	161,673		3	%	—		—	%	—		—	%
Fuels	2,029		—	%	3,432		—	%	5,507		—	%
Asphalt and other by-products	426,093		9	%	217,351		7	%	121,806		5	%
Total	2,231,602		48	%	1,807,626		58	%	1,408,872		64	%
Fuel products:
Gasoline	1,174,859		25	%	619,630		20	%	304,544		14	%
Diesel	941,047		20	%	513,334		16	%	330,756		15	%
Jet fuel	183,953		4	%	148,036		5	%	135,796		6	%
Heavy fuel oils and other	125,821		3	%	46,297		1	%	10,784		1	%
Total	2,425,680		52	%	1,327,297		42	%	781,880		36	%
Consolidated sales	$	4,657,282	100	%	$	3,134,923	100	%	$	2,190,752	100	%

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

d. Major Customers

During the years ended December 31, 2012, 2011 and 2010, the Company had no customer that represented 10% or greater of consolidated sales.

15. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total (1)
2012
Sales	$	1,169,586	$	1,086,996	$	1,179,818	$	1,220,882	$	4,657,282
Gross profit	84,244		128,808		158,406		141,719		513,177
Net income	51,923		65,662		42,416		45,736		205,737
Net income available to limited partners	50,054		62,875		39,669		42,392		194,990
Limited partners’ interest basic net income per unit	$	0.97	$	1.14	$	0.69	$	0.73	$	3.51
Limited partners’ interest diluted net income per unit	$	0.97	$	1.14	$	0.69	$	0.73	$	3.50
Weighted average limited partner units outstanding — basic	51,685,000		55,028,000		57,746,000		57,746,000
Weighted average limited partner units outstanding — diluted	51,736,000		55,074,000		57,826,000		57,898,000

	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

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

16. Subsequent Events

On January 2, 2013, The Company completed the acquisition of NuStar Energy L.P.’s San Antonio, Texas refinery, together with related assets and the assumption of certain liabilities and obligations (the “San Antonio Acquisition”). The refinery has total crude oil throughput capacity of 14,500 bpd and primarily produces jet fuel, diesel, other fuel products and specialty solvents. Total consideration for the San Antonio Acquisition was approximately $115,694, including approximately $15,000 for inventories acquired at closing, subject to certain post-closing adjustments. The San Antonio Acquisition was funded with borrowings under the Company’s revolving credit facility with the balance through cash on hand. The San Antonio Acquisition purchase price allocation has not yet been finalized due to the timing of the closing of the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in thousands, except per unit data)

On January 8, 2013, the Company completed a public offering of its common units in which it sold 5,750,000 common units, including the overallotment option of 750,000 common units, to the underwriters of the offering at a price to the public of $31.81 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 $175,248 and were used to repay borrowings under its revolving credit facility and for general partnership purposes. Underwriting discounts totaled $7,360. The Company’s general partner contributed $3,733 to maintain its 2% general partner interest.

On January 14, 2013, the Company declared a quarterly cash distribution of $0.65 per unit on all outstanding common units, or approximately $44,540 (including the general partner’s incentive distribution rights) in aggregate, for the quarter ended December 31, 2012. The distribution was paid on February 14, 2013 to unitholders of record as of the close of business on February 4, 2013. This quarterly distribution of $0.65 per unit equates to $2.60 per unit, or approximately $178,160 (including the general partner’s incentive distribution rights) in aggregate on an annualized basis.

On February 7, 2013, the Company entered into a joint venture agreement with MDU Resources Group, Inc. (“MDU”) to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture will be called Dakota Prairie Refining, LLC. Funding for the project will occur over the course of the construction period, with the majority of the direct funding by the Company expected in 2014. The joint venture will allocate profits on a 50%/50% basis to the Company and MDU. The joint venture will be governed by a board of managers comprised of representatives from both the Company and MDU. MDU will provide a portion of the crude oil supply to the refinery, as well as natural gas and electricity utility services. The Company will provide refinery operations, crude oil procurement and refined product marketing expertise to the joint venture.

The fair value of the Company’s derivatives decreased by approximately $24,000 subsequent to December 31, 2012 to a net liability of approximately $69,000. The fair value of the Company’s long-term debt, excluding capital leases, has increased by approximately $20,000 subsequent to December 31, 2012.

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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, as amended (the “Exchange Act”) 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, 2012 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 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On January 3, 2012, January 6, 2012, July 3, 2012, October 1, 2012 and January 2, 2013, we completed the Missouri, TruSouth, Royal Purple, Montana and San Antonio Acquisitions, respectively, which include 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 Missouri, TruSouth, Royal Purple, Montana and San Antonio Acquisitions from our evaluation, as permitted under existing SEC rules. We are currently in the process of evaluating and integrating the Missouri, TruSouth, Royal Purple, Montana and San Antonio Acquisitions’ historical internal controls over financial reporting with ours. We expect to complete the integration of Missouri, TruSouth, Royal Purple and Montana in fiscal year 2013 and the integration of San Antonio in fiscal year 2014.

On January 1, 2013, the Company implemented an enterprise resource planning (“ERP”) system on a company-wide basis, which is expected to improve the efficiency of certain financial and related transaction processes. The implementation of a company-wide ERP system will affect the processes that constitute our internal control over financial reporting and will require testing for effectiveness.

See Management’s Report on Internal Control Over Financial Reporting included in Item 8 “Financial Statements and Supplemental Data.”

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance

Management of Calumet Specialty Products Partners, L.P. and Director Independence

Our general partner, Calumet GP, LLC, manages our operations and activities. Unitholders are 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, LLC Marketplace Rules (“NASDAQ Rules”), a listed limited partnership like us is not required 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 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 Rules 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.

Directors and Executive Officers

The following table shows information regarding the directors and executive officers of Calumet GP, LLC as of March 1, 2013.

Name	Age	Position with Calumet GP, LLC
Fred M. Fehsenfeld, Jr.	62	Chairman of the Board
F. William Grube	65	Chief Executive Officer and Vice Chairman of the Board
Jennifer G. Straumins	39	President and Chief Operating Officer
R. Patrick Murray, II	41	Senior Vice President, Chief Financial Officer and Secretary
Timothy R. Barnhart	53	Senior Vice President — Operations
James S. Carter	64	Director
William S. Fehsenfeld	62	Director
Robert E. Funk	67	Director
George C. Morris III	57	Director
Nicholas J. Rutigliano	65	Director

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.

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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.

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 senior vice president, chief financial officer and secretary of our general partner since January 2013. From September 2005 through December 2012, Mr. Murray served as vice president, chief financial officer and secretary of our general partner. 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 senior vice president — operations of our general partner since January 2013. From December 2009 to December 2012, Mr. Barnhart served as vice president — operations of our general partner. 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.

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.

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

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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 is also a member of the board of directors of Arch Coal, Inc., a public company which produces thermal and metallurgical coal from surface and underground mines.

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 served as president of Tobias Insurance Group, Inc., a commercial insurance brokerage business he founded, since 1973 to 2012 prior to it being acquired by Assured Partners, LLC. Mr. Rutigliano now serves as president of Assured Partners of Indiana, LLC. 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 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, has overall responsibility for evaluating and either approving or recommending to the board of directors the director, chief

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executive officer and senior executive compensation plans, policies and programs of the Company. 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.

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 East 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 filed pursuant to Section 16(a), as well as written representations that no other reports were required for 2012, Calumet’s directors and executive officers filed all reports required by Section 16(a) with the exception of (i) one late filing related to phantom unit vesting on January 22, 2012 for Fred M. Fehsenfeld, Jr., (ii) one late filing related to phantom unit vesting on January 22, 2012 for James S. Carter, (iii) one late filing related to phantom unit vesting on January 22, 2012 for Robert E. Funk, (iv) one late filing related to phantom unit vesting on January 22, 2012 for Nicholas J. Rutigliano, (v) one late filing related to phantom unit vesting on January 22, 2012 for Jennifer G. Straumins, (vi) one late filing related to phantom unit vesting on January 22, 2012 for R. Patrick Murray, II, (vii) one late filing related to phantom unit vesting on January 22, 2012 for Timothy R. Barnhart, (viii) one late filing related to phantom unit vesting on January 22, 2012 for Robert M. Mills and (ix) one late filing related to phantom unit vesting on January 22, 2012 for Jeffrey D. Smith. 

. 

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Item 11. Executive and Director Compensation

Compensation Discussion and Analysis

Fiscal Year 2012 Financial Performance

In 2012, our named executive officers (listed below) were instrumental in our ability to deliver strong financial results and to grow the company, while making strategic acquisitions that we believe will foster our long-term growth. Under the guidance of our senior executive team, we reported record revenue of $4,657.3 million, a 48.6% increase over the prior year. Other year-over-year financial accomplishments include:

• Net income increased 378.1% to $205.7 million

• Increased Adjusted EBITDA 91.7% to $404.6 million

• Increase Distributable Cash Flow 121.1% to $281.1 million

• Distributed $132.4 million of cash to unitholders, an increase of 60.0% over 2011

Overview

For purposes of this Compensation Discussion and Analysis and the compensation tables that follow, the names and positions of our named executive officers for the 2012 year were:

• F. William Grube - Chief Executive Officer and Vice Chairman of the Board

• Jennifer G. Straumins - President and Chief Operating Officer

• R. Patrick Murray, II - Vice President and Chief Financial Officer

• Timothy R. Barnhart - Vice President - Operations

• William A. Anderson - former Vice President - Sales and Marketing (effective October 5, 2012, our new Vice President - Marketing and New Products)

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 the integrated and collaborative effort required by the full executive team to maximize performance. Distributable

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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 25% of the median of market for companies of similar size to us. In 2011, 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:

• review of a peer group of publicly-traded master limited partnerships for executive compensation comparisons;

• analysis of market pay levels and trends for our named executive officers, other officers and key employees from peer companies including base salary, annual incentives and long-term incentives; and

• assessment of Calumet’s executive pay levels relative to overall market levels.

The following master limited partnerships and corporation were included by Buck Consultants in the peer group for the compensation review: Atlas Pipeline Partners, L.P., Boardwalk Pipeline Partners, LP, Buckeye Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, L.P., DCP Midstream Partners, LP, Energy Transfer Partners, L.P., Genesis Energy, L.P., Inergy, L.P., Kinder Morgan Energy Partners, L.P., Magellan Midstream Partners, L.P., MarkWest Energy Partners, L.P., NuStar Energy L.P., ONEOK Partners, L.P., PVR Partners, L.P., Regency Energy Partners LP, Suburban Propane Partners, L.P., Sunoco Logistics Partners L.P., Syntroleum Corporation, Targa Resources Partners LP and Williams Partners, L.P. Peer group companies were validated and selected based on their comparability of EBITDA (a non-GAAP measurement), sales and market capitalization, but also included additional master limited partnerships larger than us in terms of such selection criteria to compare our compensation against a broader peer group given our growth in such selection criteria. Market data compiled from public disclosures of the peer group companies were used in the review to compare our compensation of the key executive group against the market. Buck Consultants provided a presentation of its findings to the compensation committee in October 2011 that assisted us in making the compensation decisions described below for the 2012 year.

The compensation committee used the findings of the Buck Consultants executive compensation review to validate the total competitiveness of compensation for our key executives, including each named executive officer. Specifically, the Buck Consultants review indicated that aggregate target total direct compensation of our key executives, which includes all the major elements of our executive compensation program, including base salary, short-term incentives and long-term compensation, was below the median of market by approximately 25%, driven primarily by long-term compensation as total cash compensation, which includes aggregate base salaries and aggregate short-term incentives for the key executives, assuming the target levels of such incentives are achieved, fall above the median of the expanded peer group by less than 5%. Long-term incentives for the key executives fall below the 25th percentile of the peer group by approximately 25%, which the compensation committee deemed appropriate given our smaller size relative to certain master limited partnerships included in the expanded peer group, with an expectation by the compensation committee that with future achievement of strategic goals and further growth in financial performance, such long-term incentive opportunities should migrate toward the median level of the expanded peer group. Our compensation committee requested that Buck Consultants provide us with a similar presentation in October 2012 to the report that we received in the 2011 year, which we used to assist us in making our compensation decisions for the 2013 year. As of this filing, we have not made any material changes to our compensation program for the 2013 year.

Review of Named Executive Officer Performance

The compensation committee reviews, on an annual basis, each compensation element for a named executive officer. In each case, the compensation committee takes into account the scope of responsibilities and experience and balances these against competitive salary levels. The compensation committee has the opportunity to meet with the named executive officers at various times during the year, which allows the compensation committee to form its own assessment of each individual’s performance.

Objectives of Compensation Programs

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;

• make incentive compensation a significant portion of an executive’s total compensation, designed to balance short-term and long-term performance;

• align the interests of our executives with those of our unitholders; and

• attract, develop and retain executives with a compensation structure that is competitive with other publicly-traded partnerships of similar size.

Elements of Executive Compensation

The compensation committee believes the total compensation and benefits program for our named executive officers should consist of the following:

• base salary;

• annual incentive plan which includes short-term cash awards and also includes an optional deferred compensation element;

• long-term incentive compensation, including unit-based awards;

• retirement, health and welfare benefits; and

• perquisites.

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

Design. 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. In the case of Mr. Grube, his 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.

Results. Mr. Grube’s salary increase for 2012 was 3.7%, which was equivalent to the average of the percentage increases of all salaried employees for 2012. With respect to our other executive officers, the compensation committee determined to increase the base salaries for our other executive officers by 3.2%, based on the same formula.

Compensation Changes for 2013. Mr. Grube’s salary increase for 2013 was 3.7%, based on the same formula described above. With respect to our other named executive officers, the compensation committee approved increased salaries as part of its annual salary review process. Effective January 1, 2013, the base salaries for Ms. Straumins, Mr. Murray and Mr. Barnhart are $350,000, $320,000 and $300,000, respectively. Due to Mr. Anderson’s change in duties at the end of the 2012 year, we do not expect him to be a named executive officer for the 2013 year. The levels of increases in the base salaries for these executives were based on increased job complexity due to the growth of our business. In addition, in the case of each of Mr. Murray and Mr. Barnhart, the increases take into account their increased job responsibilities resulting from their respective promotions to senior vice president and chief financial officer and senior vice president — operations effective January 1, 2013. The compensation committee also considered the increases to base salary to be appropriate based on comparisons against our peer group of publicly traded partnerships in an effort to ensure that base salaries were closer to the market median of our peer group.

Short-Term Cash Awards

Design. Under the Cash Incentive Compensation Plan (the “Cash Incentive Plan”), short-term cash awards are designed to aid us in retaining and motivating executives to assist us in meeting our financial performance objectives on an annual basis. Short-term cash awards are granted to named executive officers and certain other management employees based on our achievement of performance targets on our distributable cash flow, thereby establishing a direct link between executive compensation and our financial performance.

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 our achievement of a minimum, target or stretch level of distributable cash flow for the fiscal year. At the recommendation of the compensation

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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.

Generally, no awards are paid under the Cash Incentive Plan unless we 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.

Results. For fiscal year 2012, the minimum distributable cash flow goal was $123.0 million, the target goal was $138.5 million and the stretch goal was $169.3 million. For the reasons described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 2012 Update,” we exceeded our stretch goal with 2012 distributable cash flow of $281.1 million.

The following table summarizes the levels of cash award opportunity for each named executive officer and the actual percentage earned by them in 2012:

	Cash Incentive Award Opportunity as a Percentage of Base Salary
	Minimum		Target		Stretch		Actual Payout
F. William Grube	50	%	100	%	200	%	216	%	(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 $595,000.

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 25% of the median of our peer group, while placing significant emphasis on the achievement of our distributable cash flow goals.

For 2012, 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 2011 fiscal year. The board of directors set the stretch cash flow goal at 22% 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 2012 Update,” for a discussion of the factors that impacted our results, including our higher gross profit per barrel sold of fuel products and higher sales volume of both specialty products and fuel products, the primary drivers that enabled us to exceed our distributable cash flow targets. The following table reflects our historical minimum, target and stretch distributable cash flow goals:

Distributable Cash Flow (In millions)
Fiscal Year	Actual		Minimum Goal	Target Goal	Stretch Goal
2012	$281.1		$123.0	$138.5	$169.3
2011	$126.4	(1)(2)	$79.4	$89.6	$110.0
2010	$79.8	(1)(2)	$79.4	$89.6	$110.0

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(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 2011 and 2010 Distributable Cash Flow calculations, please refer to our 2011 and 2010 Annual Reports.

Compensation Changes for 2013. Upon the recommendation of the compensation committee, the board of directors has approved new distributable cash flow targets for the 2013 fiscal year based on budgets prepared by management. We do not disclose our confidential 2013 targets, which, if disclosed, would put us at a competitive disadvantage. However, we believe that the targets that are set for the 2013 year will be more difficult to achieve than the targets set for the 2012 year and there is no guarantee that our named executive officers will receive an award related to the 2013 year.

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

Design. 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 participants’ 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 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 the compensation committee recommends and the board of directors approves.

Results. On February 29, 2012, 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 2011 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 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 Nonqualified Deferred Compensation” 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

Design. 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 2012, 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.

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Results. 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 at approximately the 25th percentile of peer practices for long-term equity based awards for similarly situated executive officers. The following table reflects the number of phantom units that would be awarded to our named executive officers depending on whether we achieved the distributable cash flow minimum, target and stretch goals discussed above in “Short-Term Cash Awards” as well as the actual number of phantom units earned in 2012, which will be awarded in the first quarter of 2013:

	2012 Phantom Unit Award Opportunity			Phantom  Units Granted
	Minimum	Target	Stretch
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 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 2012 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.

Although we have not historically maintained a traditional pension plan for our employees, we continued to maintain the Penreco Pension Plan after our acquisition of Penreco in 2008 for the employees that were participating in the plan at that time. Only one of our named executive officers, Mr. Barnhart, was and is a participant in the Penreco Pension Plan. While the plan

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was frozen in 2009, Mr. Barnhart still holds an account in that plan. Please see the “Pension Benefits” section below for additional details.

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:

• 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.

• Executive Physical Program:    Generally on an annual basis, we pay for a complete and professional personal physical exam for each named executive officer appropriate for his or her age to improve their health and productivity.

• Club Memberships:    We pay club membership fees for 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.

• Spousal Travel:    On an occasional basis, we pay expenses related to travel of the spouses of our named executive officers in order to accompany the named executive officer to business-related events.

• Long-Term Disability Insurance:    We provide compensation to allow each named executive officer to purchase long-term disability insurance on an after-tax basis at no net cost to them.

• Use of Company Aircraft:     On an occasional basis, our named executive officers may be eligible to use a leased aircraft for personal use and the incremental cost to us is treated as and reflected in the tables below as compensation to the applicable officer for purposes of these disclosures. The items that we use to determine the incremental cost to us of these flights include the variable costs for personal use of aircraft that were charged to us by the vendor that operates the leased aircraft for contracted hourly costs, fuel charges, and taxes.

The compensation committee periodically reviews the perquisite program to determine if adjustments are appropriate and did not make any material changes to the program during the 2012 year.

Other Compensation Related Matters

Tax Implications of Executive Compensation

Because we are 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 a 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

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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.”

Our employment agreement with Mr. Grube and the related severance provisions are designed to meet the following objectives:

• Change in Control:    In certain scenarios, the potential for merger or being acquired may be in the best interests of our unitholders. We provide the potential for severance compensation to Mr. Grube in the event of a change in control transaction to promote his ability to act in the best interests of our unitholders even though his employment could be terminated as a result of the transaction.

• Termination without Cause:    We believe severance compensation in such a scenario is appropriate because Mr. Grube is bound by confidentiality, nonsolicitation and noncompetition provisions covering one year after termination and because we and Mr. Grube have 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 to us, the compensation committee believes these potential benefits are reasonable.

Report of the Compensation Committee for the Year Ended December 31, 2012

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

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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, 2012, 2011 and 2010:

	Summary Compensation Table for 2012
Name and Principal Position	Year	Salary		Unit Awards (4)		Non-Equity Incentive Plan Compensation (5)		Change in Pension Value and Nonqualified Deferred Compensation Earnings (6)		All Other Compensation (7)		Total
F. William Grube	2012	$	413,000	$	698,289	$	892,500	$	—	$	40,608	$	2,044,397
Chief Executive Officer and Vice Chairman of the Board	2011	398,000		935,597		692,400		—		19,760		2,045,757
	2010	386,131		278,220		115,378		—		19,574		799,303
Jennifer G. Straumins	2012	297,500		427,751		595,000		—		19,428		1,339,679
President and Chief Operating Officer	2011	288,500		506,130		577,000		—		19,381		1,391,011
	2010	280,000		173,736		101,728		—		17,884		573,348
R. Patrick Murray, II (1)	2012	292,000		493,475		525,600		—		19,409		1,330,484
Vice President and Chief Financial Officer	2011	283,500		545,094		510,300		—		19,363		1,358,257
	2010	275,000		129,699		114,184		—		17,240		536,123
Timothy R. Barnhart (2)	2012	271,000		683,380		325,200		54,848		19,334		1,353,762
Vice President — Operations	2011	263,000		614,752		420,800		64,866		19,290		1,382,708
	2010	255,000		179,931		66,175		38,800		17,735		557,641
William A. Anderson (3)	2012	271,000		395,928		542,000		—		19,334		1,228,262
Vice President — Sales and Marketing	2011	263,000		466,128		526,000		—		35,219		1,290,347
	2010	255,000		76,680		132,350		—		40,960		504,990

(1) Mr.  Murray’s title in the table was applicable for the 2012 year. He was appointed senior vice president and chief financial officer effective January 1, 2013.

(2) Mr. Barnhart’s title in the table was applicable for the 2012 year. He was appointed senior vice president - operations effective January 1, 2013.

(3) Mr. Anderson’s title in the table was applicable for the first portion of the 2012 year. He was appointed vice president - marketing and new products effective October 5, 2012.

(4) The amounts include the aggregate grant date fair value of (i) phantom unit 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 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. The amounts reflect the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. See note 10 to our consolidated financial statements for the fiscal year ending December 31, 2012 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards.

(5) 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” for further details.

(6) Represents aggregate change in the actuarial present value of accumulated benefits under the Penreco Pension Plan. Please read “Pension Benefits” for further details.

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(7) 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 Ms. Straumins, Mr. Murray, Mr. Barnhart and Mr. Anderson in 2012, as such amounts for these named executive officers were each less than $10,000 in aggregate.

	401(k) Plan Matching Contributions		Vehicle		Spousal Travel		Club Membership		Long-Term Disability Insurance		Company Aircraft		Term Life Insurance		Total
F. William Grube	$	18,375	$	5,883	$	—	$	—	$	792	$	14,142	$	1,416	$	40,608
Jennifer G. Straumins	18,375		—		—		—		—		—		1,053		19,428
R. Patrick Murray, II	18,375		—		—		—		—		—		1,034		19,409
Timothy R. Barnhart	18,375		—		—		—		—		—		959		19,334
William A. Anderson	18,375		—		—		—		—		—		959		19,334

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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, 2012:

Grants of Plan-Based Awards Table for the Year Ended December 31, 2012

		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)			Estimated Possible 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 (#)
F. William Grube		223,125	446,250	892,500
					10,800	21,600	32,400
	2/14/2012							351	7,757
	2/29/2012							2,425	53,593
	5/15/2012							574	13,621
	8/14/2012							562	14,309
	11/14/2012							491	15,118
Jennifer G. Straumins		148,750	297,500	595,000
					7,200	14,400	21,600
	2/14/2012							330	7,293
	5/15/2012							326	7,736
	8/14/2012							321	8,173
	11/14/2012							280	8,621
R. Patrick Murray, II		146,000	292,000	584,000
					7,200	14,400	21,600
	2/14/2012							167	3,691
	2/29/2012							794	17,547
	5/15/2012							240	5,695
	8/14/2012							233	5,932
	11/14/2012							204	6,281
Timothy R. Barnhart		135,500	271,000	542,000
					7,200	14,400	21,600
	2/14/2012							288	6,365
	2/29/2012							1,474	32,575
	5/15/2012							424	10,062
	8/14/2012							415	10,566
	11/14/2012							360	11,084
William A. Anderson		135,500	271,000	542,000
					7,200	14,400	21,600

(1) Estimated possible payouts under non-equity incentive plan awards represent the ranges of potential cash incentive awards granted under our Cash Incentive Plan related to fiscal year 2012. 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 possible payouts under equity incentive plan awards represent the ranges of potential unit based awards earned under the 2012 Phantom Unit Program as part of Calumet’s Long-Term Incentive Plan. These units will be awarded in

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the first quarter of 2013. For a description of this plan and available awards under the 2012 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 2012, if any, in connection with the named executive officer’s deferral of a portion of his or her cash incentive award under our Cash Incentive Compensation Plan into the Calumet Executive Deferred Compensation Plan. See “Nonqualified Deferred Compensation” 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.

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 20% 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	20	%	40	%	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 Plan and the material terms relating to phantom units that we may grant pursuant to the 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. Units withheld to satisfy our general partner’s tax withholding obligations are available for delivery pursuant to other awards. 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

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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.

Phantom Units.    During the 2012 year, we granted phantom units pursuant to the Plan. 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 phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which 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 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 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.

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 with phantom units 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.

2012 Phantom Unit Program.    In addition to the features described above, potential awards under our 2012 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 2012 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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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 various annual adjustment by the compensation committee of the board of directors of our general partner that have been made following the Effective Date, as well as the right to participate in our Long-Term Incentive Plan, other bonus plans, our retirement, health and welfare benefit plans, and the use of an automobile. 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. The potential severance benefits provided within the employment agreement are described in greater detail in the “Potential Payments Upon Termination or Change in Control” section below. 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.

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 for 2012.

Salary Percentage for 2012

Name	Percentage of Total Compensation
F. William Grube	20%
Jennifer G. Straumins	22%
R. Patrick Murray, II	22%
Timothy R. Barnhart	20%
William A. Anderson	22%

Outstanding Equity Awards at Fiscal Year-End

Our named executive officers had the following outstanding equity awards at December 31, 2012.

Outstanding Equity Awards at December 31, 2012

	Unit Awards
Name	Number of Units That Have Not Vested		Market Value of Units  That Have Not Vested (1)
F. William Grube (2)	22,870	(7)	$	695,019
Jennifer G. Straumins (3)	14,817	(7)	450,289
R. Patrick Murray, II (4)	14,138	(7)	429,654
Timothy R. Barnhart (5)	15,992	(7)	485,997
William A. Anderson (6)	11,700	(7)	355,563

(1) Market value of phantom units reported in these columns is calculated by multiplying the closing market price $30.39 of our common units at December 31, 2012 (the last trading day of the fiscal year) by the number of units.

(2) 1,350 phantom units vest on December 31, 2013; 16,200 phantom units vest ratably over two years on each of December 31, 2013 and 2014; 1,148 phantom units vest ratably over two years on each of July 1, 2013 and 2014; 1,585

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phantom units vest ratably over three years on each of July 1, 2013, 2014 and 2015 and 2,587 phantom units vest ratably over four years on each of July 1, 2013, 2014, 2015 and 2016.

(3) 900 phantom units vest on December 31, 2013; 10,800 phantom units vest ratably over two years on each of December 31, 2013 and 2014; 1,412 phantom units vest on January 22, 2013; 1,107 phantom units vest ratably over two years on each of July 1, 2013 and 2014 and 598 phantom units vest ratably over three years on each of July 1, 2013, 2014 and 2015.

(4) 900 phantom units vest on December 31, 2013; 10,800 phantom units vest ratably over two years on each of December 31, 2013 and 2014; 703 phantom units vest on January 22, 2013; 498 phantom units vest ratably over two years on each of July 1, 2013 and 2014; 390 phantom units vest ratably over three years on each of July 1, 2013, 2014 and 2015 and 847 phantom units vest ratably over four years on each of July 1, 2013, 2014, 2015 and 2016.

(5) 900 phantom units vest on December 31, 2013; 10,800 phantom units vest ratably over two years on each of December 31, 2013 and 2014; 1,052 phantom units vest on January 22, 2013; 758 phantom units vest ratably over two years on each of July 1, 2013 and 2014; 909 phantom units vest ratably over three years on each of July 1, 2013, 2014 and 2015 and 1,573 phantom units vest ratably over four years on each July 1, 2013, 2014, 2015 and 2016.

(6) 900 phantom units vest on each December 31, 2013 and 10,800 phantom units vest ratably over two years on each of December 31, 2013 and 2014.

(7) Does not include the following phantom unit awards, which will be awarded during the first quarter of 2013 and which relate to services provided during fiscal year 2012: 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 88,649 phantom units related to the Deferred Compensation Plan and the Long Term Incentive Plan vest during the year ended December 31, 2012. 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, 2012

	Unit Awards
Name	Number of  Units Vested	Value Realized on Vesting (1)
F. William Grube	27,458	$	716,489
Jennifer G. Straumins	14,765	390,123
R. Patrick Murray, II	15,781	416,045
Timothy R. Barnhart	18,945	490,948
William A. Anderson	11,700	319,923

(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 vesting on such date.

Pension Benefits

Executive	Plan Name	Number of Years  of Credited Service (1)	Present Value  of Accumulated Benefits (2)		Payments  During 2012
Timothy R. Barnhart	Penreco Pension Plan	26.3205	$	359,325	$	—

(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 2012 fiscal year; a further description can be found in Note 11 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.

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(2) In addition to the assumptions noted within Note 11 to our audited consolidated financial statements for the 2012 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, 2012 Financial Accounting Standards (“FAS”) disclosure weighted average discount rate of 3.86% 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).

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 $250,000 for the 2012 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, 2012, 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 2012
Name	Executive Contributions in 2012 (1)		Company Contributions in 2012 (2)		Aggregate Earnings in 2012 (3)		Aggregate Withdrawals/ Distributions		Aggregate Balance at end of 2012 (4)
F. William Grube	$	160,800	$	53,593	$	50,805	$	—	$	851,102
Jennifer G. Straumins	—		—		31,823		—		538,693
R. Patrick Murray, II	52,664		17,547		21,599		—		374,192
Timothy R. Barnhart	97,726		32,575		38,077		—		652,352

(1) Executive contributions in 2012 represent phantom unit grants on February 29, 2012 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 Plan related to the 2011 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 2011 under “Unit Awards” in the Summary Compensation Table.

(2) Our contributions in 2012 represent discretionary matching contributions made in the form of phantom unit grants on February 29, 2012 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 2011 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 2012 under “Unit Awards” in the Summary Compensation Table.

(3) Aggregate earnings in 2012 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 29, 2012, as well as phantom units granted in fiscal year 2011, 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 2012 are included as compensation in 2012 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 2012 year, the dollar amount of each participant’s account as of December 31, 2012 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, 2012, which was $30.39. The phantom units associated with each executive’s account as of December 31, 2012 were as follows: Mr. Grube, 28,006; Ms. Straumins, 17,726; Mr. Murray, 12,313 and Mr. Barnhart, 21,466. 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 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 and (c) For 2011, Mr. Grube, $160,800; Mr. Murray, $52,664 and Mr. Barnhart, $97,726.

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

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contributions of phantom units or purely discretionary contributions of phantom units, in amounts and at times as the compensation committee determines appropriate. For the 2012 year, the compensation committee authorized matching contributions of deferred amounts related to the 2011 fiscal year. For each equivalent three phantom units credited to a participant’s account at the time the 2011 cash incentive award was paid during the first quarter of 2012, 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 2012 matching contributions related to fiscal year 2011 will vest ratably over four years on each July 1 beginning July 1, 2013. 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 (as such terms are defined 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, 2012, 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, 2012, 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 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.

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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, 2012, 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) $1,743,602; and (d) $1,805,166, with an aggregate value of $3,548,768.

Termination of Employment by Mr. Grube for Good Reason or by Us Without Cause

Upon the termination of Mr. Grube’s employment by him for good reason or by us without cause:

a. We will pay him a lump sum cash payment in an amount equal to three times his annual base salary then in effect;

b. We will pay him a lump sum equal to his earned annual base salary through the date of termination to the extent not theretofore paid;

c. We will pay him a lump sum equal to any compensation incentive awards payable in cash with respect to fiscal years ended prior to the year that includes the date of termination to the extent not theretofore paid;

d. We will pay him a lump sum cash payment with respect to his participation in any plans, programs, contracts or other arrangements that may result in a cash payment for the fiscal year that includes the date of termination on a prorated basis considering the date of termination relative to the full fiscal year;

e. All equity-based awards (including phantom unit awards) held by Mr. Grube shall immediately vest in full (at their target levels, if applicable) and become fully exercisable or payable, as the case may be.

“Good reason” as defined in the employment agreement includes: (i) any material breach by us of the employment agreement; (ii) any requirement by us that Mr. Grube relocate outside of the metropolitan Indianapolis, Indiana area; (iii) failure of any successor to us to assume the employment agreement not later than the date as of which it acquires substantially all of the equity, assets or business of us; (iv) any material reduction in Mr. Grube’s title, authority, responsibilities, or duties (including a change that causes him to cease being a member of the board of directors or reporting directly and solely to the board of directors); or (v) the assignment of Mr. Grube any duties materially inconsistent with his duties as 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, 2012, 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) $1,239,000 (or three times $413,000); (b) $0; (c) $0; (d) $1,743,602; and (e) $1,805,166, with an aggregate value of $4,787,768.

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.

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If Mr. Grube’s employment were to have terminated by him without good reason or by us for cause on December 31, 2012, 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) $1,743,602, with an aggregate value of $1,743,602.

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 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 our officers’ employment with us or a successor entity, we want to provide our 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, 2012 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	$	1,805,166	$	1,805,166
Jennifer G. Straumins	1,203,444		1,203,444
R. Patrick Murray, II	1,203,444		1,203,444
Timothy R. Barnhart	1,203,444		1,203,444
William A. Anderson	1,203,444		1,203,444

(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, 2012 closing common unit price of $30.39. 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 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, 2012 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	$	851,102	$	851,102
Jennifer G. Straumins	538,693		538,693
R. Patrick Murray, II	374,192		374,192
Timothy R. Barnhart	652,352		652,352
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, 2012 closing common unit price of $30.39. 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 Compensation 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 board committee meetings. Non-employee director compensation consists of the following:

• an annual fee of $50,000, payable in quarterly installments;

• an annual award of 2,200 restricted or phantom units;

• 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, payable in quarterly installments; 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 board 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.

The following table sets forth certain compensation information of our non-employee directors for the year ended December 31, 2012:

	Director Compensation Table for 2012
Name	Fees Earned or Paid in Cash		Unit Awards (1)		Total
Fred M. Fehsenfeld, Jr.	$	55,000	$	117,070	$	172,070
James S. Carter	59,000		122,726		181,726
William S. Fehsenfeld	50,000		69,784		119,784
Robert E. Funk	56,500		112,149		168,649
George C. Morris III	58,000		99,673		157,673
Nicholas J. Rutigliano	50,000		115,036		165,036

(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 2012 pursuant to the Deferred Compensation Plan and (iii) DERs credited in the

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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. The amounts reflect the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. See Note 10 to our consolidated financial statements for the fiscal year ending December 31, 2012 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards.

Annual Phantom Unit Awards

On October 31, 2012, each non-employee director was granted 2,200 phantom units with a grant date fair value of $69,784. With respect to this award, 25% of the phantom units vested on December 31, 2012, 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, 2012, each non-employee director had 3,198 unvested phantom units outstanding with a market value of $97,187 related to annual equity awards from 2010, 2011 and 2012. Related to these annual equity awards made to non-employee directors, an aggregate of 19,188 unvested phantom units with a market value of $583,123 were outstanding as of December 31, 2012.

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 2012 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 2012. 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 2012 was made on a quarterly basis as of the date of our quarterly board meetings related to fiscal year 2012.

The following table summarizes the aggregate balance of each director’s Deferred Compensation Plan account at the end of the fiscal year:

Nonqualified Deferred Compensation Table for 2012
Name	Number of Units	Aggregate Balance at end of 2012 (1)
Fred M. Fehsenfeld, Jr.	16,490	$	501,131
James S. Carter	19,100	580,449
Robert E. Funk	13,904	422,543
George C. Morris III	6,304	191,579
Nicholas J. Rutigliano	16,410	498,700

(1) The dollar amount of each director’s account as of December 31, 2012 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, 2012, which was $30.39.

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” for descriptions of our transactions in fiscal year 2012 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

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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.

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 28, 2013 held by:

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

• each director of our general partner;

• each named executive officer of our general partner; and

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

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

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The address for the beneficial owners listed below, other than The Heritage Group and 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) (2)	11,867,533	18.75	%
Calumet, Incorporated (2)	1,934,287	3.60	%
F. William Grube (3)(4)(5)	1,391,298	2.20	%
Jennifer G. Straumins (6)	1,335,818	2.11	%
Fred M. Fehsenfeld, Jr. (1)(2)(7)(8)	673,414	1.06	%
R. Patrick Murray, II	24,681	*
Timothy R. Barnhart	23,035	*
George C. Morris III (9)	88,803	*
William S. Fehsenfeld (1)(8)(10)	75,752	*
Nicholas J. Rutigliano (1)(8)(11)	58,346	*
James S. Carter	42,371	*
Robert E. Funk	37,746	*
All directors and executive officers as a group (10 persons)	3,751,264	5.93	%

*  = 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.

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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) 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.

(3) Includes 775,000 common units that are owned by AEG Associates II, LLC, an 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.

(4) Includes common units that are owned by a grantor retained annuity trusts for which Janet K. Grube, the spouse of F. William Grube, serves as sole trustee. Janet K. Grube and her two children are the beneficiaries of such trusts. F. William Grube disclaims beneficial ownership of the common units owned by the trust.

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

(6) Includes common units that are owned by the children of Jennifer G. Straumins, of which she disclaims beneficial ownership.

(7) Includes common units that are owned by the spouse and certain children of Fred M. Fehsenfeld, Jr., for which he disclaims beneficial ownership.

(8) Does not include a total of 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.

(9) Includes common units that are owned by the spouse of George C. Morris III, of which he disclaims beneficial ownership.

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

(11) Includes common units that are owned by the spouse of Nicholas J. Rutigliano, 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, 2012:

	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	510,852	—		122,295
Total	510,852	$	—	122,295

(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 may 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 will 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 18,132,686 common units representing a 28.7% 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, 2012 and for additional information related to incentive distribution rights.

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 and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.

Omnibus Agreement

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

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

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

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

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

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

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

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

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 and surety/performance bond requirements, including our general liability, automobile liability, excess liability, workers’ compensation as well as directors’ and officers’ liability and issuance of surety/performance bonds. The total premiums and fees paid by us through Mr. Rutigliano’s firm for 2012 were approximately $0.5 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 2012 were approximately $1.1 million, which represented purchases based upon standard, index-based market rates.

From May 2008 to May 2011 we purchased 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. This agreement was terminated in May 2011.

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 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 active but is not currently in use.

From September 2009 to May 2011, we purchased crude oil under 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. This agreement was terminated in May 2011.

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

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chief operating officer, Jennifer G. Straumins, the terms of the aforementioned 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 2012, 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 2012 were approximately $1.8 million. As of December 31, 2012 there was an immaterial 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 2012, 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 2012 were approximately $0.3 million. As of December 31, 2012, there was no 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 2012 for cleaning and waste removal services were approximately $6.4 million. As of December 31, 2012, there was a $0.2 million 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 2012, 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 2012 were approximately $0.6 million. As of December 31, 2012, there were approximately $0.5 million 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. During 2012, we made ordinary course sales of certain specialty products to Asphalt Materials of $7.2 million. As of December 31, 2012, there was no balance due us from Asphalt Materials related to these products sales. 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, 2012, there was approximately $1.6 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 $26.8 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.

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;

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(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 2012 and 2011.

	Year Ended December 31,
	2012		2011
Audit fees	$	2,002,000	$	1,680,000
Audit-related fees	1,266,000		581,000
Tax fees	105,000		—
All other fees	176,000		139,500
Total	$	3,549,000	$	2,400,500

“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 various securities offerings in 2012 and purchase price allocation procedures related to acquisitions.

“Tax fees” are related to due diligence and domestic compliance matters.

“All other fees” primarily consist of those associated with insurance claim consulting services and due diligence related to acquisitions.

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. 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 NumberDescription
2.1	—	Unit Purchase Agreement, dated as of June 5, 2012, by and among Calumet Lubricants Co., Limited Partnership, Royal Purple, Inc. and the shareholders of Royal Purple, Inc. named therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on June 8, 2012 (File No. 000-51734)).
2.2	—	Share Purchase Agreement, dated as of August 14, 2012, among Calumet Specialty Products Partners, L.P. and Connacher Oil and Gas Limited (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on August 20, 2012 (File No. 000-51734)).
3.1	—	Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.2	—	Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
3.3	—	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).
3.4	—	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 Registrant’s 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 to the 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 Registrant’s 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 Registrant’s Current Report on Form 8-K filed with the Commission on April 26, 2011 (File No. 000-51734)).
4.3	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)).

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Exhibit NumberDescription
4.4	—	Indenture, dated June 29, 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 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 5, 2012 (File No. 000-51734)).
4.5	—	Registration Rights Agreement, dated June 29, 2012, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 5, 2012 (File No. 000-51734)).
10.1	—	LVT Unit Agreement, effective January 1, 2008, between ConocoPhillips Company and Calumet Penreco, LLC (incorporated by reference to Exhibit 10.11 to the Registrant’s 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.
10.2	—	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 Registrant’s 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.
10.3	—	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 Registrant’s 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	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on March 20, 2008 (File No. 000-51734)).
10.5	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on May 6, 2008 (File No. 000-51734)).
10.6	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on December 1, 2008 (File No. 000-51734)).
10.7	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on April 22, 2009 (File No. 000-51734)).
10.8	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No. 000-51734)).
10.9	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No. 000-51734)).
10.10	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on March 25, 2011 (File No. 000-51734)).
10.11	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 4, 2009 (File No. 000-51734)).
10.12	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 6, 2009 (File No. 000-51734)).
10.13	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on December 3, 2009 (File No. 000-51734)).

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Exhibit NumberDescription
10.14	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No. 000-51734)).
10.15	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No. 000-51734)).
10.16	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on March 25, 2011 (File No. 000-51734)).
10.17*	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on December 22, 2008 (File No. 000-51734)).
10.18*	—	Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No. 000-51734)).
10.19*	—	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)).
10.20	—	Omnibus Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
10.21*	—	Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1/A filed with the Commission on November 16, 2005 (File No. 333-128880)).
10.22*	—	Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009 (incorporated by reference to Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K filed with the Commission on March 4, 2009 (File No. 000-51734).
10.23*	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on January 4, 2011 (File No. 000-51734)).
10.24	—	Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)).
10.25	—	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 (incorporated by reference to Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K filed with the Commission on February 29, 2012 (File No. 000-51734)).
10.26	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 8, 2011 (File No. 000-51734)).
10.27	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on October 6, 2011 (File No. 000-51734)).
10.28	—	Crude Oil Purchase Agreement effective as of October 1, 2011, by and between BP Products North America Inc. and Calumet Superior, LLC (incorporated by reference to Exhibit 10.30 to the Registrant’s Annual Report on Form 10-K filed with the Commission on February 29, 2012 (File No. 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.29	—	Amended and Restated Crude Oil Purchase Agreement, dated April 1, 2012 by and between BP Products North America Inc. and Calumet Superior, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 9, 2012 (File No. 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

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Exhibit NumberDescription
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.

*** 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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, 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

Date: March 1, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, 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	Chief Executive Officer, Director and Vice Chairman of the Board of Calumet GP, LLC (Principal Executive Officer)	Date:	March 1, 2013
F. William Grube
/s/    R. Patrick Murray, II	Senior Vice President, Chief Financial Officer and Secretary of Calumet GP, LLC (Principal Accounting and Financial Officer)	Date:	March 1, 2013
R. Patrick Murray, II
/s/    Fred M. Fehsenfeld, Jr.	Director and Chairman of the Board of Calumet GP, LLC	Date:	March 1, 2013
Fred M. Fehsenfeld, Jr.
/s/    James S. Carter	Director of Calumet GP, LLC	Date:	March 1, 2013
James S. Carter
/s/    William S. Fehsenfeld	Director of Calumet GP, LLC	Date:	March 1, 2013
William S. Fehsenfeld
/s/    Robert E. Funk	Director of Calumet GP, LLC	Date:	March 1, 2013
Robert E. Funk
/s/    Nicholas J. Rutigliano	Director of Calumet GP, LLC	Date:	March 1, 2013
Nicholas J. Rutigliano
/s/    George C. Morris III	Director of Calumet GP, LLC	Date:	March 1, 2013
George C. Morris III

169

Index to Exhibits

Exhibit NumberDescription
2.1	—	Unit Purchase Agreement, dated as of June 5, 2012, by and among Calumet Lubricants Co., Limited Partnership, Royal Purple, Inc. and the shareholders of Royal Purple, Inc. named therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on June 8, 2012 (File No. 000-51734)).
2.2	—	Share Purchase Agreement, dated as of August 14, 2012, among Calumet Specialty Products Partners, L.P. and Connacher Oil and Gas Limited (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on August 20, 2012 (File No. 000-51734)).
3.1	—	Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.2	—	Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
3.3	—	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).
3.4	—	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 Registrant’s 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 to the 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 Registrant’s 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 Registrant’s Current Report on Form 8-K filed with the Commission on April 26, 2011 (File No. 000-51734)).
4.3	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)).
4.4	—	Indenture, dated June 29, 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 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 5, 2012 (File No. 000-51734)).
4.5	—	Registration Rights Agreement, dated June 29, 2012, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 5, 2012 (File No. 000-51734)).
10.1	—	LVT Unit Agreement, effective January 1, 2008, between ConocoPhillips Company and Calumet Penreco, LLC (incorporated by reference to Exhibit 10.11 to the Registrant’s 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.
10.2	—	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 Registrant’s 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.
10.3	—	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 Registrant’s 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.

170

Exhibit NumberDescription
10.4	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on March 20, 2008 (File No. 000-51734)).
10.5	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on May 6, 2008 (File No. 000-51734)).
10.6	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on December 1, 2008 (File No. 000-51734)).
10.7	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on April 22, 2009 (File No. 000-51734)).
10.8	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No. 000-51734)).
10.9	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No. 000-51734)).
10.10	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on March 25, 2011 (File No. 000-51734)).
10.11	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 4, 2009 (File No. 000-51734)).
10.12	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 6, 2009 (File No. 000-51734)).
10.13		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 Registrant’s Current Report on Form 8-K filed with the Commission on December 3, 2009 (File No. 000-51734)).
10.14	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on May 7, 2010 (File No. 000-51734)).
10.15	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No. 000-51734)).
10.16	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on March 25, 2011 (File No. 000-51734)).
10.17*	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on December 22, 2008 (File No. 000-51734)).
10.18*	—	Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No. 000-51734)).
10.19*	—	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)).

171

Exhibit NumberDescription
10.2	—	Omnibus Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
10.21*	—	Form of Unit Option Grant (incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1/A filed with the Commission on November 16, 2005 (File No. 333-128880)).
10.22*	—	Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009 (incorporated by reference to Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K filed with the Commission on March 4, 2009 (File No. 000-51734).
10.23*	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on January 4, 2011 (File No. 000-51734)).
10.24	—	Amended and Restated Credit Agreement, dated as June 24, 2011, by and among Calumet Specialty Products Partners, L.P. and its subsidiaries as Borrowers, the Lenders, Bank of America, N.A., as Agent and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Capital Finance, LLC as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on June 30, 2011 (File No. 000-51734)).
10.25	—	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 (incorporated by reference to Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K filed with the Commission on February 29, 2012 (File No. 000-51734)).
10.26	—	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 Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 8, 2011 (File No. 000-51734)).
10.27	—	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 Registrant’s Current Report on Form 8-K filed with the Commission on October 6, 2011 (File No. 000-51734)).
10.28	—	Crude Oil Purchase Agreement effective as of October 1, 2011, by and between BP Products North America Inc. and Calumet Superior, LLC (incorporated by reference to Exhibit 10.30 to the Registrant’s Annual Report on Form 10-K filed with the Commission on February 29, 2012 (File No. 000-51734)). Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
10.29	—	Amended and Restated Crude Oil Purchase Agreement, dated April 1, 2012 by and between BP Products North America Inc. and Calumet Superior, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 9, 2012 (File No. 000-51734)). 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.

172

*** 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.

173

EX-12.1

Exhibit 12.1

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

The table below sets forth the Computation of Ratio of Earnings to Fixed Charges for Calumet Specialty Products Partners, L.P. and its subsidiaries for each of the periods indicated.

	Year Ended December 31,
	(Unaudited) (Dollars in thousands)
	2008		2009		2010		2011		2012
Earnings
Income from continuing operations	$	44,694	$	61,936	$	17,299	$	43,965	$	206,490
Fixed charges less unamortized capitalized interest	45,450		44,903		41,910		60,257		100,390
Earnings from continuing operations before fixed charges	$	90,144	$	106,839	$	59,209	$	104,222	$	306,880
Fixed Charges
Interest expense, net of capitalized interest	$	33,938	$	33,573	$	30,497	$	48,747	$	85,573
Capitalized interest, net of amortization	6,909		575		380		592		754
Estimated interest within rental expense	11,512		11,330		11,413		11,510		14,817
Total fixed charges	$	52,359	$	45,478	$	42,290	$	60,849	$	101,144
Ratio of earnings to fixed charges	1.72		2.35		1.40		1.71		3.03

For purposes of determining the ratio of earnings to fixed charges, earnings are defined as pre-tax income from continuing operations plus the following (a) fixed charges, and (b) amortization of capitalized interest, less interest capitalized. Fixed charges consist of interest expensed and capitalized plus (a) amortized discounts and capitalized expenses related to indebtedness, and (b) an estimate of the interest within rental expense.

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

(As of December 31, 2012)

Name of Subsidiary	Jurisdiction of Organization
Calumet Operating, LLC	Delaware
Calumet LP GP, LLC	Delaware
Calumet Lubricants Co., Limited Partnership	Indiana
Calumet Sales Company Incorporated	Delaware
Calumet Shreveport, LLC	Indiana
Calumet Shreveport Lubricants & Waxes, LLC	Indiana
Calumet Shreveport Fuels, LLC	Indiana
Calumet Finance Corp.	Delaware
Calumet Penreco, LLC	Delaware
Calumet Superior, LLC	Delaware
Calumet Missouri, LLC	Delaware
Calumet Montana Refining, LLC	Delaware
Royal Purple, LLC	Delaware
TruSouth Oil, LLC	Louisiana
S&S International Mining Enterprises, Inc.	Arizona
Calumet RP I, LLC	Delaware
Calumet RP II, LLC	Delaware
Calumet RP III, LLC	Delaware
Calumet RP IV, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-8 No. 333-138767) of Calumet Specialty Products Partners, L.P. pertaining to the Calumet GP, LLC Long-Term Incentive Plan of Calumet Specialty Products Partners, L.P.;

(2) Registration Statement (Form S-3 No. 333-170390) of Calumet Specialty Products Partners, L.P.;

(3) Registration Statement (Form S-4 No. 333-178574) of Calumet Specialty Products Partners, L.P.;

(4) Registration Statement (Form S-4 No. 333-178589) of Calumet Specialty Products Partners, L.P.;

(5) Registration Statement (Form S-4 No. 333-185262) of Calumet Specialty Products Partners, L.P.; and

(6) Registration Statement (Form S-8 No. 333-186961) of Calumet Specialty Products Partners, L.P. pertaining to the Calumet GP, LLC Long-Term Incentive Plan of Calumet Specialty Products Partners, L.P.;

of our report dated March 1, 2013, with respect to the consolidated financial statements of Calumet Specialty Products Partners, L.P., our report dated March 1, 2013, with respect to the effectiveness of internal control over financial reporting of Calumet Specialty Products Partners, L.P. included in this Annual Report (Form 10-K) of Calumet Specialty Products Partners, L.P. for the year ended December 31, 2012.

/s/ ERNST & YOUNG LLP

Indianapolis, Indiana

March 1, 2013

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, F. William Grube, certify that:

1. I have reviewed this Annual Report on Form 10-K of Calumet Specialty Products Partners, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 1, 2013	/s/ F. William Grube
		F. William Grube
		Chief Executive Officer, Director and Vice Chairman of the Board of Calumet GP, LLC, general partner of Calumet Specialty Products Partners, L.P. (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, R. Patrick Murray, II, certify that:

1. I have reviewed this Annual Report on Form 10-K of Calumet Specialty Products Partners, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 1, 2013	/s/ R. Patrick Murray, II
		R. Patrick Murray, II Senior Vice President, Chief Financial Officer and Secretary of Calumet GP, LLC, general partner of Calumet Specialty Products Partners, L.P. (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Annual Report of Calumet Specialty Products Partners, L.P. (the “Company”) on Form 10-K for the year ended December 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned officers of Calumet GP, LLC, the general partner of the Company, does hereby certify that:

(a) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934.

(b) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ F. William Grube
March 1, 2013	F. William Grube
	Chief Executive Officer, Director and Vice Chairman of the Board of Calumet GP, LLC

	/s/ R. Patrick Murray, II
March 1, 2013	R. Patrick Murray, II
	Senior Vice President, Chief Financial Officer and Secretary of Calumet GP, LLC

XML

Summary of Significant Accounting Policies - Inventories (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Inventories
Cost of Inventories Determined	last-in, first-out (LIFO)
Raw materials	$ 85,399	$ 105,802
Work in process	119,526	91,763
Finished goods	348,649	300,175
Inventories total	553,574	497,740
Higher replacement cost of inventories, based on current market values	38,295	87,635
Gains in cost of sales due to the liquidation of lower cost inventory layers	(4,206)	5,166	13,661
Losses due to lower of cost or market valuation	$ (8,124)	$ (1,976)	$ (76)

XML

Commitments and Contingencies - Operating Leases (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitments and Contingencies Disclosure [Abstract]
Operating leases, rent expense	$ 26,934	$ 20,490	$ 17,104
Operating Leases, Future Minimum Commitments
2013	23,194
2014	14,937
2015	11,752
2016	7,946
2017	5,999
Thereafter	15,094
Total	$ 78,922

XML

Acquisitions (Details 1) (USD $) In Thousands, unless otherwise specified		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended			12 Months Ended		12 Months Ended		12 Months Ended
	Dec. 31, 2012 Missouri Acquisition	Dec. 31, 2012 Missouri Acquisition Customer relationships	Jan. 03, 2012 Missouri Acquisition Customer relationships	Dec. 31, 2012 TruSouth Acquisition	Jan. 06, 2012 TruSouth Acquisition	Dec. 31, 2012 TruSouth Acquisition Customer relationships	Jan. 06, 2012 TruSouth Acquisition Customer relationships	Dec. 31, 2012 TruSouth Acquisition Tradenames	Jan. 06, 2012 TruSouth Acquisition Tradenames	Dec. 31, 2012 TruSouth Acquisition Non-competition agreements	Jan. 06, 2012 TruSouth Acquisition Non-competition agreements	Dec. 31, 2012 Royal Purple Acquisition	Jul. 03, 2011 Royal Purple Acquisition	Jul. 03, 2011 Royal Purple Acquisition Tradenames	Dec. 31, 2012 Royal Purple Acquisition Customer relationships	Jul. 03, 2011 Royal Purple Acquisition Customer relationships	Dec. 31, 2012 Royal Purple Acquisition Tradenames	Jul. 03, 2011 Royal Purple Acquisition Tradenames	Dec. 31, 2012 Royal Purple Acquisition Trade secrets	Jul. 03, 2011 Royal Purple Acquisition Trade secrets
Component of intangible asset
Amount	$ 5,367		$ 5,367	$ 2,545	$ 2,545		$ 1,775		$ 675		$ 95	$ 183,398	$ 183,398	$ 14,790		$ 118,683		$ 5,746		$ 44,179
Life		20 years		14 years		16 years		9 years		2 years		18 years			20 years		10 years		12 years

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Derivatives (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	$ (215,132)	$ (34,160)
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	154,085	104,020
Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	36,993	(13,297)
Fuel Product | Crude oil swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(99,960)	133,060
Fuel Product | Crude oil swaps | Cost of sales
Derivative instruments designated as cash flow hedges
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	(49,874)	(110,945)
Fuel Product | Crude oil swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	99,672	(8,159)
Fuel Product | Gasoline swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(15,981)	(38,289)
Fuel Product | Gasoline swaps | Sales
Derivative instruments designated as cash flow hedges
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	38,388	29,468
Fuel Product | Gasoline swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	(52,038)	(1,850)
Fuel Product | Diesel swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(59,260)	(53,622)
Fuel Product | Diesel swaps | Sales
Derivative instruments designated as cash flow hedges
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	62,966	79,810
Fuel Product | Diesel swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	(10,518)	(573)
Fuel Product | Jet fuel swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(39,931)	(77,288)
Fuel Product | Jet fuel swaps | Sales
Derivative instruments designated as cash flow hedges
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	104,482	102,473
Fuel Product | Jet fuel swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	(123)	(2,715)
Specialty Product | Crude oil swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	0
Specialty Product | Crude oil swaps | Cost of sales
Derivative instruments designated as cash flow hedges
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	(1,877)	2,512
Specialty Product | Crude oil swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	0	0
Specialty Product | Natural gas swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	0
Specialty Product | Natural gas swaps | Cost of sales
Derivative instruments designated as cash flow hedges
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	0	0
Specialty Product | Natural gas swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	0	0
Specialty Product | Interest rate swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	1,979
Specialty Product | Interest rate swaps | Interest expense
Derivative instruments designated as cash flow hedges
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	0	702
Specialty Product | Interest rate swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	$ 0	$ 0

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Commitments and Contingencies - Purchase Commitments (Details) (USD $)		12 Months Ended			3 Months Ended	12 Months Ended	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 BP Purchase Agreement	Dec. 31, 2012 BP Purchase Agreement Minimum	Dec. 31, 2012 BP Purchase Agreement Maximum	Jan. 01, 2013 Houston Refining	Dec. 31, 2012 LVT Feedstock Agreement	Jan. 01, 2013 White Mineral Oil [Member] Houston Refining	Jan. 01, 2013 White Mineral Oil [Member] Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Daily required commitment			35,000	45,000			3,100	800
Intial term		1 year				10 years
Automatic renewal term		1 year
Termination notice		90 days
Limited interest in collateral pledged				$ 100,000
Annual purchase amount					162,916,000	76,355,000
Purchase Obligation, Future Minimum Commitments
2013	999,146,000
2014	157,812,000
2015	937,000
2016	579,000
2017	0
Thereafter	0
Total	$ 1,158,474,000

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Derivatives (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2012 contract	Dec. 31, 2011
Derivative [Line Items]
Number of Credit Risk Counterparties, Held in Asset Position	2
Credit Risk Derivative Assets, at Fair Value	$ 3,088,000
Credit Derivative, Collateral Held Directly or by Third Parties	0	0
Credit Risk Derivatives, at Fair Value, Net	(7,515,000)	3,561,000
Cash flow hedges classified in accumulated other comprehensive Income (loss)	(13,953,000)	47,094,000
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	(7,755)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	154,085,000	104,020,000
Standby Letters of Credit
Derivative [Line Items]
Letter of Credit Issued to Hedging Counterparty	25,000,000	25,000,000
Realized Gain
Derivative [Line Items]
Discontinuation of Cash Flow Hedge	40096
Unrealized Gain (Loss) [Member]
Derivative [Line Items]
Discontinuation of Cash Flow Hedge	2933
Jet fuel
Derivative [Line Items]
Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring	1,719,000
Not Designated as Hedging Instrument | Specialty products segment | Crude oil swaps | Unrealized Gain
Derivative [Line Items]
Derivative, Gain on Derivative	$ 1,649,000
Fourth Quarter 2012 | Not Designated as Hedging Instrument | Specialty products segment | Crude oil swaps
Derivative [Line Items]
Number of Barrels Purchased	200,000

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Summary of Significant Accounting Policies - Advertising Expense (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]
Advertising expense	$ 8,232	$ 1,699	$ 443

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Unit-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of the Company's nonvested phantom units

A summary of the Company’s nonvested phantom units as of December 31, 2012, and the changes during the years ended December 31, 2012, 2011 and 2010, are presented below:

	Number of Phantom Units		Weighted-Average Grant Date Fair Value
Non-vested at January 1, 2010	57,493		$	12.42
Granted	138,490		20.11
Vested	(90,491	)	18.05
Forfeited	—		—
Non-vested at December 31, 2010	105,492		$	17.68
Granted	640,875		20.26
Vested	(183,671	)	20.29
Forfeited	—		—
Non-vested at December 31, 2011	562,696		$	19.77
Granted	616,997		26.69
Vested	(286,976	)	21.16
Forfeited	(56,790	)	20.00
Non-vested at December 31, 2012	835,927		$	27.57

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Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivative assets:
Total derivative assets	$ 3,088	$ 58,502
Derivative liabilities:
Total derivative liabilities	47,968	43,581
Level 1
Derivative assets:
Pension plan investments	38,835	33,580
Level 2
Derivative assets:
Pension plan investments	2,731	2,462
Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Pension plan investments	38,835	33,580
Total recurring assets at fair value	38,835	33,580
Derivative liabilities:
Total derivative liabilities	0	0
Liability Awards	(2,239)	0
Total recurring liabilities at fair value	(2,239)	0
Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Pension plan investments	2,731	2,462
Total recurring assets at fair value	2,731	2,462
Derivative liabilities:
Total derivative liabilities	0	0
Liability Awards	0	0
Total recurring liabilities at fair value	0	0
Recurring | Level 3
Derivative assets:
Total derivative assets	3,088	58,502
Pension plan investments	0	0
Total recurring assets at fair value	3,088	58,502
Derivative liabilities:
Total derivative liabilities	(47,968)	(43,581)
Liability Awards	0	0
Total recurring liabilities at fair value	(47,968)	(43,581)
Recurring | Total
Derivative assets:
Total derivative assets	3,088	58,502
Pension plan investments	41,566	36,042
Total recurring assets at fair value	44,654	94,544
Derivative liabilities:
Total derivative liabilities	(47,968)	(43,581)
Liability Awards	(2,239)	0
Total recurring liabilities at fair value	(50,207)	(43,581)
Crude oil swaps | Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude oil swaps | Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude oil swaps | Recurring | Level 3
Derivative assets:
Total derivative assets	10,517	83,919
Derivative liabilities:
Total derivative liabilities	(35,819)	56,041
Crude oil swaps | Recurring | Total
Derivative assets:
Total derivative assets	10,517	83,919
Derivative liabilities:
Total derivative liabilities	(35,819)	56,041
Crude oil basis swaps | Recurring | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Crude oil basis swaps | Recurring | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Crude oil basis swaps | Recurring | Level 3
Derivative liabilities:
Total derivative liabilities	(3,363)	0
Crude oil basis swaps | Recurring | Total
Derivative liabilities:
Total derivative liabilities	(3,363)	0
Gasoline swaps | Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline swaps | Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline swaps | Recurring | Level 3
Derivative assets:
Total derivative assets	273	(20,605)
Derivative liabilities:
Total derivative liabilities	(85)	(1,596)
Gasoline swaps | Recurring | Total
Derivative assets:
Total derivative assets	273	(20,605)
Derivative liabilities:
Total derivative liabilities	(85)	(1,596)
Diesel swaps | Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel swaps | Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel swaps | Recurring | Level 3
Derivative assets:
Total derivative assets	(7,871)	(4,561)
Derivative liabilities:
Total derivative liabilities	(6,403)	(22,586)
Diesel swaps | Recurring | Total
Derivative assets:
Total derivative assets	(7,871)	(4,561)
Derivative liabilities:
Total derivative liabilities	(6,403)	(22,586)
Jet fuel swaps | Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Jet fuel swaps | Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Jet fuel swaps | Recurring | Level 3
Derivative assets:
Total derivative assets	169	1,077
Derivative liabilities:
Total derivative liabilities	(2,298)	(72,537)
Jet fuel swaps | Recurring | Total
Derivative assets:
Total derivative assets	169	1,077
Derivative liabilities:
Total derivative liabilities	(2,298)	(72,537)
Natural gas swaps | Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural gas swaps | Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural gas swaps | Recurring | Level 3
Derivative assets:
Total derivative assets	0	(1,328)
Derivative liabilities:
Total derivative liabilities	0	(1,892)
Natural gas swaps | Recurring | Total
Derivative assets:
Total derivative assets	0	(1,328)
Derivative liabilities:
Total derivative liabilities	0	(1,892)
Interest rate swaps | Recurring | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Interest rate swaps | Recurring | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Interest rate swaps | Recurring | Level 3
Derivative liabilities:
Total derivative liabilities	0	(1,011)
Interest rate swaps | Recurring | Total
Derivative liabilities:
Total derivative liabilities	$ 0	$ (1,011)

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Derivatives (Details 6)	Dec. 31, 2012 bbl	Dec. 31, 2011 bbl
Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	3,773,000
Non Cash Flow Hedging | Crude oil basis swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	912,000
Average Differential to NYMEX WTI ($/Bbl)	(25.20)
First Quarter 2013 | Non Cash Flow Hedging | Crude oil basis swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	180,000
BPD	2,000
Average Differential to NYMEX WTI ($/Bbl)	(23.75)
Second Quarter 2013 | Non Cash Flow Hedging | Crude oil basis swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	364,000
BPD	4,000
Average Differential to NYMEX WTI ($/Bbl)	(27.38)
Third Quarter 2013 | Non Cash Flow Hedging | Crude oil basis swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	184,000
BPD	2,000
Average Differential to NYMEX WTI ($/Bbl)	(23.75)
Fourth Quarter 2013 | Non Cash Flow Hedging | Crude oil basis swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	184,000
BPD	2,000
Average Differential to NYMEX WTI ($/Bbl)	(23.75)
Fuel Product | Non Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	1,821,000
Average Swap ($/Bbl)	98.72
Fuel Product | Non Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	1,456,000
Average Swap ($/Bbl)	127.20
Fuel Product | Non Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	365,000
Average Swap ($/Bbl)	105.50
Fuel Product | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	15,997,500	16,536,000
Average Swap ($/Bbl)	92.85	89.07
Fuel Product | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	10,864,500	5,312,000
Average Swap ($/Bbl)	117.13	114.44
Fuel Product | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		6,882,500
Average Swap ($/Bbl)	123.56	109.60
Fuel Product | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	1,360,000	4,341,500
Average Swap ($/Bbl)	114.84	102.63
Fuel Product | Calendar Year 2014 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	5,110,000	1,000,000
BPD	14,000	2,740
Average Swap ($/Bbl)	89.47	90.55
Fuel Product | Calendar Year 2014 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	4,781,500
Barrels per Day Sold	13,100
Average Swap ($/Bbl)	115.81
Fuel Product | Calendar Year 2014 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	1,275,000	1,000,000
Barrels per Day Sold	3,493	2,740
Average Swap ($/Bbl)	116.64	115.56
Fuel Product | First Quarter 2013 | Non Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	630,000
BPD	7,000
Average Swap ($/Bbl)	101.34
Fuel Product | First Quarter 2013 | Non Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	540,000
Barrels per Day Sold	6,000
Average Swap ($/Bbl)	130.57
Fuel Product | First Quarter 2013 | Non Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	90,000
Barrels per Day Sold	1,000
Average Swap ($/Bbl)	105.50
Fuel Product | First Quarter 2013 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	1,665,000
BPD	18,500
Average Swap ($/Bbl)	101.67
Fuel Product | First Quarter 2013 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	1,035,000
Barrels per Day Sold	11,500
Average Swap ($/Bbl)	127.39
Fuel Product | First Quarter 2013 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	630,000
Barrels per Day Sold	7,000
Average Swap ($/Bbl)	113.59
Fuel Product | Second Quarter 2013 | Non Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	455,000
BPD	5,000
Average Swap ($/Bbl)	98.56
Fuel Product | Second Quarter 2013 | Non Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	364,000
Barrels per Day Sold	4,000
Average Swap ($/Bbl)	126.82
Fuel Product | Second Quarter 2013 | Non Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	91,000
Barrels per Day Sold	1,000
Average Swap ($/Bbl)	105.50
Fuel Product | Second Quarter 2013 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	1,911,000
BPD	21,000
Average Swap ($/Bbl)	100.22
Fuel Product | Second Quarter 2013 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	546,000
Barrels per Day Sold	6,000
Average Swap ($/Bbl)	122.74
Fuel Product | Second Quarter 2013 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	819,000
Barrels per Day Sold	9,000
Average Swap ($/Bbl)	129.20
Fuel Product | Second Quarter 2013 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	546,000
Barrels per Day Sold	6,000
Average Swap ($/Bbl)	116.32
Fuel Product | Third Quarter 2013 | Non Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	368,000
BPD	4,000
Average Swap ($/Bbl)	96.58
Fuel Product | Third Quarter 2013 | Non Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	276,000
Barrels per Day Sold	3,000
Average Swap ($/Bbl)	124.17
Fuel Product | Third Quarter 2013 | Non Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	92,000
Barrels per Day Sold	1,000
Average Swap ($/Bbl)	105.50
Fuel Product | Third Quarter 2013 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	1,426,000
BPD	15,500
Average Swap ($/Bbl)	95.62
Fuel Product | Third Quarter 2013 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	874,000
Barrels per Day Sold	9,500
Average Swap ($/Bbl)	122.23
Fuel Product | Third Quarter 2013 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	368,000
Barrels per Day Sold	4,000
Average Swap ($/Bbl)	125.13
Fuel Product | Third Quarter 2013 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	184,000
Barrels per Day Sold	2,000
Average Swap ($/Bbl)	114.73
Fuel Product | Fourth Quarter 2013 | Non Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	368,000
BPD	4,000
Average Swap ($/Bbl)	96.58
Fuel Product | Fourth Quarter 2013 | Non Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	276,000
Barrels per Day Sold	3,000
Average Swap ($/Bbl)	124.17
Fuel Product | Fourth Quarter 2013 | Non Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	92,000
Barrels per Day Sold	1,000
Average Swap ($/Bbl)	105.50
Fuel Product | Fourth Quarter 2013 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	1,104,000
BPD	12,000
Average Swap ($/Bbl)	93.41
Fuel Product | Fourth Quarter 2013 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	828,000
Barrels per Day Sold	9,000
Average Swap ($/Bbl)	120.82
Fuel Product | Fourth Quarter 2013 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	276,000
Barrels per Day Sold	3,000
Average Swap ($/Bbl)	122.36
Fuel Product | First Quarter 2012 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased		2,866,500
BPD		31,500
Average Swap ($/Bbl)		85.34
Fuel Product | First Quarter 2012 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		546,000
Barrels per Day Sold		6,000
Average Swap ($/Bbl)		118.07
Fuel Product | First Quarter 2012 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		1,274,000
Barrels per Day Sold		14,000
Average Swap ($/Bbl)		97.97
Fuel Product | First Quarter 2012 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		1,046,500
Barrels per Day Sold		11,500
Average Swap ($/Bbl)		100.72
Fuel Product | Second Quarter 2012 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased		2,775,500
BPD		30,500
Average Swap ($/Bbl)		84.83
Fuel Product | Second Quarter 2012 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		819,000
Barrels per Day Sold		9,000
Average Swap ($/Bbl)		110.09
Fuel Product | Second Quarter 2012 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		1,046,500
Barrels per Day Sold		11,500
Average Swap ($/Bbl)		98.47
Fuel Product | Second Quarter 2012 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		910,000
Barrels per Day Sold		10,000
Average Swap ($/Bbl)		102.48
Fuel Product | Third Quarter 2012 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased		2,852,000
BPD		31,000
Average Swap ($/Bbl)		84.83
Fuel Product | Third Quarter 2012 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		1,150,000
Barrels per Day Sold		12,500
Average Swap ($/Bbl)		105.48
Fuel Product | Third Quarter 2012 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		782,000
Barrels per Day Sold		8,500
Average Swap ($/Bbl)		99.78
Fuel Product | Third Quarter 2012 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		920,000
Barrels per Day Sold		10,000
Average Swap ($/Bbl)		102.48
Fuel Product | Fourth Quarter 2012 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased		2,622,000
BPD		28,500
Average Swap ($/Bbl)		86.73
Fuel Product | Fourth Quarter 2012 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		966,000
Barrels per Day Sold		10,500
Average Swap ($/Bbl)		110.11
Fuel Product | Fourth Quarter 2012 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		736,000
Barrels per Day Sold		8,000
Average Swap ($/Bbl)		104.79
Fuel Product | Fourth Quarter 2012 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		920,000
Barrels per Day Sold		10,000
Average Swap ($/Bbl)		102.48
Fuel Product | Calendar Year 2013 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased		4,420,000
BPD		12,110
Average Swap ($/Bbl)		97.93
Fuel Product | Calendar Year 2013 | Cash Flow Hedging | Diesel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold	3,835,000	1,831,000
Barrels per Day Sold	10,507	5,016
Average Swap ($/Bbl)	116.00	123.20
Fuel Product | Calendar Year 2013 | Cash Flow Hedging | Jet fuel swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		2,044,000
Barrels per Day Sold		5,600
Average Swap ($/Bbl)		125.13
Fuel Product | Calendar Year 2013 | Cash Flow Hedging | Gasoline swaps
Derivatives related to crude oil purchases in fuel products segment
Barrels Sold		545,000
Barrels per Day Sold		1,493
Average Swap ($/Bbl)		107.11
Fuel Product | Calendar Year 2015 | Cash Flow Hedging | Crude Oil Swaps [Member]
Derivatives related to crude oil purchases in fuel products segment
Barrels Purchased	4,781,500
BPD	13,100
Average Swap ($/Bbl)	89.49

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Employee Benefit Plans - Change in Benefit Obligation, Plan Assets and Funded Status (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of amounts recognized in the consolidated balance sheets:
Accumulated other comprehensive (income) loss	$ (11,526)	$ (8,567)
Pension Plans, Defined Benefit
Change in projected benefit obligation (“PBO”):
Benefit obligation at beginning of year	55,265	24,761
Projected benefit obligation attributable to acquisitions	4,900	26,218
Service cost	1,130	296	84
Interest cost	2,376	1,638	1,336
Plan curtailments	(3,685)	0
Benefits paid	(2,607)	(1,162)
Actuarial loss	7,897	3,554
Administrative expense	(40)	(40)
Plan amendments	0	0
Employee contributions	0	0
Benefit obligation at end of year	65,236	55,265	24,761
Change in plan assets:
Fair value of plan assets at beginning of year	36,042	16,039
Fair value of pension assets attributable to acquisitions	3,178	17,718
Benefit payments	(2,607)	(1,162)
Actual return on assets	1,917	1,568
Administrative expense	(40)	(40)
Employee contributions	0	0
Employer contribution	3,076	1,919
Fair value of plan assets at end of year	41,566	36,042	16,039
Funded status — benefit obligation in excess of plan assets	(23,670)	(19,223)
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	(23,670)	(19,223)
Prior service credit	0	0
Unrecognized net actuarial loss (gain)	11,927	8,289
Accumulated other comprehensive (income) loss	11,927	8,289
Net amount recognized at end of year	(11,743)	(10,934)
Other Postretirement Benefit Plans, Defined Benefit
Change in projected benefit obligation (“PBO”):
Benefit obligation at beginning of year	7,734	446
Projected benefit obligation attributable to acquisitions	0	6,477
Service cost	287	114	0
Interest cost	185	96	23
Plan curtailments	(7,873)	0
Benefits paid	(80)	(81)
Actuarial loss	106	624
Administrative expense	0	0
Plan amendments	(81)	0
Employee contributions	51	58
Benefit obligation at end of year	329	7,734	446
Change in plan assets:
Fair value of plan assets at beginning of year	0	0
Fair value of pension assets attributable to acquisitions	0	0
Benefit payments	(80)	(81)
Actual return on assets	0	0
Administrative expense	0	0
Employee contributions	51	58
Employer contribution	29	23
Fair value of plan assets at end of year	0	0	0
Funded status — benefit obligation in excess of plan assets	(329)	(7,734)
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	(329)	(7,734)
Prior service credit	(240)	(275)
Unrecognized net actuarial loss (gain)	(161)	553
Accumulated other comprehensive (income) loss	(401)	278
Net amount recognized at end of year	$ (730)	$ (7,456)

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Commitments and Contingencies - Insurance Recoveries (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitments and Contingencies Disclosure [Abstract]
Insurance recoveries	$ 0	$ 8,698	$ 0
Proceeds from insurance settlement	$ 0	$ 1,942	$ 0

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Derivatives (Details 9) (Jet fuel swaps)	Dec. 31, 2012	Dec. 31, 2011 bbl
Derivatives related to jet fuel sales in fuel products segment
Barrels Sold	3,773,000
Fuel Product | Cash flow hedges
Derivatives related to jet fuel sales in fuel products segment
Barrels Sold		6,882,500
Average Swap ($/Bbl)	123.56	109.60

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Unit-Based Compensation (Details Textual) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for grant under the Plan	783,960
Vested phantom unit grants
Unit-Based Compensation (Textual) [Abstract]
Compensation expense related to vested phantom unit grants	$ 4,583	$ 3,027	$ 784
Vested phantom unit grants, liability awards
Unit-Based Compensation (Textual) [Abstract]
Compensation expense related to vested phantom unit grants	2,239
Nonvested phantom units
Unit-Based Compensation (Textual) [Abstract]
Unit-Based Compensation nonvested phantom compensation costs are expected to be recognized over a weighted-average period	3 years
Unit-Based Compensation (Additional Textual) [Abstract]
Unrecognized compensation costs related to nonvested phantom unit grants	23,044	11,124
Fair value of phantom units vested during the period	6,083	3,727
Nonvested phantom units, liability awards [Member]
Unit-Based Compensation (Textual) [Abstract]
Compensation expense related to vested phantom unit grants	$ 16,139
Long-Term Incentive Plan | Phantom Share Units (PSUs) [Member]
Unit-Based Compensation (Additional Textual) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Annual Vesting | Director Compensation Package | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	25.00%
Director | Long-Term Incentive Plan | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Service period	4 years
Management [Member] | Long-Term Incentive Plan | Phantom Share Units (PSUs) [Member]
Unit-Based Compensation (Additional Textual) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Management [Member] | Vested at Grant | Long-Term Incentive Plan | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	25.00%

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Fair Value Measurements (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value
Financial Instrument:
Capital lease and other obligations	$ 5,512	$ 786
Fair Value | 2019 Notes
Financial Instrument:
Notes payable	658,795	591,750
Fair Value | 2020 Notes
Financial Instrument:
Notes payable	301,813	0
Carrying Value
Financial Instrument:
Capital lease and other obligations	5,512	786
Carrying Value | 2019 Notes
Financial Instrument:
Notes payable	587,602	586,304
Carrying Value | 2020 Notes
Financial Instrument:
Notes payable	$ 270,387	$ 0

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Employee Benefit Plans - Defined Contribution Plan (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 plan	Dec. 31, 2011	Dec. 31, 2010
Defined Contribution Plan [Line Items]
Number of plans	2
Employer matching contribution, amount	$ 3,224	$ 2,343	$ 1,948
Employer discretionary contribution amount	$ 2,511	$ 1,448	$ 1,331
Calumet 401k Plan
Defined Contribution Plan [Line Items]
Employer matching contribution, percent	5.00%
Calumet 401k Plan | Minimum
Defined Contribution Plan [Line Items]
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	0.00%
Calumet 401k Plan | Maximum
Defined Contribution Plan [Line Items]
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	70.00%
Calumet 401k Plan | Up to 4%
Defined Contribution Plan [Line Items]
Employer matching contribution, percent of match	100.00%
Maximum annual contributions per employee, incremental percentage point	1.00%
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	4.00%
Calumet 401k Plan | Up to 4% | Maximum
Defined Contribution Plan [Line Items]
Employer matching contribution, percent of match range	4.00%
Calumet 401k Plan | 4% - 6%
Defined Contribution Plan [Line Items]
Employer matching contribution, percent of match	50.00%
Maximum annual contributions per employee, incremental percentage point	1.00%
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	6.00%
Calumet 401k Plan | 4% - 6% | Minimum
Defined Contribution Plan [Line Items]
Employer matching contribution, percent of match range	4.00%
Calumet 401k Plan | 4% - 6% | Maximum
Defined Contribution Plan [Line Items]
Employer matching contribution, percent of match range	6.00%
Calumet 401k Plan | Up to 6% [Member] | Maximum
Defined Contribution Plan [Line Items]
Employer matching contribution, percent of match range	6.00%
Montana 401k Plan | Up to 6% [Member]
Defined Contribution Plan [Line Items]
Employer matching contribution, percent of match	100.00%
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	6.00%

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Derivatives (Details 10) (Gasoline swaps, Fuel Product)	Dec. 31, 2012 bbl	Dec. 31, 2011 bbl
Cash flow hedges
Derivatives related to gasoline sales in fuel products segment
Barrels Sold	1,360,000	4,341,500
Average Swap ($/Bbl)	114.84	102.63
Non cash flow hedges
Derivatives related to gasoline sales in fuel products segment
Barrels Sold	365,000
Average Swap ($/Bbl)	105.50

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Derivatives (Details 4) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	$ 5,665	$ (18,292)	$ (23,547)
Derivative instruments not designated as hedges | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(3,310)	(2,109)
Derivative instruments not designated as hedges | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(28,018)	(2,886)
Fuel Product | Derivative instruments not designated as hedges | Crude oil swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(30,488)	0
Fuel Product | Derivative instruments not designated as hedges | Crude oil swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(39,967)	0
Fuel Product | Derivative instruments not designated as hedges | Gasoline swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	22,110	0
Fuel Product | Derivative instruments not designated as hedges | Gasoline swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	519	0
Fuel Product | Derivative instruments not designated as hedges | Diesel swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	10,895	0
Fuel Product | Derivative instruments not designated as hedges | Diesel swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	8,912	0
Fuel Product | Derivative instruments not designated as hedges | Jet fuel swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1,719)	0
Fuel Product | Derivative instruments not designated as hedges | Jet fuel swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Fuel Product | Derivative instruments not designated as hedges | Jet fuel collars | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(746)
Fuel Product | Derivative instruments not designated as hedges | Jet fuel collars | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	726
Specialty Product | Derivative instruments not designated as hedges | Crude oil swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	932
Specialty Product | Derivative instruments not designated as hedges | Crude oil swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1,649	(662)
Specialty Product | Derivative instruments not designated as hedges | Natural gas swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(5,442)	(171)
Specialty Product | Derivative instruments not designated as hedges | Natural gas swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3,221	(3,221)
Specialty Product | Derivative instruments not designated as hedges | Interest rate swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(732)	(2,124)
Specialty Product | Derivative instruments not designated as hedges | Interest rate swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 1,011	$ 271

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Inventories

Inventories consist of the following:

	December 31,
	2012		2011
Raw materials	$	85,399	$	105,802
Work in process	119,526		91,763
Finished goods	348,649		300,175
	$	553,574	$	497,740

Allowance for Doubtful Accounts Activity

The activity in the allowance for doubtful accounts was as follows:

	December 31,
	2012			2011			2010
Beginning balance	$	925		$	633		$	801
Provision	362			380			(61		)
Recoveries	17			—			—
Write-offs, net	(154		)	(88		)	(107		)
Ending balance	$	1,150		$	925		$	633

Property, Plant and Equipment

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

	December 31,
	2012			2011
Land	$	11,229		$	8,857
Buildings and improvements (10 to 40 years)	28,063			19,729
Machinery and equipment (10 to 20 years)	1,172,970			1,012,318
Furniture and fixtures (5 to 10 years)	7,624			5,732
Assets under capital leases (1 to 4 years)	11,071			4,201
Construction-in-progress	53,790			22,945
	1,284,747			1,073,782
Less accumulated depreciation	(297,872		)	(231,681		)
	$	986,875		$	842,101

Advertising Costs, Policy [Policy Text Block]

The Company expenses advertising costs as incurred

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Acquisitions (Details 3) (Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions, USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions
Condensed consolidated results of operations
Sales	$ 5,064,795	$ 4,804,528
Net income	$ 234,601	$ 103,114
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 3.86	$ 1.75
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 3.85	$ 1.75

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Summary of Significant Accounting Policies - Goodwill (Details)	12 Months Ended
	Dec. 31, 2012
Accounting Policies [Abstract]
Reviews for goodwill impairment annually on	Oct. 01, 2012

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Derivatives (Details 8) (Fuel Product, Diesel swaps)	Dec. 31, 2012 bbl	Dec. 31, 2011 bbl
Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	10,864,500	5,312,000
Average Swap ($/Bbl)	117.13	114.44
Non cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	1,456,000
Average Swap ($/Bbl)	127.20
First Quarter 2013 | Non cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	540,000
BPD	6,000
Average Swap ($/Bbl)	130.57
First Quarter 2012 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold		546,000
BPD		6,000
Average Swap ($/Bbl)		118.07
Second Quarter 2012 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold		819,000
BPD		9,000
Average Swap ($/Bbl)		110.09
Third Quarter 2012 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold		1,150,000
BPD		12,500
Average Swap ($/Bbl)		105.48
Fourth Quarter 2012 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold		966,000
BPD		10,500
Average Swap ($/Bbl)		110.11
Calendar Year 2013 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	3,835,000	1,831,000
BPD	10,507	5,016
Average Swap ($/Bbl)	116.00	123.20
Calendar Year 2014 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	4,781,500
BPD	13,100
Average Swap ($/Bbl)	115.81
Second Quarter 2013 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	546,000
BPD	6,000
Average Swap ($/Bbl)	122.74
Second Quarter 2013 | Non cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	364,000
BPD	4,000
Average Swap ($/Bbl)	126.82
Third Quarter 2013 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	874,000
BPD	9,500
Average Swap ($/Bbl)	122.23
Third Quarter 2013 | Non cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	276,000
BPD	3,000
Average Swap ($/Bbl)	124.17
Fourth Quarter 2013 | Cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	828,000
BPD	9,000
Average Swap ($/Bbl)	120.82
Fourth Quarter 2013 | Non cash flow hedges
Derivatives related to diesel sales in fuel product segment
Barrels Sold	276,000
BPD	3,000
Average Swap ($/Bbl)	124.17

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Earnings Per Unit (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Jan. 01, 2013	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Numerator for basic and diluted earnings per limited partner unit:
Net income	$ 45,736	$ 42,416	$ 65,662	$ 51,923	$ 26,872	$ 19,614	$ (7,651)	$ 4,201	$ 205,737	$ 43,036	$ 16,701
General partner’s interest in net income									4,115	861	334
General partner’s incentive distribution rights									5,433	322	0
Nonvested share based payments									1,199	0	0
Net income available to limited partners	$ 42,392	$ 39,669	$ 62,875	$ 50,054	$ 26,052	$ 19,182	$ (7,498)	$ 4,117	$ 194,990	$ 41,853	$ 16,367
Denominator for basic and diluted earnings per limited partner unit:
Weighted average limited partner units outstanding — basic	57,746,000	57,746,000	55,028,000	51,685,000	51,589,000	41,828,000	39,886,000	36,875,000	55,559,000	42,599,000	35,335,000
Participating securities — phantom units									118,000	45,000	16,000
Weighted average limited partner units outstanding — diluted	57,898,000	57,826,000	55,074,000	51,736,000	51,600,000	41,837,000	39,886,000	36,895,000	55,677,000	42,644,000	35,351,000
Limited partners’ interest basic net income per unit	0.73	0.69	1.14	0.97					3.51	0.98	0.46
Limited partners’ interest diluted net income per unit	0.73	0.69	1.14	0.97					3.50	0.98	0.46

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total (1)
2012
Sales	$	1,169,586	$	1,086,996	$	1,179,818	$	1,220,882	$	4,657,282
Gross profit	84,244		128,808		158,406		141,719		513,177
Net income	51,923		65,662		42,416		45,736		205,737
Net income available to limited partners	50,054		62,875		39,669		42,392		194,990
Limited partners’ interest basic net income per unit	$	0.97	$	1.14	$	0.69	$	0.73	$	3.51
Limited partners’ interest diluted net income per unit	$	0.97	$	1.14	$	0.69	$	0.73	$	3.50
Weighted average limited partner units outstanding — basic	51,685,000		55,028,000		57,746,000		57,746,000
Weighted average limited partner units outstanding — diluted	51,736,000		55,074,000		57,826,000		57,898,000

	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

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

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Goodwill and Intangible Assets - Changes in Goodwill (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Goodwill
Beginning balance:	$ 48,335,000	$ 48,335,000
Acquisitions	138,678,000	0
Accumulated impairment losses	0	0
Ending balance:	187,013,000	48,335,000
Specialty Product
Goodwill
Beginning balance:	48,335,000
Acquisitions	111,035,000	0
Accumulated impairment losses	0	0
Ending balance:	159,370,000	48,335,000
Fuel Product
Goodwill
Beginning balance:	0	0
Acquisitions	27,643,000	0
Accumulated impairment losses	0	0
Ending balance:	$ 27,643,000	$ 0

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Derivatives (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivative assets and liabilities at fair values
Derivative Assets	$ 3,088	$ 58,502
Derivative Liabilities	(47,968)	(43,581)
Derivative instruments not designated as hedges
Derivative assets and liabilities at fair values
Derivative Assets	0	(1,328)
Derivative Liabilities	(10,682)	(2,903)
Fuel Product | Derivative instruments designated as hedges
Derivative assets and liabilities at fair values
Derivative Assets	3,088	59,830
Derivative Liabilities	(37,286)	(40,678)
Fuel Product | Derivative instruments designated as hedges | Crude oil swaps
Derivative assets and liabilities at fair values
Derivative Assets	10,517	83,919
Derivative Liabilities	(26,743)	56,041
Fuel Product | Derivative instruments designated as hedges | Gasoline swaps
Derivative assets and liabilities at fair values
Derivative Assets	273	(20,605)
Derivative Liabilities	2,086	(1,596)
Fuel Product | Derivative instruments designated as hedges | Diesel swaps
Derivative assets and liabilities at fair values
Derivative Assets	(7,871)	(4,561)
Derivative Liabilities	(10,331)	(22,586)
Fuel Product | Derivative instruments designated as hedges | Jet fuel swaps
Derivative assets and liabilities at fair values
Derivative Assets	169	1,077
Derivative Liabilities	(2,298)	(72,537)
Fuel Product | Derivative instruments not designated as hedges | Crude oil swaps
Derivative assets and liabilities at fair values
Derivative Assets	0	0
Derivative Liabilities	(10,725)	0
Fuel Product | Derivative instruments not designated as hedges | Crude oil basis swaps
Derivative assets and liabilities at fair values
Derivative Assets	0	0
Derivative Liabilities	(3,363)	0
Fuel Product | Derivative instruments not designated as hedges | Gasoline swaps
Derivative assets and liabilities at fair values
Derivative Assets	0	0
Derivative Liabilities	(2,171)	0
Fuel Product | Derivative instruments not designated as hedges | Diesel swaps
Derivative assets and liabilities at fair values
Derivative Assets	0	0
Derivative Liabilities	3,928	0
Specialty Product | Derivative instruments not designated as hedges | Crude oil swaps
Derivative assets and liabilities at fair values
Derivative Assets	0	0
Derivative Liabilities	1,649	0
Specialty Product | Derivative instruments not designated as hedges | Natural gas swaps
Derivative assets and liabilities at fair values
Derivative Assets	0	(1,328)
Derivative Liabilities	0	(1,892)
Specialty Product | Derivative instruments not designated as hedges | Interest rate swaps
Derivative assets and liabilities at fair values
Derivative Assets	0	0
Derivative Liabilities	$ 0	$ (1,011)

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Long-Term Debt - Schedule of Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Summary of Long-term debt
Total long-term debt	$ 863,501	$ 587,090
Less current portion of long-term debt	771	551
Long-term Debt, Excluding Current Maturities	862,730	586,539
Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012
Debt Instrument [Line Items]
Effective interest rate percentage	9.91%
Summary of Long-term debt
Borrowings under 2019 Notes and 2020 Notes	600,000	600,000
Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012
Debt Instrument [Line Items]
Effective interest rate percentage	10.00%
Summary of Long-term debt
Borrowings under 2019 Notes and 2020 Notes	275,000	0
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027
Summary of Long-term debt
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	5,512	786
Less unamortized discounts
Summary of Long-term debt
Less unamortized discounts	$ (17,011)	$ (13,696)

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Acquisitions (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Superior Acquisition	Dec. 31, 2012 TruSouth Acquisition	Jan. 06, 2012 TruSouth Acquisition	Dec. 31, 2012 Missouri Acquisition	Dec. 31, 2012 Royal Purple Acquisition	Jul. 03, 2011 Royal Purple Acquisition	Dec. 31, 2012 Montana Acquisition
The allocation of the aggregate purchase price to assets acquired and liabilities assumed:
Accounts receivable					$ 5,217			$ 15,159		$ 28,973
Inventories				183,602	7,976		2,775	19,299		43,682
Prepaid expenses and other current assets				5,845	272			236		23,105
Deposits								13		256
Property, plant and equipment				239,478	17,682		9,955	10,579		125,472
Goodwill					392		1,478	109,165		27,643
Other intangible assets					2,545	2,545	5,367	183,398	183,398
Accounts payable					(2,672)			(3,804)		(8,402)
Accrued salaries, wages and benefits				(775)	(151)			(1,698)		(1,448)
Business Acquisition, Purchase Price Allocation, Deferred Taxes Asset (Liability), Net, Noncurrent										(27,643)
Accrued salaries, wages and benefits								(198)		(3,015)
Other current liabilities					(918)			(910)		(107)
Long-term debt					(3,516)
Total purchase price				413,173	26,827		19,575	331,239
Goodwill	187,013	48,335	48,335
Other noncurrent assets, net										327
Accrued income taxes payable										(15,571)
Pension and postretirement benefit obligations				(14,977)						(1,722)
Total purchase price, net of cash acquired										$ 191,550

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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, TruSouth Oil, LLC, Calumet Montana Refining, LLC, S&S International Mining Enterprises, Inc., Royal Purple, 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 inventory is recorded 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. The replacement cost of these inventories, based on current market values, would have been $38,295 and $87,635 higher as of December 31, 2012 and 2011, respectively.

Inventories consist of the following:

	December 31,
	2012		2011
Raw materials	$	85,399	$	105,802
Work in process	119,526		91,763
Finished goods	348,649		300,175
	$	553,574	$	497,740

Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. During the year ended December 31, 2012, the Company recorded $4,206 of losses in cost of sales in the consolidated statements of operations due to the liquidation of higher cost inventory layers. During the years ended December 31, 2011 and 2010 the Company recorded $5,166 and $13,661, respectively, of gains in cost of sales in the consolidated statements of operations due to the liquidation of lower cost inventory layers.

In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. During the years ended December 31, 2012, 2011 and 2010 the Company recorded $8,124, $1,976 and $76 of losses in cost of sales in the consolidated statements of operations due to the lower of cost or market valuation.

Accounts Receivable

The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are carried at their face amounts and are generally due within 30 days 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. Individual accounts are written off against the allowance for doubtful accounts after all reasonable collection efforts have been exhausted. The activity in the allowance for doubtful accounts was as follows:

	December 31,
	2012			2011			2010
Beginning balance	$	925		$	633		$	801
Provision	362			380			(61		)
Recoveries	17			—			—
Write-offs, net	(154		)	(88		)	(107		)
Ending balance	$	1,150		$	925		$	633

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.

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

	December 31,
	2012			2011
Land	$	11,229		$	8,857
Buildings and improvements (10 to 40 years)	28,063			19,729
Machinery and equipment (10 to 20 years)	1,172,970			1,012,318
Furniture and fixtures (5 to 10 years)	7,624			5,732
Assets under capital leases (1 to 4 years)	11,071			4,201
Construction-in-progress	53,790			22,945
	1,284,747			1,073,782
Less accumulated depreciation	(297,872		)	(231,681		)
	$	986,875		$	842,101

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 2012, 2011 and 2010, the Company incurred $86,327, $49,339 and $30,886, respectively, of interest expense of which $754, $592 and $389, respectively, was capitalized as a component of property, plant and equipment.

The Company has not recorded an asset retirement obligation as of December 31, 2012 or 2011 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.

During the years ended December 31, 2012, 2011 and 2010, the Company recorded $74,292, $55,536 and $51,365, respectively, of depreciation expense on its property, plant and equipment. Depreciation expense included $1,030, $1,050 and $1,050 for the years ended 2012, 2011 and 2010, respectively, related to the Company’s capital lease assets.

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, 2012 and 2011, the Company has $15,007 and $6,037, respectively, of unamortized capitalized software costs. During the years ended December 31, 2012, 2011 and 2010, the Company recorded $967, $416, and $262, respectively, of amortization expense on capitalized computer software.

Goodwill

Goodwill represents the excess of purchase price over fair value of the net assets acquired in the acquisitions of Penreco on January 3, 2008, Missouri on January 3, 2012, TruSouth on January 6, 2012, Royal Purple on July 3, 2012 and Montana on October 1, 2012. See Note 3 for more information. 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 (“ASU 2011-08”) which amends the rules for testing goodwill for impairment. Under ASU 2011-08, 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.

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 judgment 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 its reporting units are greater than their carrying amounts. No impairment was recognized in 2012, 2011 or 2010.

Other Intangible Assets

Other intangible assets consist of tangible assets associated with supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements that were acquired in the acquisition of Penreco on January 3, 2008, the Missouri Acquisition on January 3, 2012, the TruSouth Acquisition on January 6, 2012 and the Royal Purple Acquisition on July 3, 2012. The majority of these assets are being amortized using discounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships are being amortized using the discounted estimated future cash flows method based upon assumed rates of annual customer attrition. For more information, refer to Note 4.

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.

During 2012, the Company recorded a write-down related to unutilized fixed assets within its specialty products segment. The non-cash charge of $1,640 was recorded in other operating costs and expenses on the consolidated statements of operations.

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 the 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. Generally, tax returns remain subject to examination by taxing authorities for three years. The Company had no unrecognized tax benefits as of December 31, 2012 and 2011.

Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Company’s partnership agreement. Individual partners have different investment basis 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 Company is not readily available.

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 7.

Other Noncurrent Assets

Other noncurrent assets include deferred debt issuance costs and turnaround costs. Deferred debt issuance costs were $29,414 and $26,374 as of December 31, 2012 and 2011, 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 $6,578 and $1,996 at December 31, 2012 and 2011, respectively.

Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $14,346 and $12,471 as of December 31, 2012 and 2011, 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 $17,813 and $12,538 at December 31, 2012 and 2011, 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 the Company’s partnership agreement.

Unit Based Compensation

For unit based compensation awards granted, compensation expense is recognized in the Company’s consolidated financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The unit based compensation awards vest over a period not exceeding four years. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.

Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). Liability Awards are recorded in accrued salaries, wages and benefits based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense.

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 $107,900, $94,187 and $85,471, respectively, for the years ended December 31, 2012, 2011, and 2010, in transportation expense in the consolidated statements of operations, the majority of which is billed to customers.

Advertising Expenses

The Company expenses advertising costs as incurred which totaled $8,232, $1,699 and $443 in 2012, 2011 and 2010, respectively.

New Accounting Pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the 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 was effective for the first reporting period (including interim periods) beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on the Company’s 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 amended current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income (loss) as part of the statement of partners’ capital. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income (loss) which contains two sections, net income and other comprehensive income (loss), 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 (loss) by component in both the statement in which net income is presented and the statement in which other comprehensive income (loss) 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, were effective for fiscal years (including interim periods) beginning after December 15, 2011 and are to be applied retrospectively, with early adoption permitted. The Company elected to present the components of comprehensive loss in two separate but consecutive financial statements, namely the consolidated statements of operations and the consolidated statements of comprehensive income (loss).

In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)—Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the balance sheet. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet Topic(210)—Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies the scope of the setting disclosures and addresses any unintended consequences. Amendments to ASU 2011-11, as superseded by ASU 2013-01, are effective for the first reporting period (including interim periods) beginning after January 1, 2013 and should be applied retrospectively for any period presented. The Company is in the process of evaluating the impact of the adoption of ASU 2011-11 and ASU 2013-01 on its financial statements.

In July 2012, the FASB issued ASU No. 2012-02, Intangibles (Topic 350)—Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). ASU 2012-02 permits an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is more than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset exceeds its carrying amount, quantitative impairment testing is not required. However, if an entity concludes otherwise, quantitative impairment testing is required. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The adoption of ASU 2012-02 did not have a material impact on the Company’s consolidated financial statements.

In October 2012, the FASB issued ASU No. 2012-04, Technical Corrections and Improvements (“ASU 2012-04”). ASU 2012-04 covers a wide range of topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. ASU 2012-04 is effective for fiscal periods beginning after December 15, 2012. The Company is in the process of evaluating the impact of the adoption of ASU 2012-04 on its financial statements.    

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220)—Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires entities to report either on the statement of operations or disclose in the footnotes to the consolidated financial statements the effects on earnings from items that are reclassified out of comprehensive income. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. ASU 2013-02 is effective prospectively for the first reporting period after December 15, 2012 with early adoption permitted. The adoption of ASU 2013-02 will not have a material impact on the Company’s consolidated financial statements.

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Long-Term Debt - Note Redemption Rate (Details)	12 Months Ended
	Dec. 31, 2012
Summary of Redemption Price During Period
2016	104.813%
2017	102.406%
2018 and at any time thereafter	100.00%
Borrowings under 2020 Notes, interest at a fixed rate of 9.375% | 2015
Summary of Redemption Price During Period
Percentage of redemption price	104.688%
Borrowings under 2020 Notes, interest at a fixed rate of 9.375% | 2016
Summary of Redemption Price During Period
Percentage of redemption price	102.344%
Borrowings under 2020 Notes, interest at a fixed rate of 9.375% | 2017 and any time thereafter
Summary of Redemption Price During Period
Percentage of redemption price	100.00%

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Summary of Significant Accounting Policies - Impairment of Long-Lived Assets (Details) (Specialty Product, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Specialty Product
Accounting Policies [Line Items]
Impairment of long-lived assets held-for-use	$ 1,640

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt Instrument [Line Items]

Summary of long-term debt

Long-term debt consisted of the following:

	December 31, 2012			December 31, 2011
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 9.91% for the year ended December 31, 2012	600,000			600,000
Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012	275,000			—
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	5,512			786
Less unamortized discounts	(17,011		)	(13,696		)
Total long-term debt	863,501			587,090
Less current portion of long-term debt	771			551
	$	862,730		$	586,539

Schedule of basis spread

As of December 31, 2012, the margin was 100 basis points for prime and 225 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s 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
≥ 66%	1.00%	2.25%
≥ 33% and < 66%	1.25%	2.50%
< 33%	1.50%	2.75%

Maturities of long-term debt

Year	Maturity
2013	$	771
2014	423
2015	303
2016	328
2017	355
Thereafter	878,332
Total	$	880,512

Summary of future minimum lease payments

As of December 31, 2012, the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows:

Year	Capital Leases
2013	$	1,189
2014	805
2015	661
2016	661
2017	661
Thereafter	4,789
Total minimum lease payments	8,766
Less amount representing interest	3,254
Capital lease obligations	5,512
Less obligations due within one year	771
Long-term capital lease obligations	$	4,741

Borrowings under 2020 Notes, interest at a fixed rate of 9.375%

Debt Instrument [Line Items]

Summary of redemption price during the period

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	%

Borrowings under 2019 Notes, interest at a fixed rate of 9.625%

Debt Instrument [Line Items]

Summary of redemption price during the period

if redeemed during the twelve-month period beginning on August 1 of the years indicated below:

Year	Percentage
2016	104.813	%
2017	102.406	%
2018 and at any time thereafter	100.000	%

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Operating Leases, Fiscal Year Maturity Schedule

As of December 31, 2012, 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
2013	$	23,194
2014	14,937
2015	11,752
2016	7,946
2017	5,999
Thereafter	15,094
Total	$	78,922

Purchase Commitment, Fiscal Year Maturity Schedule

As of December 31, 2012, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows:

Year	Commitment
2013	$	999,146
2014	157,812
2015	937
2016	579
2017	—
Thereafter	—
Total	$	1,158,474

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Segments and Related Information (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Segment assets
Total assets	$ 2,253,045	$ 1,732,058
Fuel Product
Segment assets
Total assets	683,249	573,018
Specialty Product
Segment assets
Total assets	$ 1,569,796	$ 1,159,040

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Commitments and Contingencies - Labor Matters (Details)	12 Months Ended
	Dec. 31, 2012 employee
Concentration Risk [Line Items]
Number of employees	1,190
Labor Force Concentration Risk | Workforce Subject to Collective Bargaining Arrangements
Concentration Risk [Line Items]
Number of employees	580
Percentage of employees	48.70%
Labor Force Concentration Risk | Workforce Subject to Collective Bargaining Arrangements Expiring within One Year
Concentration Risk [Line Items]
Number of employees	230
Percentage of employees	19.30%

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Summary of Significant Accounting Policies - Other Noncurrent Assets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Deferred debt issuance costs	$ 29,414	$ 26,374
Accumulated amortization, deferred debt issuance costs	6,578	1,996
Capitalized major maintenance and repairs	14,346	12,471
Accumulated amortization, capitalized major maintenance and repairs	$ 17,813	$ 12,538

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2012

Derivative [Line Items]

Derivative assets and liabilities at fair values

The Company recorded the following derivative assets and liabilities at their fair values as of December 31, 2012 and 2011:

	Derivative Assets						Derivative Liabilities
	December 31, 2012			December 31, 2011			December 31, 2012			December 31, 2011
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	10,517		$	83,919		$	(26,743	)	$	56,041
Gasoline swaps	273			(20,605		)	2,086			(1,596		)
Diesel swaps	(7,871		)	(4,561		)	(10,331		)	(22,586		)
Jet fuel swaps	169			1,077			(2,298		)	(72,537		)
Total derivative instruments designated as hedges	3,088			59,830			(37,286		)	(40,678		)
Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps	—			—			(10,725		)	—
Crude oil basis swaps	—			—			(3,363		)	—
Gasoline swaps	—			—			(2,171		)	—
Diesel swaps	—			—			3,928			—
Specialty products segment: (1)
Crude oil swaps	—			—			1,649			—
Natural gas swaps (2)	—			(1,328		)	—			(1,892		)
Interest rate swaps: (3)	—			—			—			(1,011		)
Total derivative instruments not designated as hedges	—			(1,328		)	(10,682		)	(2,903		)
Total derivative instruments	$	3,088		$	58,502		$	(47,968	)	$	(43,581	)

(1) 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.

(2) The Company periodically enters into 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 for the interest payments under the previous term loan facility are no longer designated as cash flow hedges.

Gain (loss) in statement of financial performance

Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2012 and 2011 related to its derivative instruments not designated as cash flow hedges:

	Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivatives Year Ended December 31,						Amount of Gain (Loss) Recognized in Unrealized Loss on Derivatives Year Ended December 31,
Type of Derivative	2012			2011			2012			2011
Fuel products segment:
Crude oil swaps	$	(30,488	)	$	—		$	(39,967	)	$	—
Crude oil basis swaps	2,066			—			(3,363		)	—
Gasoline swaps	22,110			—			519			—
Diesel swaps	10,895			—			8,912			—
Jet fuel swaps	(1,719		)	—			—			—
Jet fuel collars	—			(746		)	—			726
Specialty products segment:
Crude oil swaps	—			932			1,649			(662		)
Natural gas swaps	(5,442		)	(171		)	3,221			(3,221		)
Interest rate swaps:	(732		)	(2,124		)	1,011			271
Total	$	(3,310	)	$	(2,109	)	$	(28,018	)	$	(2,886	)

Th

Company recorded the following amounts in its consolidated balance sheets, consolidated statements of operations, consolidated statements of other comprehensive income (loss) and its consolidated statements of partners’ capital as of, and for the years ended December 31, 2012 and 2011 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 Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)
	Year Ended December 31,						Location of (Gain) Loss	Year Ended December 31,						Location of Gain (Loss)	Year Ended December 31,
Type of Derivative	2012			2011				2012			2011				2012			2011
Fuel products segment:
Crude oil swaps	$	(99,960	)	$	133,060		Cost of sales	$	(49,874	)	$	(110,945	)	Unrealized/Realized	$	99,672		$	(8,159	)
Gasoline swaps	(15,981		)	(38,289		)	Sales	38,388			29,468			Unrealized/Realized	(52,038		)	(1,850		)
Diesel swaps	(59,260		)	(53,622		)	Sales	62,966			79,810			Unrealized/Realized	(10,518		)	(573		)
Jet fuel swaps	(39,931		)	(77,288		)	Sales	104,482			102,473			Unrealized/Realized	(123		)	(2,715		)
Specialty products segment:
Crude oil swaps	—			—			Cost of sales	(1,877		)	2,512			Unrealized/Realized	—			—
Natural gas swaps	—			—			Cost of sales	—			—			Unrealized/Realized	—			—
Interest rate swaps:	—			1,979			Interest  expense	—			702			Unrealized/Realized	—			—
Total	$	(215,132	)	$	(34,160	)		$	154,085		$	104,020			$	36,993		$	(13,297	)

Th

Effective portion of the hedges classified in accumulated other comprehensive income

effective portion of the cash flow hedges classified in accumulated other comprehensive loss was $13,953 as of December 31, 2012. The effective portion of the cash flow hedges classified in accumulated other comprehensive income was $47,094 as of December 31, 2011. Absent a change in the fair market value of the underlying transactions, the following other comprehensive income (loss) at December 31, 2012 will be reclassified to earnings by December 31, 2015 with balances being recognized as follows:

Year	Accumulated Other Comprehensive Income (Loss)
2013	$	(7,755	)
2014	(7,789		)
2015	1,591
Total	$	(13,953	)

Ba

Specialty Product | Natural Gas Swap Contracts

Derivative [Line Items]

Natural gas swap contracts by expiration dates

ural Gas Swap Contracts

At December 31, 2012, the Company did not have any natural gas derivatives related to natural gas purchases in its specialty products segment.

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

Cr

Fuel Product | Crude Oil Swap Contracts

Derivative [Line Items]

Derivative related different product segment

de Oil Contracts — Fuel Products Segment

Crude Oil Swap Contracts

At December 31, 2012, 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 2013	1,665,000	18,500	$	101.67
Second Quarter 2013	1,911,000	21,000	100.22
Third Quarter 2013	1,426,000	15,500	95.62
Fourth Quarter 2013	1,104,000	12,000	93.41
Calendar Year 2014	5,110,000	14,000	89.47
Calendar Year 2015	4,781,500	13,100	89.49
Totals	15,997,500
Average price			$	92.85

At December 31, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as cash flow hedges.

Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Swap ($/Bbl)
First Quarter 2013	630,000	7,000	$	101.34
Second Quarter 2013	455,000	5,000	98.56
Third Quarter 2013	368,000	4,000	96.58
Fourth Quarter 2013	368,000	4,000	96.58
Totals	1,821,000
Average price			$	98.72

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

Crude Oil Basis Swap Contracts

In April, July and December 2012, the Company entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between Canadian heavy crude oil and NYMEX WTI crude oil. At December 31, 2012, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as cash flow hedges.

Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Differential to NYMEX WTI ($/Bbl)
First Quarter 2013	180,000	2,000	$	(23.75	)
Second Quarter 2013	364,000	4,000	(27.38		)
Third Quarter 2013	184,000	2,000	(23.75		)
Fourth Quarter 2013	184,000	2,000	(23.75		)
Totals	912,000
Average differential			$	(25.20	)

At

Fuel Product | Diesel swaps

Derivative [Line Items]

Diesel swap contracts by expiration dates

December 31, 2012, 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)
Second Quarter 2013	546,000	6,000	$	122.74
Third Quarter 2013	874,000	9,500	122.23
Fourth Quarter 2013	828,000	9,000	120.82
Calendar Year 2014	3,835,000	10,507	116.00
Calendar Year 2015	4,781,500	13,100	115.81
Totals	10,864,500
Average price			$	117.13

At December 31, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges.

Diesel Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
First Quarter 2013	540,000	6,000	$	130.57
Second Quarter 2013	364,000	4,000	126.82
Third Quarter 2013	276,000	3,000	124.17
Fourth Quarter 2013	276,000	3,000	124.17
Totals	1,456,000
Average price			$	127.20

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

Je

Fuel Product | Jet Fuel Swap Contracts

Derivative [Line Items]

Jet swap contracts by expiration dates

December 31, 2012, 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 2013	1,035,000	11,500	$	127.39
Second Quarter 2013	819,000	9,000	129.20
Third Quarter 2013	368,000	4,000	125.13
Fourth Quarter 2013	276,000	3,000	122.36
Calendar Year 2014	1,275,000	3,493	116.64
Totals	3,773,000
Average price			$	123.56

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

Ga

Fuel Product | Gasoline Swap Contracts

Derivative [Line Items]

Gasoline swap contracts by expiration dates

December 31, 2012, 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 2013	630,000	7,000	$	113.59
Second Quarter 2013	546,000	6,000	116.32
Third Quarter 2013	184,000	2,000	114.73
Totals	1,360,000
Average price			$	114.84

At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.

Gasoline Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
First Quarter 2013	90,000	1,000	$	105.50
Second Quarter 2013	91,000	1,000	105.50
Third Quarter 2013	92,000	1,000	105.50
Fourth Quarter 2013	92,000	1,000	105.50
Totals	365,000
Average price			$	105.50

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

In

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Hierarchy of Recurring Fair Value Measurements

The Company’s recurring assets and liabilities measured at fair value at December 31, 2012 and December 31, 2011 were as follows:

	December 31, 2012											December 31, 2011
	Level 1			Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets:
Derivative assets:
Crude oil swaps	—			—		10,517			10,517			—		—		83,919			83,919
Gasoline swaps	—			—		273			273			—		—		(20,605		)	(20,605		)
Diesel swaps	—			—		(7,871		)	(7,871		)	—		—		(4,561		)	(4,561		)
Jet fuel swaps	—			—		169			169			—		—		1,077			1,077
Natural gas swaps	—			—		—			—			—		—		(1,328		)	(1,328		)
Total derivative assets	—			—		3,088			3,088			—		—		58,502			58,502
Pension plan investments	38,835			2,731		—			41,566			33,580		2,462		—			36,042
Total recurring assets at fair value	$	38,835		$	2,731	$	3,088		$	44,654		$	33,580	$	2,462	$	58,502		$	94,544
Liabilities:
Derivative liabilities:
Crude oil swaps	$	—		$	—	$	(35,819	)	(35,819		)	$	—	$	—	$	56,041		$	56,041
Crude oil basis swaps	—			—		(3,363		)	(3,363		)	—		—		—			—
Gasoline swaps	—			—		(85		)	(85		)	—		—		(1,596		)	(1,596		)
Diesel swaps	—			—		(6,403		)	(6,403		)	—		—		(22,586		)	(22,586		)
Jet fuel swaps	—			—		(2,298		)	(2,298		)	—		—		(72,537		)	(72,537		)
Natural gas swaps	—			—		—			—			—		—		(1,892		)	(1,892		)
Interest rate swaps	—			—		—			—			—		—		(1,011		)	(1,011		)
Total derivative liabilities	—			—		(47,968		)	(47,968		)	—		—		(43,581		)	(43,581		)
Liability Awards	$	(2,239	)	$	—	$	—		$	(2,239	)	—		—		—			—
Total recurring liabilities at fair value	$	(2,239	)	$	—	$	(47,968	)	$	(50,207	)	$	—	$	—	$	(43,581	)	$	(43,581	)

Summary of net changes in fair value of company level 3 financial assets and liabilities.

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the year ended December 31, 2012 and 2011:

	Derivative Instruments, Net
	For the Year Ended December 31,
	2012			2011
Fair value at January 1,	$	14,921		$	(32,814	)
Realized (gain) loss on derivative instruments	(9,452		)	7,909
Unrealized loss on derivative instruments	(3,787		)	(10,383		)
Change in fair value of cash flow hedges	(215,132		)	(34,160		)
Settlements	168,570			84,369
Transfers in (out) of Level 3	—			—
Fair value at December 31,	$	(44,880	)	$	14,921
Total loss included in net income attributable to changes in unrealized loss relating to financial assets and liabilities held as of December 31,	$	(3,787	)	$	(10,383	)

Carrying and estimated fair value of the Company's financial instruments, carried at adjusted historical cost

The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at December 31, 2012 and December 31, 2011 were as follows:

	December 31, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial Instrument:
2019 Notes	$	658,795	$	587,602	$	591,750	$	586,304
2020 Notes	$	301,813	$	270,387	$	—	$	—
Capital lease and other obligations	$	5,512	$	5,512	$	786	$	786

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Description of the Business

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of the Business

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, 2012, the Company had 57,529,778 limited partner common units and 1,174,077 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses. The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, asphalt, waxes and fuel and fuel related products including gasoline, diesel, jet fuel and heavy fuel oils. The Company owns facilities located in Shreveport, Louisiana (“Shreveport” and “TruSouth”); Superior, Wisconsin (“Superior”); Great Falls, Montana (“Montana”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”); Dickinson, Texas (“Dickinson”); Louisiana, Missouri (“Missouri”) and Porter, Texas (“Royal Purple”) and terminals located in Burnham, Illinois (“Burnham”); Rhinelander, Wisconsin (“Rhinelander”); Crookston, Minnesota (“Crookston”) and Proctor, Minnesota (“Duluth”).

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Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2012

Equity [Abstract]

Schedule of Incentive Distributions

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	%

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Partners' Capital (Details) (USD $)	0 Months Ended					1 Months Ended	12 Months Ended
	May 08, 2012	May 08, 2012	Oct. 13, 2011	Sep. 08, 2011	Feb. 24, 2011	Feb. 28, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Partners' Capital (Textual) [Abstract]
Partners' capital account, units, converted						13,066,000
Partners' Capital Account, Units, Conversion Ratio						1
Common units sold in public offering		6,000,000	750,000	11,000,000	4,500,000
Public offering price per share	$ 25.50	$ 25.50	$ 18.00	$ 18.00	$ 21.45
Proceeds from public offerings of common units, net		$ 146,558,000	$ 12,915,000	$ 189,497,000	$ 92,290,000		$ 146,558,000	$ 294,702,000	$ 793,000
Underwriting discounts, commissions and expenses	6,180,000	6,180,000	540,000	7,866,000	3,915,000
Contributions from Calumet GP, LLC	3,122,000		275,000	4,041,000	1,970,000		3,122,000	6,286,000	18,000
General partner percentage interest in partners capital	2.00%		2.00%	2.00%	2.00%
Limited partners' cash distributions rights period							45 days
Limited partners' minimum vote required for removal of general partner							66.67%
Limited partners', threshold of ownership percentage banned from voting on removal of general partner							20.00%
General partners' ownership percentage that may require limited partners to sell							80.00%
Partners' capital, after distribution required cash amount							45,000,000
Partners' capital, distribution, fixed charge coverage ratio threshold							1.75
Distributions to partners							132,400,000	82,743,000	65,739,000
General partner's incentive distribution rights							5,433,000	322,000	0
Limited Partners
Partners' Capital (Textual) [Abstract]
Number of units							57,529,778
Public Ownership
Partners' Capital (Textual) [Abstract]
Number of units							39,397,092
Company's affiliates
Partners' Capital (Textual) [Abstract]
Number of units							18,132,686
Lesser of Borrowing Base
Partners' Capital (Textual) [Abstract]
Partners' capital, after distribution required threshold percentage							15.00%
Lesser of Credit Facility Commitments
Partners' Capital (Textual) [Abstract]
Partners' capital, after distribution required threshold percentage							15.00%
Maximum
Partners' Capital (Textual) [Abstract]
Partners' capital, distribution amount, below fixed charge coverage ratio threshold							$ 70,000,000

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Summary of Significant Accounting Policies - Accounts Receivable (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Activity in Allowance for Doubtful Accounts
Beginning balance	$ 925	$ 633	$ 801
Provision	362	380	(61)
Recoveries	17	0	0
Write-offs, net	(154)	(88)	(107)
Ending balance	$ 1,150	$ 925	$ 633
Fuel Product
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable due within	10 days
Minimum | Specialty Product
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable due within	30 days
Maximum | Specialty Product
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable due within	45 days

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Goodwill and Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	16 years
Gross Amount	$ 255,134	$ 63,824
Accumulated Amortization	(58,051)	(41,149)
Amortization expense of intangible assets	16,902	6,991	8,810
2013	25,401
2014	24,297
2015	22,165
2016	20,217
2017	17,669
2018	14,904
Customer relationships
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	20 years
Gross Amount	154,307	28,482
Accumulated Amortization	(22,612)	(12,936)
Supplier agreements
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	4 years
Gross Amount	21,519	21,519
Accumulated Amortization	(21,519)	(19,926)
Tradenames
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	9 years
Gross Amount	6,421	0
Accumulated Amortization	(550)	0
Trade secrets
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	12 years
Gross Amount	44,179	0
Accumulated Amortization	(3,116)	0
Patents
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	12 years
Gross Amount	1,573	1,573
Accumulated Amortization	(1,112)	(966)
Non-competition agreements
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	5 years
Gross Amount	5,827	5,732
Accumulated Amortization	(5,780)	(4,182)
Distributor agreements
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	3 years
Gross Amount	2,019	2,019
Accumulated Amortization	(2,019)	(2,019)
Royalty agreements
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Weighted Average Life	19 years
Gross Amount	4,499	4,499
Accumulated Amortization	(1,343)	(1,120)
Tradenames - Royal Purple Retail
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Indefinite-Lived Intangible Assets (Excluding Goodwill)	$ (14,790)	$ 0

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Derivatives (Details 5) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 154,085	$ 104,020
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Cash Flow Hedges Classified in Accumulated Other Comprehensive Loss	(13,953)	47,094
Calendar Year 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(7,755)
Calendar Year 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(7,789)
Calendar Year 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 1,591

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 32,174	$ 64
Accounts receivable:
Trade, less allowance for doubtful accounts of $1,150 and $925, respectively	219,314	208,928
Other	7,469	3,137
Total accounts receivable	226,783	212,065
Inventories	553,574	497,740
Derivative assets	3,088	58,502
Prepaid expenses and other current assets	10,368	8,179
Deposits	7,959	2,094
Total current assets	833,946	778,644
Property, plant and equipment, net	986,875	842,101
Goodwill	187,013	48,335
Other intangible assets, net	197,083	22,675
Other noncurrent assets, net	48,128	40,303
Total assets	2,253,045	1,732,058
Current liabilities:
Accounts payable	333,416	302,826
Accrued interest payable	23,526	10,500
Accrued salaries, wages and benefits	20,067	13,481
Accrued income taxes payable	27,577	452
Other taxes payable	13,676	12,616
Other current liabilities	8,397	4,600
Current portion of long-term debt	771	551
Derivative liabilities	47,968	43,581
Total current liabilities	475,398	388,607
Pension and postretirement benefit obligations	23,999	26,957
Other long-term liabilities	1,125	1,055
Long-term debt, less current portion	862,730	586,539
Total liabilities	1,363,252	1,003,158
Commitments and contingencies
Partners’ capital:
Limited partners’ interest (57,529,778 units and 51,529,778 units, issued and outstanding at December 31, 2012 and 2011, respectively)	884,805	666,471
General partner’s interest	30,467	23,902
Accumulated other comprehensive income (loss)	(25,479)	38,527
Total partners’ capital	889,793	728,900
Total liabilities and partners’ capital	$ 2,253,045	$ 1,732,058

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Summary of Significant Accounting Policies - Shipping and Handling Costs (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]
Shipping and handling costs	$ 107,900	$ 94,187	$ 85,471

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Employee Benefit Plans - Future Benefit Payments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2013	$ 2,402
2014	2,504
2015	2,608
2016	2,720
2017	2,813
2018 to 2022	16,355
Total	29,402
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2013	59
2014	44
2015	41
2016	25
2017	16
2018 to 2022	72
Total	$ 257

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Consolidated Statements of Partners' Capital (USD $) In Thousands, unless otherwise specified	Total	Accumulated Other Comprehensive Income (Loss)	General Partner	Limited Partner, Common	Limited Partner, Subordinated
Beginning balance at Dec. 31, 2009	$ 485,347	$ 12,644	$ 19,087	$ 418,902	$ 34,714
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	(40,263)	(40,263)	0	0	0
Net income	16,701	0	334	10,305	6,062
Proceeds from public offering of common units, net	793	0	0	793	0
Contribution from Calumet GP, LLC	18	0	18	0	0
Units repurchased for phantom unit grants	(248)	0	0	(248)	0
Amortization of vested phantom units	1,670	0	0	1,670	0
Distributions to partners	(65,739)	0	(1,314)	(40,579)	(23,846)
Ending balance at Dec. 31, 2010	398,279	(27,619)	18,125	390,843	16,930
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	66,146	66,146	0	0	0
Net income	43,036	0	1,183	41,853	0
Proceeds from public offering of common units, net	294,702	0	0	294,702	0
Contribution from Calumet GP, LLC	6,286	0	6,286	0	0
Units repurchased for phantom unit grants	(620)	0	0	(620)	0
Issuance of phantom units	787	0	0	787	0
Amortization of vested phantom units	3,027	0	0	3,027	0
Subordinated unit conversion	0	0	0	10,789	(10,789)
Distributions to partners	(82,743)	0	(1,692)	(74,910)	(6,141)
Ending balance at Dec. 31, 2011	728,900	38,527	23,902	666,471	0
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	(64,006)	(64,006)	0	0	0
Net income	205,737	0	9,548	196,189	0
Proceeds from public offering of common units, net	146,558	0	0	146,558	0
Contribution from Calumet GP, LLC	3,122	0	3,122	0	0
Units repurchased for phantom unit grants	(2,110)	0	0	(2,110)	0
Issuance of phantom units	1,648	0	0	1,648	0
Amortization of vested phantom units	2,344	0	0	2,344	0
Distributions to partners	(132,400)	0	(6,105)	(126,295)	0
Ending balance at Dec. 31, 2012	$ 889,793	$ (25,479)	$ 30,467	$ 884,805	$ 0

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Employee Benefit Plans - Plan Allocation (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	47.00%	62.00%
Equity
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Minimum	25.00%
Target Allocation Maximum	35.00%
Target Allocation	30.00%
Defined Benefit Plan, Actual Plan Asset Allocations	14.00%	11.00%
Foreign equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	2.00%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Minimum	45.00%
Target Allocation Maximum	55.00%
Target Allocation	50.00%
Defined Benefit Plan, Actual Plan Asset Allocations	20.00%	18.00%
Capital preservation portfolio
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Minimum	15.00%
Target Allocation Maximum	25.00%
Target Allocation	20.00%
Balanced fund
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	7.00%	0.00%
Commingled Fund
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	7.00%	7.00%

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Commitments and Contingencies - Occupational Health and Safety (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended		12 Months Ended
	Dec. 31, 2012	Mar. 14, 2011	Dec. 31, 2012 Occupational Safety and Health Administration	Dec. 31, 2011 Occupational Safety and Health Administration	Dec. 31, 2012 Minimum	Dec. 31, 2012 Maximum
Loss Contingencies [Line Items]
Standard certification	ISO-9001-2008
Capital expenditures			$ 728	$ 4,075	$ 2,000	$ 6,000
Expected environmental capital expenditures in 2013					1,000	4,000
Penalty paid during period			119
OHSA 2011 spending	first quarter of 2011
Citation and notice of penalty	Mar. 14, 2011
Proposed penalty		$ 208

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Segments and Related Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Jan. 01, 2013	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012 segment	Dec. 31, 2011	Dec. 31, 2010
Reportable segment information
Number of Reportable Segments									2
Sales:
External customers									$ 4,657,282	$ 3,134,923	$ 2,190,752
Intersegment sales									0	0	0
Sales	1,220,882	1,179,818	1,086,996	1,169,586	1,018,133	777,780	733,770	605,240	4,657,282	3,134,923	2,190,752
Depreciation and amortization									105,025	74,393	70,293
Operating income (loss)									285,928	125,292	71,490
Reconciling items to net income:
Interest expense									(85,573)	(48,747)	(30,497)
Realized (gain) loss on derivative instruments									5,665	(18,292)	(23,547)
Debt extinguishment costs									0	(15,130)	0
Other									470	842	(147)
Income tax expense									(753)	(929)	(598)
Net income	45,736	42,416	65,662	51,923	26,872	19,614	(7,651)	4,201	205,737	43,036	16,701
Capital expenditures									57,053	49,478	35,001
Specialty Product
Sales:
External customers									2,231,602	1,807,626	1,408,872
Intersegment sales									1,153,095	1,079,338	775,366
Sales									3,384,697	2,886,964	2,184,238
Depreciation and amortization									84,648	70,084	70,293
Operating income (loss)									125,710	134,844	73,194
Reconciling items to net income:
Capital expenditures									41,686	45,141	35,001
Fuel Product
Sales:
External customers									2,425,680	1,327,297	781,880
Intersegment sales									73,545	46,119	39,410
Sales									2,499,225	1,373,416	821,290
Depreciation and amortization									20,377	4,309	0
Operating income (loss)									160,218	(9,552)	(1,704)
Reconciling items to net income:
Capital expenditures									15,367	4,337	0
Combined Segments
Sales:
External customers									4,657,282	3,134,923	2,190,752
Intersegment sales									1,226,640	1,125,457	814,776
Sales									5,883,922	4,260,380	3,005,528
Depreciation and amortization									105,025	74,393	70,293
Operating income (loss)									285,928	125,292	71,490
Reconciling items to net income:
Capital expenditures									57,053	49,478	35,001
Eliminations
Sales:
External customers									0	0	0
Intersegment sales									(1,226,640)	(1,125,457)	(814,776)
Sales									(1,226,640)	(1,125,457)	(814,776)
Depreciation and amortization									0	0	0
Operating income (loss)									0	0	0
Reconciling items to net income:
Capital expenditures									$ 0	$ 0	$ 0

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Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Unit [Abstract]

Computation of basic and diluted earnings per limited partner unit

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(In thousands, except unit data)
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	205,737	$	43,036	$	16,701
General partner’s interest in net income	4,115		861		334
General partner’s incentive distribution rights	5,433		322		—
Nonvested share based payments	1,199		—		—
Net income available to limited partners	$	194,990	$	41,853	$	16,367
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average limited partner units outstanding	55,559		42,599		35,335
Effect of dilutive securities:
Participating securities — phantom units	118		45		16
Diluted weighted average limited partner units outstanding	55,677		42,644		35,351
Limited partners’ interest basic net income per unit	$	3.51	$	0.98	$	0.46
Limited partners’ interest diluted net income per unit	$	3.50	$	0.98	$	0.46

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Long-Term Debt - Maturity Schedule (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Maturities of long-term debt
2013	$ 771
2014	423
2015	303
2016	328
2017	355
Thereafter	878,332
Total	$ 880,512

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total (1)
2012
Sales	$	1,169,586	$	1,086,996	$	1,179,818	$	1,220,882	$	4,657,282
Gross profit	84,244		128,808		158,406		141,719		513,177
Net income	51,923		65,662		42,416		45,736		205,737
Net income available to limited partners	50,054		62,875		39,669		42,392		194,990
Limited partners’ interest basic net income per unit	$	0.97	$	1.14	$	0.69	$	0.73	$	3.51
Limited partners’ interest diluted net income per unit	$	0.97	$	1.14	$	0.69	$	0.73	$	3.50
Weighted average limited partner units outstanding — basic	51,685,000		55,028,000		57,746,000		57,746,000
Weighted average limited partner units outstanding — diluted	51,736,000		55,074,000		57,826,000		57,898,000

	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

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

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Reportable segment information

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, 2012	Specialty Products		Fuel Products			Combined Segments		Eliminations			Consolidated Total
Sales:
External customers	$	2,231,602	$	2,425,680		$	4,657,282	$	—		$	4,657,282
Intersegment sales	1,153,095		73,545			1,226,640		(1,226,640		)	—
Total sales	$	3,384,697	$	2,499,225		$	5,883,922	$	(1,226,640	)	$	4,657,282
Depreciation and amortization	84,648		20,377			105,025		—			105,025
Operating income	125,710		160,218			285,928		—			285,928
Reconciling items to net income:
Interest expense											(85,573		)
Gain on derivative instruments											5,665
Other											470
Income tax expense											(753		)
Net income											$	205,737
Capital expenditures	$	41,686	$	15,367		$	57,053	$	—		$	57,053
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		)
Loss on derivative instruments											(23,547		)
Other											(147		)
Income tax expense											(598		)
Net income											$	16,701
Capital expenditures	$	35,001	$	—		$	35,001	$	—		$	35,001

Segment assets

	December 31,
	2012		2011
Segment assets:
Specialty products	$	1,569,796	$	1,159,040
Fuel products	683,249		573,018
Total assets	$	2,253,045	$	1,732,058

Major product category sales

The following table sets forth the major product category sales:

	Year Ended December 31,
	2012				2011				2010
Specialty products:
Lubricating oils	$	1,007,928	22	%	$	947,798	30	%	$	759,701	35	%
Solvents	491,114		11	%	495,934		16	%	396,894		18	%
Waxes	142,765		3	%	143,111		5	%	124,964		6	%
Packaged and synthetic specialty products	161,673		3	%	—		—	%	—		—	%
Fuels	2,029		—	%	3,432		—	%	5,507		—	%
Asphalt and other by-products	426,093		9	%	217,351		7	%	121,806		5	%
Total	2,231,602		48	%	1,807,626		58	%	1,408,872		64	%
Fuel products:
Gasoline	1,174,859		25	%	619,630		20	%	304,544		14	%
Diesel	941,047		20	%	513,334		16	%	330,756		15	%
Jet fuel	183,953		4	%	148,036		5	%	135,796		6	%
Heavy fuel oils and other	125,821		3	%	46,297		1	%	10,784		1	%
Total	2,425,680		52	%	1,327,297		42	%	781,880		36	%
Consolidated sales	$	4,657,282	100	%	$	3,134,923	100	%	$	2,190,752	100	%

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Transactions with Related Parties (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Number of crude oil supply agreement with related party	1
Limited Partner [Member]
Related Party Transaction [Line Items]
Product sales to related parties	$ 9,309	$ 16,500	$ 4,727
Trade accounts and other receivables	139	1,818
Excluding Legacy Resources
Related Party Transaction [Line Items]
Purchases from related party	7,181	1,768	1,480
Accounts payable from related parties	2,230	1,393
Legacy Resources
Related Party Transaction [Line Items]
Purchases from related party	1,120	229,793	591,777
Accounts payable from related parties	96	574
Tobias Insurance Group, Inc
Related Party Transaction [Line Items]
Purchases from related party	$ 510	$ 566	$ 638

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

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, TruSouth Oil, LLC, Calumet Montana Refining, LLC, S&S International Mining Enterprises, Inc., Royal Purple, 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

Accounts Receivable

The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are carried at their face amounts and are generally due within 30 days 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.

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.

Composite Depreciation Method

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

Capitalized Software

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.

Goodwill

Goodwill represents the excess of purchase price over fair value of the net assets acquired in the acquisitions of Penreco on January 3, 2008, Missouri on January 3, 2012, TruSouth on January 6, 2012, Royal Purple on July 3, 2012 and Montana on October 1, 2012. See Note 3 for more information. 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 (“ASU 2011-08”) which amends the rules for testing goodwill for impairment. Under ASU 2011-08, 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.

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 judgment 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.

Other Intangible Assets

Other intangible assets consist of tangible assets associated with supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements that were acquired in the acquisition of Penreco on January 3, 2008, the Missouri Acquisition on January 3, 2012, the TruSouth Acquisition on January 6, 2012 and the Royal Purple Acquisition on July 3, 2012. The majority of these assets are being amortized using discounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships are being amortized using the discounted estimated future cash flows method based upon assumed rates of annual customer attrition. For more information, refer to Note 4.

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.

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 the 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. Generally, tax returns remain subject to examination by taxing authorities for three years. The Company had no unrecognized tax benefits as of December 31, 2012 and 2011.

Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Company’s partnership agreement. Individual partners have different investment basis 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 Company is not readily available.

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 7.

Deferred Debt Issuance Cost

Deferred debt issuance costs were $29,414 and $26,374 as of December 31, 2012 and 2011, 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.

Turnaround Costs

Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $14,346 and $12,471 as of December 31, 2012 and 2011, respectively. The Company capitalizes these costs and amortizes the costs on a straight-line basis over the lives of the turnaround assets.

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 the Company’s 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.

New Accounting Pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the 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 was effective for the first reporting period (including interim periods) beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on the Company’s 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 amended current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income (loss) as part of the statement of partners’ capital. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income (loss) which contains two sections, net income and other comprehensive income (loss), 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 (loss) by component in both the statement in which net income is presented and the statement in which other comprehensive income (loss) 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, were effective for fiscal years (including interim periods) beginning after December 15, 2011 and are to be applied retrospectively, with early adoption permitted. The Company elected to present the components of comprehensive loss in two separate but consecutive financial statements, namely the consolidated statements of operations and the consolidated statements of comprehensive income (loss).

In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)—Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the balance sheet. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet Topic(210)—Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies the scope of the setting disclosures and addresses any unintended consequences. Amendments to ASU 2011-11, as superseded by ASU 2013-01, are effective for the first reporting period (including interim periods) beginning after January 1, 2013 and should be applied retrospectively for any period presented. The Company is in the process of evaluating the impact of the adoption of ASU 2011-11 and ASU 2013-01 on its financial statements.

In July 2012, the FASB issued ASU No. 2012-02, Intangibles (Topic 350)—Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). ASU 2012-02 permits an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is more than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset exceeds its carrying amount, quantitative impairment testing is not required. However, if an entity concludes otherwise, quantitative impairment testing is required. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The adoption of ASU 2012-02 did not have a material impact on the Company’s consolidated financial statements.

In October 2012, the FASB issued ASU No. 2012-04, Technical Corrections and Improvements (“ASU 2012-04”). ASU 2012-04 covers a wide range of topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. ASU 2012-04 is effective for fiscal periods beginning after December 15, 2012. The Company is in the process of evaluating the impact of the adoption of ASU 2012-04 on its financial statements.    

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220)—Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires entities to report either on the statement of operations or disclose in the footnotes to the consolidated financial statements the effects on earnings from items that are reclassified out of comprehensive income. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. ASU 2013-02 is effective prospectively for the first reporting period after December 15, 2012 with early adoption permitted. The adoption of ASU 2013-02 will not have a material impact on the Company’s consolidated financial statements.

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Derivatives (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	$ (215,132)	$ (34,160)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	154,085	104,020
Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	36,993	(13,297)
Not Designated as Hedging Instrument | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(3,310)	(2,109)
Not Designated as Hedging Instrument | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(28,018)	(2,886)
Fuel Product | Crude oil swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(99,960)	133,060
Fuel Product | Crude oil swaps | Cost of sales
Derivative instruments designated as cash flow hedges
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(49,874)	(110,945)
Fuel Product | Crude oil swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	99,672	(8,159)
Fuel Product | Gasoline swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(15,981)	(38,289)
Fuel Product | Gasoline swaps | Sales
Derivative instruments designated as cash flow hedges
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	38,388	29,468
Fuel Product | Gasoline swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	(52,038)	(1,850)
Fuel Product | Diesel swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(59,260)	(53,622)
Fuel Product | Diesel swaps | Sales
Derivative instruments designated as cash flow hedges
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	62,966	79,810
Fuel Product | Diesel swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	(10,518)	(573)
Fuel Product | Jet fuel swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(39,931)	(77,288)
Fuel Product | Jet fuel swaps | Sales
Derivative instruments designated as cash flow hedges
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	104,482	102,473
Fuel Product | Jet fuel swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	(123)	(2,715)
Fuel Product | Not Designated as Hedging Instrument | Crude oil swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(30,488)	0
Fuel Product | Not Designated as Hedging Instrument | Crude oil swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(39,967)	0
Fuel Product | Not Designated as Hedging Instrument | Crude oil basis swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	2,066	0
Fuel Product | Not Designated as Hedging Instrument | Crude oil basis swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(3,363)	0
Fuel Product | Not Designated as Hedging Instrument | Gasoline swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	22,110	0
Fuel Product | Not Designated as Hedging Instrument | Gasoline swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	519	0
Fuel Product | Not Designated as Hedging Instrument | Diesel swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	10,895	0
Fuel Product | Not Designated as Hedging Instrument | Diesel swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	8,912	0
Fuel Product | Not Designated as Hedging Instrument | Jet fuel swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1,719)	0
Fuel Product | Not Designated as Hedging Instrument | Jet fuel swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Fuel Product | Not Designated as Hedging Instrument | Jet fuel collars | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(746)
Fuel Product | Not Designated as Hedging Instrument | Jet fuel collars | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	726
Specialty Product | Crude oil swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	0
Specialty Product | Crude oil swaps | Cost of sales
Derivative instruments designated as cash flow hedges
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1,877)	2,512
Specialty Product | Crude oil swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	0
Specialty Product | Natural gas swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	0
Specialty Product | Natural gas swaps | Cost of sales
Derivative instruments designated as cash flow hedges
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0
Specialty Product | Natural gas swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	0
Specialty Product | Interest rate swaps
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	1,979
Specialty Product | Interest rate swaps | Interest expense
Derivative instruments designated as cash flow hedges
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	702
Specialty Product | Interest rate swaps | Unrealized/Realized
Derivative instruments designated as cash flow hedges
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	0
Specialty Product | Not Designated as Hedging Instrument | Crude oil swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	932
Specialty Product | Not Designated as Hedging Instrument | Crude oil swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1,649	(662)
Specialty Product | Not Designated as Hedging Instrument | Natural gas swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(5,442)	(171)
Specialty Product | Not Designated as Hedging Instrument | Natural gas swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3,221	(3,221)
Specialty Product | Not Designated as Hedging Instrument | Interest rate swaps | Realized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(732)	(2,124)
Specialty Product | Not Designated as Hedging Instrument | Interest rate swaps | Unrealized Gain
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 1,011	$ 271

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating activities
Net income	$ 205,737	$ 43,036	$ 16,701
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	91,669	63,009	60,287
Amortization of turnaround costs	13,356	11,384	10,006
Non-cash interest expense	6,081	3,728	3,864
Non-cash debt extinguishment costs	0	14,401	0
Provision for doubtful accounts	22	380	74
Unrealized (gain) loss on derivative instruments	3,787	10,383	15,843
Loss on disposal of fixed assets	2,488	1,525	239
Non-cash equity based compensation	6,512	4,895	1,540
Other non-cash activities	1,070	74	142
Changes in assets and liabilities:
Accounts receivable	34,609	(54,484)	(35,267)
Inventories	17,898	(167,028)	(9,860)
Prepaid expenses and other current assets	21,680	(425)	(98)
Derivative activity	(5,033)	11,742	2,990
Turnaround costs	(14,899)	(14,052)	(10,684)
Deposits	(5,852)	0	4,767
Other assets	(4,007)	(426)	(2,006)
Accounts payable	11,859	131,261	64,639
Accrued interest payable	13,026	7,350	100
Accrued salaries, wages and benefits	1,039	4,066	1,189
Accrued income taxes payable	(16,089)	366	4
Other taxes payable	862	5,528	(381)
Other liabilities	1,932	(12,033)	10,463
Pension and postretirement benefit obligations	(7,639)	(902)	(409)
Net cash provided by operating activities	380,108	63,778	134,143
Investing activities
Additions to property, plant and equipment	(57,053)	(49,478)	(35,001)
Proceeds from insurance recoveries — equipment	0	1,942	0
Cash paid for acquisitions, net of cash acquired	(569,191)	(413,173)	0
Proceeds from sale of property, plant and equipment	2,010	285	242
Net cash used in investing activities	(624,234)	(460,424)	(34,759)
Financing activities
Proceeds from borrowings — revolving credit facility	1,558,323	1,598,680	1,015,485
Repayments of borrowings — revolving credit facility	(1,558,323)	(1,609,512)	(1,044,553)
Repayments of borrowings — term loan credit facility	0	(367,385)	(3,850)
Payments on capital lease obligations	(1,499)	(1,069)	(1,302)
Proceeds from public offerings of common units, net	146,558	294,702	793
Proceeds from senior notes offerings	270,187	586,000	0
Debt issuance costs	(7,622)	(27,666)	0
Contributions from Calumet GP, LLC	3,122	6,286	18
Units repurchased for phantom unit grants	(2,110)	(620)	(248)
Distributions to partners	(132,400)	(82,743)	(65,739)
Net cash provided by (used in) financing activities	276,236	396,673	(99,396)
Net increase (decrease) in cash and cash equivalents	32,110	27	(12)
Cash and cash equivalents at beginning of year	64	37	49
Cash and cash equivalents at end of year	32,174	64	37
Supplemental disclosure of cash flow information
Interest paid, net of capitalized interest	66,223	37,856	26,389
Income taxes paid	718	568	188
Supplemental disclosure of noncash financing and investing activities
Equipment acquired under capital lease	$ 5,771	$ 0	$ 0

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 1,150	$ 925
Limited partners' interest units issued	57,529,778	51,529,778
Limited partners' interest units outstanding	57,529,778	51,529,778

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Unit-Based Compensation

12 Months Ended

Dec. 31, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Unit-Based Compensation

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 the Company’s general partner have been granted phantom units under the terms of the Plan as part of their director compensation package related to fiscal years 2010, 2011 and 2012. 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, 2012 and 2011, 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 during the performance period, 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 have DERs on these phantom units from the date of grant.

The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and 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.

Liability Awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units. Phantom unit Liability Awards are recorded in accrued salaries, wages and benefits in the consolidated balance sheets based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense within general and administrative expense in the consolidated statements of operations.

A summary of the Company’s nonvested phantom units as of December 31, 2012, and the changes during the years ended December 31, 2012, 2011 and 2010, are presented below:

	Number of Phantom Units		Weighted-Average Grant Date Fair Value
Non-vested at January 1, 2010	57,493		$	12.42
Granted	138,490		20.11
Vested	(90,491	)	18.05
Forfeited	—		—
Non-vested at December 31, 2010	105,492		$	17.68
Granted	640,875		20.26
Vested	(183,671	)	20.29
Forfeited	—		—
Non-vested at December 31, 2011	562,696		$	19.77
Granted	616,997		26.69
Vested	(286,976	)	21.16
Forfeited	(56,790	)	20.00
Non-vested at December 31, 2012	835,927		$	27.57

For the years ended December 31, 2012, 2011 and 2010, compensation expense of $4,583, $3,027 and $784, respectively, was recognized in the consolidated statements of operations related to vested phantom unit grants, including $2,239 attributable to Liability Awards for the year ended December 31, 2012. As of December 31, 2012 and 2011, there was a total of $23,044 and $11,124, respectively of unrecognized compensation costs related to nonvested phantom unit grants, including $16,139 attributable to Liability Awards for the year ended December 31, 2012. 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, 2012 and 2011, was $6,083 and $3,727, respectively.

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Subsequent Events (Details) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended				12 Months Ended			0 Months Ended	12 Months Ended		0 Months Ended	3 Months Ended			3 Months Ended		0 Months Ended
	May 08, 2012	Oct. 13, 2011	Sep. 08, 2011	Feb. 24, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jan. 08, 2013 Subsequent Event	Dec. 31, 2012 Subsequent Event	Jan. 02, 2013 Subsequent Event San Antonio Acquisition	Jan. 08, 2013 Subsequent Event Overallotment Option	Jan. 01, 2013 Subsequent Event Dividend Declared	Jan. 23, 2013 Subsequent Event Dividend Declared	Dec. 31, 2012 Subsequent Event Dividend Declared	Jan. 01, 2013 Subsequent Event Dividend Paid	Dec. 31, 2012 Subsequent Event Dividend Paid	Feb. 07, 2013 Dakota Prairie Refining, LLC [Member] Subsequent Event
Business Combination, Separately Recognized Transactions [Line Items]
Acquired refinery throughput capacity (barrels per day)										14,500
Total purchase price										$ 115,694
Inventories										15,000
Common units sold in public offering	6,000,000	750,000	11,000,000	4,500,000				5,750,000			750,000
Public offering price per share	$ 25.50	$ 18.00	$ 18.00	$ 21.45				$ 31.81
Proceeds from public offerings of common units, net	146,558	12,915	189,497	92,290	146,558	294,702	793	175,248
Underwriting discounts	6,180	540	7,866	3,915				7,360
General partner contributed capital								3,733
General partner percentage interest in partners capital								2.00%
Quarterly cash distribution date												Jan. 14, 2013
Cash distribution per unit													$ 0.65
Aggregate quarterly distribution														44,540
Distribution paid date															Feb. 14, 2013
Record date for the close of business															Feb. 04, 2013
Quarterly distribution dividends payable amount per unit																$ 2.60
Quarterly distribution dividends payable amount																178,160
Joint venture, profit sharing percentage																	50.00%
Derivative decrease to fair value									(24,000)
Fair of value net liability									69,000
Long-term debt increase to fair value									$ 20,000

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Employee Benefit Plans - Assumptions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
1% Point Increase, Effect on total service and interest cost components of benefit costs	110
1% Point Decrease, Effect on total service and interest cost components of benefit costs	(85)
1% Point Increase, Effect on postretirement benefit obligation	5
1% Point Decrease, Effect on postretirement benefit obligation	(4)
Pension Plans, Defined Benefit
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate	3.83%	4.59%
Other Postretirement Benefit Plans, Defined Benefit
Assumed Trend Rates
Immediate trend rate	8.00%	8.20%	8.40%
Penreco Plan | Pension Plans, Defined Benefit
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate	4.63%	5.50%	6.04%
Expected return on plan assets	6.00%	6.50%	7.50%
Penreco Plan | Other Postretirement Benefit Plans, Defined Benefit
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate	3.33%	4.04%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate	4.04%	4.54%	5.55%
Assumed Trend Rates
Immediate trend rate	7.70%	8.00%
Benefit obligation ultimate trend rate		4.50%
Net periodic cost ultimate trend rate	4.50%	4.50%	4.50%
Benefit obligation year that rate reaches ultimate trend rate	2029	2029
Net periodic cost year that rate reaches ultimate trend rate	2029	2029	2029
Assumed annual percentage change for trend rate	(0.20%)
Montana Plan | Pension Plans, Defined Benefit
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Rate of compensation increase	3.00%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate	3.89%
Expected return on plan assets	6.00%
Rate of compensation increase	3.00%
Superior Plan | Pension Plans, Defined Benefit
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Rate of compensation increase		3.75%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate	4.55%	4.71%
Expected return on plan assets	3.00%	6.50%
Rate of compensation increase	3.75%	3.75%
Superior Plan | Other Postretirement Benefit Plans, Defined Benefit
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate		4.65%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate	4.65%	4.82%
Assumed Trend Rates
Immediate trend rate		8.00%
Benefit obligation ultimate trend rate		4.50%
Net periodic cost ultimate trend rate	4.50%	5.00%
Benefit obligation year that rate reaches ultimate trend rate		2029
Net periodic cost year that rate reaches ultimate trend rate	2029	2020

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Employee Benefit Plans - Change in Benefit Obligation (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits
Components of net periodic pension and other post retirement benefits cost
Service cost	$ 1,130	$ 296	$ 84
Interest cost	2,376	1,638	1,336
Expected return on assets	(1,704)	(1,347)	(1,034)
Amortization of net (gain) loss	578	281	274
Amortization of prior service cost	0	0	0
Curtailment gain recognized	(218)	0	0
Settlement gain recognized	0	0	0
Net periodic pension cost	2,162	868	660
Other Post Retirement Employee Benefits
Components of net periodic pension and other post retirement benefits cost
Service cost	287	114	0
Interest cost	185	96	23
Expected return on assets	0	0	0
Amortization of net (gain) loss	(7)	(2)	(3)
Amortization of prior service cost	(39)	(35)	(35)
Curtailment gain recognized	(6,983)	0	0
Settlement gain recognized	(141)	0	0
Net periodic pension cost	$ (6,698)	$ 173	$ (15)

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Document and Entity Information (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Feb. 28, 2013	Jun. 29, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	Calumet Specialty Products Partners, L.P.
Entity Central Index Key	0001340122
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 937.1
Entity Common Stock, Shares Outstanding		63,279,778

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

The Company has two domestic defined contribution plans administered by its general partner for (i) all full-time employees that are eligible to participate in the plan (“Calumet 401k Plan”) and (ii) all Montana union employees that are eligible to participate in the plan (“Montana 401k Plan”). Participants in the Calumet 401k Plan 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% of eligible compensation contribution by the participant up to 4% and 50% of each additional 1% eligible compensation contribution up to 6%, for a maximum contribution by the Company of 5% of eligible compensation contributions per participant. Participants in the Montana 401k Plan are allowed to contribute pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% contribution by the participant up to 6% for a maximum contribution. The Company’s matching contributions expenses were $3,224, $2,343 and $1,948 for 2012, 2011 and 2010, respectively. The plans also include a profit-sharing component for eligible employees. 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 $2,511, $1,448 and $1,331 for 2012, 2011 and 2010, respectively.

The Company has domestic noncontributory defined benefit plans for 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”), (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”) or (iii) were former employees of Montana Refining Company, Inc. and who became employees of the Company as a result of the Montana Acquisition on October 1, 2012 (the “Montana Pension Plan” and together with the Penreco Pension Plan and the Superior Pension Plan, the “Pension Plan”).

Under the Penreco Pension Plan and Superior Pension Plan benefits are based primarily on years of service for USW and IUOE represented employees and the employee’s final 60 months’ average compensation for salaried employees. Under the Montana Pension plan benefits are based primarily on years of service and the employees’ 36 months’ highest 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 balanced fund, a commingled fund and cash and cash equivalents.

The Company also has domestic contributory defined benefit post retirement 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.”

In 2009, the Company amended the Penreco Pension Plan, which curtailed Penreco employees from accumulating additional benefits subsequent to December 31, 2009.

Effective July 1, 2012, the Company amended the Superior Pension Plan and Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012. For the year ended December 31, 2012, the Company recorded a $218 curtailment gain related to the Superior Pension Plan and a $6,983 curtailment gain related to the Superior Other Plan, all of which is recorded in general and administrative expense in the consolidated statements of operations. All information presented below has been adjusted for this curtailment.

Effective October 1, 2012, the date of the Montana Acquisition, the Company amended the Montana Pension Plan, which curtailed only the Montana salaried employees from accumulating additional benefits subsequent to October 31, 2012. All information presented below has been adjusted for these curtailments.

During 2012, the Company made contributions of $3,076 to its Pension Plan and $29 to its Other Plan. The Company expects to make contributions in 2013 of approximately $4,402 to its Pension Plan and $59 to its Other Plan.

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,
	2012						2011
	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	$	55,265		$	7,734		$	24,761		$	446
Projected benefit obligation attributable to acquisitions	4,900			—			26,218			6,477
Service cost	1,130			287			296			114
Interest cost	2,376			185			1,638			96
Plan curtailments	(3,685		)	(7,873		)	—			—
Benefits paid	(2,607		)	(80		)	(1,162		)	(81		)
Actuarial loss	7,897			106			3,554			624
Administrative expense	(40		)	—			(40		)	—
Plan amendments	—			(81		)	—			—
Employee contributions	—			51			—			58
Benefit obligation at end of year	$	65,236		$	329		$	55,265		$	7,734
Change in plan assets:
Fair value of plan assets at beginning of year	$	36,042		$	—		$	16,039		$	—
Fair value of pension assets attributable to acquisitions	3,178			—			17,718			—
Benefit payments	(2,607		)	(80		)	(1,162		)	(81		)
Actual return on assets	1,917			—			1,568			—
Administrative expense	(40		)	—			(40		)	—
Employee contributions	—			51			—			58
Employer contribution	3,076			29			1,919			23
Fair value of plan assets at end of year	$	41,566		$	—		$	36,042		$	—
Funded status — benefit obligation in excess of plan assets	$	(23,670	)	$	(329	)	$	(19,223	)	$	(7,734	)
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	$	(23,670	)	$	(329	)	$	(19,223	)	$	(7,734	)
Prior service credit	—			(240		)	—			(275		)
Unrecognized net actuarial loss (gain)	11,927			(161		)	8,289			553
Accumulated other comprehensive (income) loss	11,927			(401		)	8,289			278
Net amount recognized at end of year	$	(11,743	)	$	(730	)	$	(10,934	)	$	(7,456	)

The accumulated benefit obligation for the Pension Plan was $63,429 and $52,543 as of December 31, 2012 and 2011, respectively. The accumulated benefit obligation for the Pension Plan was more than plan assets by $21,863 and $16,501 as of December 31, 2012 and 2011, respectively. Selected information for the Company’s Pension Plan with an accumulated benefit obligation in excess of plan assets were as follows:

	Year Ended December 31,
	2012		2011
Projected benefit obligation	$	65,236	$	55,265
Accumulated benefit obligation	$	63,429	$	52,543
Fair value of plan assets	$	41,566	$	36,042

The components of net periodic pension cost and other post retirement benefits cost 2012, 2011 and 2010 were as follows:

	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011			2010
Service cost	$	1,130		$	296		$	84		$	287		$	114		$	—
Interest cost	2,376			1,638			1,336			185			96			23
Expected return on assets	(1,704		)	(1,347		)	(1,034		)	—			—			—
Amortization of net (gain) loss	578			281			274			(7		)	(2		)	(3		)
Amortization of prior service cost	—			—			—			(39		)	(35		)	(35		)
Curtailment gain recognized	(218		)	—			—			(6,983		)	—			—
Settlement gain recognized	—			—			—			(141		)	—			—
Net periodic pension cost	$	2,162		$	868		$	660		$	(6,698	)	$	173		$	(15	)

The components of changes recognized in other comprehensive income for the Pension Plan and Other Plan for 2012, 2011 and 2010 were as follows:

	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011		2010
Changes in plan assets and benefit obligations recognized in other comprehensive income:
Net loss	$	4,216		$	3,334		$	695		$	106		$	624	$	30
New prior service cost	—			—						(81		)	—		(345		)
Amounts recognized as a component of net periodic benefit cost:
Amortization or settlement recognition of net (loss) gain	(578		)	(281		)	(274		)	(820		)	2		3
Amortization or curtailment recognition of prior service credit	—			—			—			116			35		35
Total recognized in other comprehensive loss (income)	$	3,638		$	3,053		$	421		$	(679	)	$	661	$	(277	)
Total recognized in net periodic benefit and other comprehensive loss (income)	$	5,800		$	3,921		$	1,081		$	(7,377	)	$	834	$	(292	)

The portion relating to the Pension Plan and Other Plan classified in accumulated other comprehensive loss is $11,526 and $8,567 as of December 31, 2012 and 2011, respectively. In 2013, the estimated amount that will be amortized from accumulated other comprehensive income includes a loss of $817 for the Pension Plan. Also in 2013, the estimated amounts that will be amortized from accumulated other comprehensive income include a gain of $8 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, 2012 and 2011 were as follows:

	Benefit Obligations Assumptions
	2012		2011
Pension Plan:
Discount rate	3.83	%	4.59	%
Rate of compensation increase for Penreco Pension Plan	N/A		N/A
Rate of compensation increase for Superior Pension Plan	N/A		3.75	%
Rate of compensation increase for Montana Pension Plan	3.00	%	N/A
Other Plan:
Discount rate for Penreco Other Plan	3.33	%	4.04	%
Discount rate for Superior Other Plan	N/A		4.65	%
Immediate trend rate for Penreco Other Plan (1)	7.70	%	8.00	%
Immediate trend rate for Superior Other Plan (2)	N/A		8.00	%
Ultimate trend rate for Penreco Other Plan (1)	4.50	%	4.50	%
Ultimate trend rate for Superior Other Plan (2)	N/A		4.50	%
Year that the rate reaches ultimate trend rate for Penreco Other Plan (1)	2029		2029
Year that the rate reaches ultimate trend rate for Superior Other Plan (2)	N/A		2029

(1) For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% in 2029 for the Penreco Other Plan and remain at that level thereafter.

(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% in 2029 for the Superior Other Plan and remain at that level thereafter. Effective July 1, 2012, the Company amended the Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012.

The significant weighted average assumptions used to determine the net periodic benefit cost for the years ended December 31, 2012 and 2011 were as follows:

	Net Periodic Benefit Cost Assumptions
	2012		2011		2010
Pension Plan:
Discount rate for Penreco Pension Plan	4.63	%	5.50	%	6.04	%
Discount rate for Superior Pension Plan	4.55	%	4.71	%	N/A
Discount rate for Montana Pension Plan	3.89	%	N/A		N/A
Expected return on plan assets for Penreco Pension Plan (1)	6.00	%	6.50	%	7.50	%
Expected return on plan assets for Superior Pension Plan (1)	3.00	%	6.50	%	N/A
Expected return on plan assets for Montana Pension Plan (1)	6.00	%	N/A		N/A
Rate of compensation increase for Penreco Pension Plan	N/A		N/A		N/A
Rate of compensation increase for Superior Pension Plan	3.75	%	3.75	%	N/A
Rate of compensation increase for Montana Pension Plan	3.00	%	N/A		N/A
Other Plan:
Discount rate for Penreco Other Plan	4.04	%	4.54	%	5.55	%
Discount rate for Superior Other Plan	4.65	%	4.82	%	N/A
Immediate trend rate (2)	8.00	%	8.20	%	8.40	%
Ultimate trend rate for Penreco Other Plan (2)	4.50	%	4.50	%	4.50	%
Ultimate trend rate for Superior Other Plan (2)	4.50	%	5.00	%	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)	2029		2020		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 2012. 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.

An increase or decrease by one percentage point in the assumed healthcare cost trend rates would have the following effect on the post retirement benefit obligation and service and interest cost components of benefit costs for the Other Plan as of December 31, 2012:

	1% Point Increase		1% Point Decrease
Increase (decrease) in:
Effect on total of service and interest cost components of benefit costs	$	110	$	(85	)
Effect on post retirement benefit obligation	$	5	$	(4	)

Investment Policy

The Company’s 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 the Company’s 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 the Company’s investment objectives, ensure risk control, and limit concentrations.

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, 2012 and 2011 by asset category, are as follows:

	2012		2011
	Pension Benefits		Pension Benefits
Cash and cash equivalents (1)	47	%	62	%
Equity	14	%	11	%
Foreign equities	5	%	2	%
Fixed income	20	%	18	%
Balanced fund	7	%	—	%
Commingled fund	7	%	7	%
	100	%	100	%

(1) The Superior Pension Plan assets are included in cash and cash equivalents and such assets will be invested in 2013 based upon the current investment policy.

The Company’s investments associated with its Pension Plan primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded, (iii) a commingled fund and (iv) a balanced fund. The mutual and balanced 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 8 for the definition of Levels 1, 2 and 3. The Company’s Pension Plan assets measured at fair value at December 31, 2012 and 2011 were as follows:

	Fair Value of Pension Assets at December 31,
	2012				2011
	Level 1		Level 2		Level 1		Level 2
Cash and cash equivalents	$	19,295	$	—	$	22,243	$	—
Equity	5,900		—		4,000		—
Foreign equities	2,268		—		691		—
Commingled fund	—		2,731		—		2,462
Balanced fund	2,961		—		—		—
Fixed income	8,411		—		6,646		—
	$	38,835	$	2,731	$	33,580	$	2,462

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2012:

	Pension Benefits		Other Post Retirement Employee Benefits
2013	$	2,402	$	59
2014	2,504		44
2015	2,608		41
2016	2,720		25
2017	2,813		16
2018 to 2022	16,355		72
Total	$	29,402	$	257

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Fair Value Measurements (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Realized (gain) loss on derivative instruments	$ 5,665	$ (18,292)	$ (23,547)
Unrealized loss on derivative instruments	(3,787)	(10,383)	(15,843)
Change in fair value of cash flow hedges	(215,132)	(34,160)	(29,015)
Level 3
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Fair value at January 1,	14,921	(32,814)
Realized (gain) loss on derivative instruments	(9,452)
Unrealized loss on derivative instruments	(3,787)
Change in fair value of cash flow hedges	(215,132)
Settlements	168,570
Transfers in (out) of Level 3	0	0
Fair value at December 31,	$ (44,880)	$ 14,921

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Employee Benefit Plans - Accumulated Benefit Obligation (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligations in excess of plan assets	$ 21,863	$ 16,501
Projected benefit obligation	65,236	55,265	24,761
Accumulated benefit obligation	63,429	52,543
Fair value of plan assets	41,566	36,042	16,039
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	329	7,734	446
Fair value of plan assets	$ 0	$ 0	$ 0

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Consolidated Statements of Operations (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Statement [Abstract]
Sales	$ 4,657,282	$ 3,134,923	$ 2,190,752
Cost of sales	4,144,105	2,860,793	1,992,003
Gross profit	513,177	274,130	198,749
Operating costs and expenses:
Selling	41,556	12,237	8,436
General and administrative	60,904	38,599	26,788
Transportation	107,900	94,187	85,471
Taxes other than income taxes	9,073	5,661	4,601
Insurance recoveries	0	(8,698)	0
Other	7,816	6,852	1,963
Operating income	285,928	125,292	71,490
Other income (expense):
Interest expense	(85,573)	(48,747)	(30,497)
Debt extinguishment costs	0	(15,130)	0
Realized gain (loss) on derivative instruments	9,452	(7,909)	(7,704)
Unrealized loss on derivative instruments	(3,787)	(10,383)	(15,843)
Other	470	842	(147)
Total other expense	(79,438)	(81,327)	(54,191)
Income before income taxes	206,490	43,965	17,299
Income tax expense	753	929	598
Net income	205,737	43,036	16,701
Allocation of net income:
Net income	205,737	43,036	16,701
Less:
General partner’s interest in net income	4,115	861	334
General partner’s incentive distribution rights	5,433	322	0
Non-vested share based payments	1,199	0	0
Net income available to limited partners	$ 194,990	$ 41,853	$ 16,367
Weighted average limited partner units outstanding:
Basic (units)	55,559,000	42,599,000	35,335,000
Diluted (units)	55,677,000	42,644,000	35,351,000
Limited partners’ interest basic net income per unit	3.51	0.98	0.46
Limited partners’ interest diluted net income per unit	3.50	0.98	0.46
Cash distributions declared per limited partner unit	$ 2.30	$ 1.94	$ 1.83

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Operating Leases

The Company has various operating leases for the use of land, storage tanks, 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, 2012, 2011, and 2010 was $26,934, $20,490 and $17,104, respectively.

As of December 31, 2012, 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
2013	$	23,194
2014	14,937
2015	11,752
2016	7,946
2017	5,999
Thereafter	15,094
Total	$	78,922

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.

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 supplies the Superior refinery with a portion 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. In April 2012, the Company amended and restated the BP Purchase Agreement, which has an initial term of one year ending April 1, 2013, and 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. 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.

Certain other feedstocks are purchased under long-term supply contracts. The Company also purchases finished products from Houston Refining. 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. In addition, 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. The annual purchase commitment under these agreements is approximately $162,916.

As of December 31, 2012, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows:

Year	Commitment
2013	$	999,146
2014	157,812
2015	937
2016	579
2017	—
Thereafter	—
Total	$	1,158,474

In connection with the Company’s acquisition of Penreco on January 3, 2008, the Company entered into a feedstock purchase agreement with Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, Phillips 66 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 $76,355 of feedstock for the LVT unit in each fiscal year of the term of the contract, expiring January 1, 2018, based on pricing estimates as of December 31, 2012. This amount is not included in the table above.

Labor Matters

The Company has approximately 580 employees covered by various collective bargaining agreements, or approximately 48.7% of its total workforce of approximately 1,190 employees. These agreements have expiration dates of March 31, 2013, April 30, 2013, April 30, 2014, October 31, 2014, January 31, 2015 and June 30, 2017. The Company has approximately 230 employees, or approximately 19.3% 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”), the Louisiana Department of Environmental Quality (“LDEQ”), the Wisconsin Department of Natural Resources (“WDNR”), the Montana Department of Environmental Quality (“MDEQ”), the Texas Commission on Environmental Quality (“TCEQ”), the Internal Revenue Service, various state and local departments of revenue and the federal Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.

Insurance Recoveries

During the second quarter 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 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.

In connection with the Montana Acquisition (see Note 3), the Company became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and MDEQ. The material obligations imposed by the Montana Consent Decree have been completed. Periodic reporting is the primary current obligation under the Montana Consent Decree. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previous Hazardous Waste Permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. The Company believes that all such contamination is subject to the indemnification of Montana Refining Company, Inc. by Holly Corporation (“Holly”) for pre-existing conditions. The Company is indemnified by Holly under the asset purchase agreement between Holly and Connacher, which the Company became a party to such indemnification rights through the share purchase agreement between the Company and Connacher. Holly is responsible for existing environmental conditions at the Montana refinery, and previously had been reimbursing Connacher for remedial actions subject to the indemnification.

Also, in connection with the Superior Acquisition, the Company became a party to an existing consent decree (“Superior Consent Decree”) with the EPA and the WDNR that applies, in part, to its Superior refinery. Under the Superior 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 the WDNR. The Company currently estimates costs of approximately $3,000 to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform required tasks under the Superior 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 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 federal 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 will result in the Company incurring additional costs, which could be substantial. During 2012 and 2011, the Company incurred approximately $2,379 and $2,270, respectively, of costs related to installing process equipment pursuant to the EPA fuel content regulations.

On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and attended an informal conference with the EPA held September 12, 2012. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial results or operations.

In addition, the Company is indemnified by Murphy Oil for specified environmental liabilities arising from the operations of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior 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 under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations prior to December 31, 2010. Among other things the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During 2012 and 2011, the Company incurred approximately $4,200 and $4,000, respectively, of expenditures and estimates additional expenditures of approximately $2,000 to $6,000 of capital expenditures and expenditures related to additional personnel and environmental studies over the next three years as a result of the implementation those requirements. 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.

In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require the Company to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on June 1, 2012, the EPA issued final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. The Company is currently evaluating the effect that the NSPS rule may have on the Company’s refinery operations.

Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. Additionally, the Company incurred approximately $395, $338 and $541 in 2012, 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. 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.

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, 2012 and December 31, 2011, the Company incurred approximately $728 and $4,075, respectively, of capital expenditures and expects to incur between $1,000 and $4,000 of capital expenditures in 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, 2012 and December 31, 2011, the Company had outstanding standby letters of credit of $222,359 and $230,040, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 6 for additional information regarding the Company’s revolving credit facility. The maximum amount of letters of credit the Company could issue at December 31, 2012 and 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 in effect ($850,000 at December 31, 2012 and December 31, 2011).

As of December 31, 2012 and December 31, 2011, the Company had availability to issue letters of credit of $355,091 and $340,715, respectively, under its revolving credit facility. As discussed in Note 6, as of December 31, 2012 and 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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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

Changes in goodwill balances are as follows:

	Year Ended December 31,
	2012						2011
	Specialty		Fuel				Specialty		Fuel
	Products		Products		Total		Products		Products		Total
Beginning balance:	$	48,335	$	—	$	48,335	$	48,335	$	—	$	48,335
Acquisitions	111,035		27,643		138,678		—		—		—
Accumulated impairment losses	—		—		—		—		—		—
Ending balance:	$	159,370	$	27,643	$	187,013	$	48,335	$	—	$	48,335

Other intangible assets consist of the following:

	Weighted Average Life (Years)	December 31, 2012					December 31, 2011
		Gross Amount		Accumulated Amortization			Gross Amount		Accumulated Amortization
Customer relationships	20	$	154,307	$	(22,612	)	$	28,482	$	(12,936	)
Supplier agreements	4	21,519		(21,519		)	21,519		(19,926		)
Tradenames - Royal Purple Retail	Indefinite	14,790		—			—		—
Tradenames	9	6,421		(550		)	—		—
Trade secrets	12	44,179		(3,116		)	—		—
Patents	12	1,573		(1,112		)	1,573		(966		)
Non-competition agreements	5	5,827		(5,780		)	5,732		(4,182		)
Distributor agreements	3	2,019		(2,019		)	2,019		(2,019		)
Royalty agreements	19	4,499		(1,343		)	4,499		(1,120		)
	16	$	255,134	$	(58,051	)	$	63,824	$	(41,149	)

Supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements are being amortized to properly match expense with the discounted estimated future cash flows over the terms of the related agreements. Agreements with terms allowing for the potential extension of such agreements are being amortized based on the initial term only. Customer relationships are being amortized using discounted estimated future cash flows based upon assumed rates of annual customer attrition. For the years ended December 31, 2012, 2011 and 2010, the Company recorded amortization expense of intangible assets of $16,902, $6,991 and $8,810, respectively.

The Company estimates that amortization of intangible assets for the next five years will be as follows:

Year	Amortization Amount
2013	$	25,401
2014	$	24,297
2015	$	22,165
2016	$	20,217
2017	$	17,669
2018	$	14,904

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Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

On January 14, 2013, the Company declared a quarterly cash distribution of $0.65 per unit on all outstanding common units, or approximately $44,540 (including the general partner’s incentive distribution rights) in aggregate, for the quarter ended December 31, 2012. The distribution was paid on February 14, 2013 to unitholders of record as of the close of business on February 4, 2013. This quarterly distribution of $0.65 per unit equates to $2.60 per unit, or approximately $178,160 (including the general partner’s incentive distribution rights) in aggregate on an annualized basis.

On February 7, 2013, the Company entered into a joint venture agreement with MDU Resources Group, Inc. (“MDU”) to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture will be called Dakota Prairie Refining, LLC. Funding for the project will occur over the course of the construction period, with the majority of the direct funding by the Company expected in 2014. The joint venture will allocate profits on a 50%/50% basis to the Company and MDU. The joint venture will be governed by a board of managers comprised of representatives from both the Company and MDU. MDU will provide a portion of the crude oil supply to the refinery, as well as natural gas and electricity utility services. The Company will provide refinery operations, crude oil procurement and refined product marketing expertise to the joint venture.

The fair value of the Company’s derivatives decreased by approximately $24,000 subsequent to December 31, 2012 to a net liability of approximately $69,000. The fair value of the Company’s long-term debt, excluding capital leases, has increased by approximately $20,000 subsequent to December 31, 2012.

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Earnings Per Unit

12 Months Ended

Dec. 31, 2012

Earnings Per Unit [Abstract]

Earnings per Unit

Earnings per Unit

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(In thousands, except unit data)
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	205,737	$	43,036	$	16,701
General partner’s interest in net income	4,115		861		334
General partner’s incentive distribution rights	5,433		322		—
Nonvested share based payments	1,199		—		—
Net income available to limited partners	$	194,990	$	41,853	$	16,367
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average limited partner units outstanding	55,559		42,599		35,335
Effect of dilutive securities:
Participating securities — phantom units	118		45		16
Diluted weighted average limited partner units outstanding	55,677		42,644		35,351
Limited partners’ interest basic net income per unit	$	3.51	$	0.98	$	0.46
Limited partners’ interest diluted net income per unit	$	3.50	$	0.98	$	0.46

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Partners' Capital Incentive Distribution (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Minimum Quarterly Distribution | Unitholders
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	98.00%
Minimum Quarterly Distribution | General Partner
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	2.00%
First Target Distribution | Unitholders
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	98.00%
First Target Distribution | General Partner
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	2.00%
Second Target Distribution | Unitholders
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	85.00%
Second Target Distribution | General Partner
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	15.00%
Third Target Distribution | Unitholders
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	75.00%
Third Target Distribution | General Partner
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	25.00%
Thereafter | Unitholders
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	50.00%
Thereafter | General Partner
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest in Distributions	50.00%
Minimum | Minimum Quarterly Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Per Common Unit	0.45
Minimum | Second Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Per Common Unit	0.495
Minimum | Third Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Per Common Unit	0.563
Minimum | Thereafter
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Per Common Unit	0.675
Maximum | First Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Per Common Unit	0.495
Maximum | Second Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Per Common Unit	0.563
Maximum | Third Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Per Common Unit	0.675

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:

• Level 1—inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities

• Level 2—inputs include other than quoted prices in active markets that are either directly or indirectly observable

• Level 3—inputs include 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.

Recurring Fair Value Measurements

Derivative Assets and Liabilities

Derivative instruments are reported in the accompanying consolidated financial statements at fair value. 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 Baa2 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, crude oil basis, gasoline, diesel, jet fuel, natural gas and interest rate swaps 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, 2012, the Company’s asset was reduced by $100 and liability was reduced by approximately $185. As a result of applying the CDS at December 31, 2011, the Company’s asset was reduced by $1,297 and the liability was reduced by approximately $165.

Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for crude oil, crude oil basis, gasoline, jet fuel, diesel, natural gas and interest rate swaps, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. 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. See Note 7 for further information on derivative instruments.

Pension Assets    

Pension assets are reported at fair value using quoted market prices in the accompanying consolidated financial statements. The Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consist of (i) cash and cash equivalents, (ii) mutual funds that are publicly traded, (iii) a commingled fund and (iv) a balanced fund. The mutual and balanced funds are publicly 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 quarter end. See Note 11 for further information on pension assets.

Liability Awards

The fair values of the Company’s Liability Awards are updated each balance sheet date based on the closing unit price on the balance sheet date. See Note 10 for further information on Liability Awards.

Hierarchy of Recurring Fair Value Measurements

The Company’s recurring assets and liabilities measured at fair value at December 31, 2012 and December 31, 2011 were as follows:

	December 31, 2012											December 31, 2011
	Level 1			Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets:
Derivative assets:
Crude oil swaps	—			—		10,517			10,517			—		—		83,919			83,919
Gasoline swaps	—			—		273			273			—		—		(20,605		)	(20,605		)
Diesel swaps	—			—		(7,871		)	(7,871		)	—		—		(4,561		)	(4,561		)
Jet fuel swaps	—			—		169			169			—		—		1,077			1,077
Natural gas swaps	—			—		—			—			—		—		(1,328		)	(1,328		)
Total derivative assets	—			—		3,088			3,088			—		—		58,502			58,502
Pension plan investments	38,835			2,731		—			41,566			33,580		2,462		—			36,042
Total recurring assets at fair value	$	38,835		$	2,731	$	3,088		$	44,654		$	33,580	$	2,462	$	58,502		$	94,544
Liabilities:
Derivative liabilities:
Crude oil swaps	$	—		$	—	$	(35,819	)	(35,819		)	$	—	$	—	$	56,041		$	56,041
Crude oil basis swaps	—			—		(3,363		)	(3,363		)	—		—		—			—
Gasoline swaps	—			—		(85		)	(85		)	—		—		(1,596		)	(1,596		)
Diesel swaps	—			—		(6,403		)	(6,403		)	—		—		(22,586		)	(22,586		)
Jet fuel swaps	—			—		(2,298		)	(2,298		)	—		—		(72,537		)	(72,537		)
Natural gas swaps	—			—		—			—			—		—		(1,892		)	(1,892		)
Interest rate swaps	—			—		—			—			—		—		(1,011		)	(1,011		)
Total derivative liabilities	—			—		(47,968		)	(47,968		)	—		—		(43,581		)	(43,581		)
Liability Awards	$	(2,239	)	$	—	$	—		$	(2,239	)	—		—		—			—
Total recurring liabilities at fair value	$	(2,239	)	$	—	$	(47,968	)	$	(50,207	)	$	—	$	—	$	(43,581	)	$	(43,581	)

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the year ended December 31, 2012 and 2011:

	Derivative Instruments, Net
	For the Year Ended December 31,
	2012			2011
Fair value at January 1,	$	14,921		$	(32,814	)
Realized (gain) loss on derivative instruments	(9,452		)	7,909
Unrealized loss on derivative instruments	(3,787		)	(10,383		)
Change in fair value of cash flow hedges	(215,132		)	(34,160		)
Settlements	168,570			84,369
Transfers in (out) of Level 3	—			—
Fair value at December 31,	$	(44,880	)	$	14,921
Total loss included in net income attributable to changes in unrealized loss relating to financial assets and liabilities held as of December 31,	$	(3,787	)	$	(10,383	)

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 instruments are recorded in earnings in realized 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 7 for further information on derivative instruments.

Nonrecurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. Refer to Note 3 for the fair values of assets acquired and liabilities assumed in connection with the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions.

The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. 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. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 4 for further information on goodwill.

The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived and indefinite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 4 for further information on long-lived assets.

Estimated Fair Value of Financial Instruments

Cash

The carrying values of cash are considered to be representative of their respective fair values.

Debt

The estimated fair value of long-term debt at December 31, 2012 consists primarily of the 2019 Notes and 2020 Notes. The estimated fair value of long-term debt at December 31, 2011 consists primarily of the 2019 Notes. The fair values of the Company’s 2019 Notes were based upon using quoted market prices in an active market and are classified as Level 1. The fair values of the Company’s 2020 Notes were based upon directly observable inputs and are classified as Level 2. The carrying value of borrowings, if any, under the Company’s revolving credit facility approximates its fair value as determined by discounted cash flows and is classified as Level 3. Capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 6 for further information on long-term debt.

The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at December 31, 2012 and December 31, 2011 were as follows:

	December 31, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial Instrument:
2019 Notes	$	658,795	$	587,602	$	591,750	$	586,304
2020 Notes	$	301,813	$	270,387	$	—	$	—
Capital lease and other obligations	$	5,512	$	5,512	$	786	$	786

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Commitments and Contingencies - Standby Letters of Credit (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Loss Contingencies [Line Items]
Maximum amount of letters of credit	$ 850,000,000	$ 850,000,000
Standby Letters of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding amount	222,359,000	230,040,000
Letters of credit issued to a hedging counterparty	25,000,000	25,000,000
Revolving Credit Facility
Loss Contingencies [Line Items]
Maximum amount of letters of credit	680,000,000
Letter of credit sublimit	400,000,000
Letter of credit sublimit percentage	80.00%
Availability to issue letters of credit	$ 355,091,000	$ 340,715,000

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Long-Term Debt

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Long-term debt consisted of the following:

	December 31, 2012			December 31, 2011
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 9.91% for the year ended December 31, 2012	600,000			600,000
Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012	275,000			—
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	5,512			786
Less unamortized discounts	(17,011		)	(13,696		)
Total long-term debt	863,501			587,090
Less current portion of long-term debt	771			551
	$	862,730		$	586,539

9 5/8% Senior Notes

On June 29, 2012, in connection with the Royal Purple Acquisition, the Company issued and sold $275,000 in aggregate principal amount of 9 5/8% of senior notes due August 1, 2020 (the “2020 Notes”) in a private placement pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 98.25 percent of par. The 2020 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $262,565, net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Royal Purple Acquisition. Refer to Note 3 for additional information regarding the Royal Purple Acquisition.

Interest on the 2020 Notes is paid semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2013. The 2020 Notes will mature on August 1, 2020, unless redeemed prior to maturity. The 2020 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (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 2020 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 indenture governing the 2020 Notes. Since all Company’s operating subsidiaries guarantee the 2020 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 August 1, 2015, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.625% 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 2020 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 August 1, 2016, the Company may on any one or more occasions redeem all or a part of the 2020 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 2020 Notes, if redeemed during the twelve-month period beginning on August 1 of the years indicated below:

Year	Percentage
2016	104.813	%
2017	102.406	%
2018 and at any time thereafter	100.000	%

Prior to August 1, 2016, the Company may on any one or more occasions redeem all or part of the 2020 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2020 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

The indenture governing the 2020 Notes contains covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2020 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2020 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 2020 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 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.

On June 29, 2012, in connection with the issuance and sale of the 2020 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2020 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC, so that holders of the 2020 Notes can offer to exchange the 2020 Notes for registered notes having substantially the same terms as the 2020 Notes and evidencing the same indebtedness as the 2020 Notes. The Company must use reasonable best efforts to cause the exchange offer registration statement to become effective by June 28, 2013 and remain effective until 180 days after the closing of the exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2020 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2020 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

9 3/8% 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 9 3/8% 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 9 3/8% 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. 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.”

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 the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (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 both Moody’s Investors Service, Inc. and 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 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

The Company has an $850,000 senior secured revolving credit facility, which is its primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility 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, 2012, the margin was 100 basis points for prime and 225 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s 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
≥ 66%	1.00%	2.25%
≥ 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 either 0.375% or 0.50% per annum depending on the average daily available unused borrowing capacity for the preceding month. 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, 2012 under the revolving credit facility was $577,450. As of December 31, 2012, the Company had no outstanding borrowings under the revolving credit facility, leaving $355,091 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.

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 has also issued to one counterparty a $25,000 standby letter of credit under the revolving credit facility. 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, 2012 and 2011. The Company’s master derivatives contracts and Collateral Trust Agreement (as defined below) 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.

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 from time to time.

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 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.

Maturities of Long-Term Debt

As of December 31, 2012, maturities of the Company’s long-term debt are as follows:

Year	Maturity
2013	$	771
2014	423
2015	303
2016	328
2017	355
Thereafter	878,332
Total	$	880,512

Capital Lease Obligations

The Company has a capital lease obligation for catalysts used in refining processes which will expire in 2013. In connection with the TruSouth Acquisition, the Company recorded $5,771 of capital leases for a building and equipment that will expire in 2027 and 2018, respectively. Assets recorded under these capital lease obligations are included in property, plant and equipment and consist of $11,071 and $4,201 as of December 31, 2012 and 2011, respectively. As of December 31, 2012 and 2011, the Company had recorded $4,251 and $3,221, respectively, in accumulated depreciation for these capital lease assets.

As of December 31, 2012, the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows:

Year	Capital Leases
2013	$	1,189
2014	805
2015	661
2016	661
2017	661
Thereafter	4,789
Total minimum lease payments	8,766
Less amount representing interest	3,254
Capital lease obligations	5,512
Less obligations due within one year	771
Long-term capital lease obligations	$	4,741

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Derivatives

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment) and natural gas. The Company uses various strategies to reduce the exposure to commodity price risk. The Company does not attempt to eliminate all of the Company’s risk due to the cost of such actions are believed to be too high in relation to the risk posed to the Company’s future cash flows, earnings and liquidity. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments such as swaps, futures and options to attempt to reduce the Company’s exposure with respect to:

• crude oil purchases;

• refined product sales;

• natural gas purchases; and

• fluctuations in the value of crude oil between geographic regions and in between the different types of crude oil such as NYMEX WTI, Light Louisiana Sour (“LLS”) and Western Canadian Select (“WCS”).

The Company does not hold or issue derivative instruments for trading purposes.

The Company recognizes all derivative instruments at their fair values (see Note 8) as either current assets or current 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 no longer qualifying it for hedge accounting. The Company recorded the following derivative assets and liabilities at their fair values as of December 31, 2012 and 2011:

	Derivative Assets						Derivative Liabilities
	December 31, 2012			December 31, 2011			December 31, 2012			December 31, 2011
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	10,517		$	83,919		$	(26,743	)	$	56,041
Gasoline swaps	273			(20,605		)	2,086			(1,596		)
Diesel swaps	(7,871		)	(4,561		)	(10,331		)	(22,586		)
Jet fuel swaps	169			1,077			(2,298		)	(72,537		)
Total derivative instruments designated as hedges	3,088			59,830			(37,286		)	(40,678		)
Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps	—			—			(10,725		)	—
Crude oil basis swaps	—			—			(3,363		)	—
Gasoline swaps	—			—			(2,171		)	—
Diesel swaps	—			—			3,928			—
Specialty products segment: (1)
Crude oil swaps	—			—			1,649			—
Natural gas swaps (2)	—			(1,328		)	—			(1,892		)
Interest rate swaps: (3)	—			—			—			(1,011		)
Total derivative instruments not designated as hedges	—			(1,328		)	(10,682		)	(2,903		)
Total derivative instruments	$	3,088		$	58,502		$	(47,968	)	$	(43,581	)

(1) 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.

(2) The Company periodically enters into 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 for the interest payments under the previous term loan facility are no longer designated as cash flow hedges.

The Company accounts for certain derivatives hedging purchases of crude oil, sales of gasoline, diesel and jet fuel 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. Periodically, the Company may enter into crude oil or fuel product basis swaps to more effectively hedge its crude oil purchases.  These derivatives can be combined with a swap contract in order to create a more effective hedge.  The Company has entered into crude oil basis swaps for 2013 that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract.

To the extent a derivative instrument designated as a hedge 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. Hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to unrealized gain (loss) on derivative instruments in the consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously accumulated in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments.

Effective January 1, 2012, hedge accounting was discontinued prospectively for certain crude oil derivative instruments when it was determined that they were no longer highly effective in offsetting changes in the cash flows associated with crude oil purchases at the Company’s Superior refinery due to the volatility in crude oil pricing differentials between heavy crude oil and NYMEX WTI. Effective April 1, 2012, hedge accounting was discontinued prospectively for certain gasoline and diesel derivative instruments associated with gasoline and diesel sales at the Company’s Superior refinery. The discontinuance of hedge accounting on these derivative instruments has caused the Company to recognize derivative gains of $40,096 in realized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012. The discontinuance of hedge accounting on these derivative instruments caused the Company to recognize derivative losses $2,933 in unrealized loss on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012.

The amount reclassified from accumulated other comprehensive income (loss) into earnings, as a result of the discontinuance of hedge accounting for certain jet fuel products derivative instruments because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, has caused the Company to recognize derivative losses of $1,719 in realized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012.

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 has resulted, 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 cash flows.

The Company recorded the following amounts in its consolidated balance sheets, consolidated statements of operations, consolidated statements of other comprehensive income (loss) and its consolidated statements of partners’ capital as of, and for the years ended December 31, 2012 and 2011 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 Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)
	Year Ended December 31,						Location of (Gain) Loss	Year Ended December 31,						Location of Gain (Loss)	Year Ended December 31,
Type of Derivative	2012			2011				2012			2011				2012			2011
Fuel products segment:
Crude oil swaps	$	(99,960	)	$	133,060		Cost of sales	$	(49,874	)	$	(110,945	)	Unrealized/Realized	$	99,672		$	(8,159	)
Gasoline swaps	(15,981		)	(38,289		)	Sales	38,388			29,468			Unrealized/Realized	(52,038		)	(1,850		)
Diesel swaps	(59,260		)	(53,622		)	Sales	62,966			79,810			Unrealized/Realized	(10,518		)	(573		)
Jet fuel swaps	(39,931		)	(77,288		)	Sales	104,482			102,473			Unrealized/Realized	(123		)	(2,715		)
Specialty products segment:
Crude oil swaps	—			—			Cost of sales	(1,877		)	2,512			Unrealized/Realized	—			—
Natural gas swaps	—			—			Cost of sales	—			—			Unrealized/Realized	—			—
Interest rate swaps:	—			1,979			Interest  expense	—			702			Unrealized/Realized	—			—
Total	$	(215,132	)	$	(34,160	)		$	154,085		$	104,020			$	36,993		$	(13,297	)

The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2012 and 2011 related to its derivative instruments not designated as cash flow hedges:

	Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivatives Year Ended December 31,						Amount of Gain (Loss) Recognized in Unrealized Loss on Derivatives Year Ended December 31,
Type of Derivative	2012			2011			2012			2011
Fuel products segment:
Crude oil swaps	$	(30,488	)	$	—		$	(39,967	)	$	—
Crude oil basis swaps	2,066			—			(3,363		)	—
Gasoline swaps	22,110			—			519			—
Diesel swaps	10,895			—			8,912			—
Jet fuel swaps	(1,719		)	—			—			—
Jet fuel collars	—			(746		)	—			726
Specialty products segment:
Crude oil swaps	—			932			1,649			(662		)
Natural gas swaps	(5,442		)	(171		)	3,221			(3,221		)
Interest rate swaps:	(732		)	(2,124		)	1,011			271
Total	$	(3,310	)	$	(2,109	)	$	(28,018	)	$	(2,886	)

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 derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of December 31, 2012, the Company had two counterparties, for which the derivatives held were net assets, totaling $3,088. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa2 and A- by Moody’s and S&P, respectively. In the event of default, the Company potentially would 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, 2012 or December 31, 2011. 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, 2012 and 2011, the Company had provided its counterparties with no collateral except for a $25,000 letter of credit 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, 2012 and 2011, there was a net liability of $7,515 and a net asset of $3,561, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, certain 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 cash flow hedges classified in accumulated other comprehensive loss was $13,953 as of December 31, 2012. The effective portion of the cash flow hedges classified in accumulated other comprehensive income was $47,094 as of December 31, 2011. Absent a change in the fair market value of the underlying transactions, the following other comprehensive income (loss) at December 31, 2012 will be reclassified to earnings by December 31, 2015 with balances being recognized as follows:

Year	Accumulated Other Comprehensive Income (Loss)
2013	$	(7,755	)
2014	(7,789		)
2015	1,591
Total	$	(13,953	)

Based on fair values as of December 31, 2012, the Company expects to reclassify $7,755 of net losses on derivative instruments from accumulated other comprehensive loss 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 dates of settlements.

Crude Oil Swap Contracts — Specialty Products Segment

As of December 31, 2012, the Company had purchased a crude oil swap for 200,000 bbls in the second quarter of 2012 related to future crude oil purchases in its specialty products segment, which is not designated as a cash flow hedge. The Company subsequently sold a crude oil derivative swap in the third quarter of 2012, and the net impact of these two derivatives is a net gain of $1,649 that has been recorded to unrealized loss in the consolidated statements of operations for the year ended December 31, 2012. This gain will be realized in January 2013 upon settlement and will be recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations.

At December 31, 2011, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.

Natural Gas Swap Contracts

At December 31, 2012, the Company did not have any natural gas derivatives related to natural gas purchases in its specialty products segment.

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

Crude Oil Contracts — Fuel Products Segment

Crude Oil Swap Contracts

At December 31, 2012, 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 2013	1,665,000	18,500	$	101.67
Second Quarter 2013	1,911,000	21,000	100.22
Third Quarter 2013	1,426,000	15,500	95.62
Fourth Quarter 2013	1,104,000	12,000	93.41
Calendar Year 2014	5,110,000	14,000	89.47
Calendar Year 2015	4,781,500	13,100	89.49
Totals	15,997,500
Average price			$	92.85

At December 31, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as cash flow hedges.

Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Swap ($/Bbl)
First Quarter 2013	630,000	7,000	$	101.34
Second Quarter 2013	455,000	5,000	98.56
Third Quarter 2013	368,000	4,000	96.58
Fourth Quarter 2013	368,000	4,000	96.58
Totals	1,821,000
Average price			$	98.72

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

Crude Oil Basis Swap Contracts

In April, July and December 2012, the Company entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between Canadian heavy crude oil and NYMEX WTI crude oil. At December 31, 2012, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as cash flow hedges.

Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Differential to NYMEX WTI ($/Bbl)
First Quarter 2013	180,000	2,000	$	(23.75	)
Second Quarter 2013	364,000	4,000	(27.38		)
Third Quarter 2013	184,000	2,000	(23.75		)
Fourth Quarter 2013	184,000	2,000	(23.75		)
Totals	912,000
Average differential			$	(25.20	)

At December 31, 2011, the Company had no derivatives related to crude oil basis swaps in its fuel products segment.

Fuel Products Swap Contracts

Diesel Swap Contracts

At December 31, 2012, 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)
Second Quarter 2013	546,000	6,000	$	122.74
Third Quarter 2013	874,000	9,500	122.23
Fourth Quarter 2013	828,000	9,000	120.82
Calendar Year 2014	3,835,000	10,507	116.00
Calendar Year 2015	4,781,500	13,100	115.81
Totals	10,864,500
Average price			$	117.13

At December 31, 2012, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges.

Diesel Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
First Quarter 2013	540,000	6,000	$	130.57
Second Quarter 2013	364,000	4,000	126.82
Third Quarter 2013	276,000	3,000	124.17
Fourth Quarter 2013	276,000	3,000	124.17
Totals	1,456,000
Average price			$	127.20

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

Jet Fuel Swap Contracts

At December 31, 2012, 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 2013	1,035,000	11,500	$	127.39
Second Quarter 2013	819,000	9,000	129.20
Third Quarter 2013	368,000	4,000	125.13
Fourth Quarter 2013	276,000	3,000	122.36
Calendar Year 2014	1,275,000	3,493	116.64
Totals	3,773,000
Average price			$	123.56

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

Gasoline Swap Contracts

At December 31, 2012, 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 2013	630,000	7,000	$	113.59
Second Quarter 2013	546,000	6,000	116.32
Third Quarter 2013	184,000	2,000	114.73
Totals	1,360,000
Average price			$	114.84

At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.

Gasoline Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
First Quarter 2013	90,000	1,000	$	105.50
Second Quarter 2013	91,000	1,000	105.50
Third Quarter 2013	92,000	1,000	105.50
Fourth Quarter 2013	92,000	1,000	105.50
Totals	365,000
Average price			$	105.50

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

Interest Rate Swap Contracts

The Company has no variable rate debt and no interest rate swaps outstanding as of December 31, 2012. For the Company’s fixed rate 2019 and 2020 Notes, changes in interest rates will generally affect the fair value, but not the Company’s interest expense or cash flows.

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Partners' Capital

12 Months Ended

Dec. 31, 2012

Equity [Abstract]

Partners' Capital

Partners’ Capital

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

On February 24, 2011, the Company completed 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.

On May 8, 2012, the Company completed a public offering of its common units in which it sold 6,000,000 common units to the underwriters of the offering at a price to the public of $25.50 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 $146,558 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $6,180. The Company’s general partner contributed $3,122 to maintain its 2% general partner interest.

Of the 57,529,778 common units outstanding at December 31, 2012, 39,397,092 common units were held by the public, with the remaining 18,132,686 common units held by the Company’s affiliates.

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 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Any holder, other than the general partner or the general partner’s affiliates, that owns 20% or more of any class of units outstanding, cannot vote on any matter.

• 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 and 2020 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 (i) a $70,000 basket for the 2019 Notes and (ii) a $120,000 for the 2020 Notes, 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, 2012, 2011 and 2010, the Company made distributions of $132,400, $82,743 and $65,739, respectively, to its partners. For the years ended December 31, 2012, 2011 and 2010, the general partner was allocated $5,433, $322 and $0, respectively, in incentive distribution rights.

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Long-Term Debt - Basis Spread (Details)	Dec. 31, 2012
Prime
Debt Instrument [Line Items]
Margin basis point	0.00%
Libor
Debt Instrument [Line Items]
Margin basis point	2.25%
Greater than 66% | Prime | Revolving Credit Facility
Debt Instrument [Line Items]
Margin basis point	1.00%
Greater than 66% | Libor | Revolving Credit Facility
Debt Instrument [Line Items]
Margin basis point	2.25%
Between 33% and 66% | Prime | Revolving Credit Facility
Debt Instrument [Line Items]
Margin basis point	1.25%
Between 33% and 66% | Libor | Revolving Credit Facility
Debt Instrument [Line Items]
Margin basis point	2.50%
Less than 33% | Prime | Revolving Credit Facility
Debt Instrument [Line Items]
Margin basis point	1.50%
Less than 33% | Libor | Revolving Credit Facility
Debt Instrument [Line Items]
Margin basis point	2.75%
Minimum | Greater than 66% | Revolving Credit Facility
Debt Instrument [Line Items]
Quarterly Average Availability Percentage	66.00%
Minimum | Between 33% and 66% | Revolving Credit Facility
Debt Instrument [Line Items]
Quarterly Average Availability Percentage	33.00%
Maximum | Between 33% and 66% | Revolving Credit Facility
Debt Instrument [Line Items]
Quarterly Average Availability Percentage	66.00%
Maximum | Less than 33% | Revolving Credit Facility
Debt Instrument [Line Items]
Quarterly Average Availability Percentage	33.00%

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Unit-Based Compensation (Details) (Nonvested Phantom Units, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Nonvested Phantom Units
Number of Phantom Units
Nonvested at beginning of period	562,696	105,492	57,493
Granted	616,997	640,875	138,490
Vested	(286,976)	(183,671)	(90,491)
Forfeited	(56,790)	0	0
Nonvested at end of period	835,927	562,696	105,492
Weighted-Average Grant Date Fair Value
Nonvested at beginning of period	$ 19.77	$ 17.68	$ 12.42
Granted	$ 26.69	$ 20.26	$ 20.11
Vested	$ 21.16	$ 20.29	$ 18.05
Forfeited	$ 20.00	$ 0	$ 0
Nonvested at end of period	$ 27.57	$ 19.77	$ 17.68

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Long-Term Debt - Capital Leases (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Equipment acquired under capital lease	$ 5,771	$ 0	$ 0
Property, plant and equipment, gross	1,284,747	1,073,782
Accumulated depreciation	297,872	231,681
Capital Leases, Future Minimum Payments
2013	1,189
2014	805
2015	661
2016	661
2017	661
Thereafter	4,789
Total minimum lease payments	8,766
Less amount representing interest	3,254
Capital lease obligations	5,512
Less obligations due within one year	771
Long-term capital lease obligations	4,741
Assets under capital leases
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	11,071	4,201
Accumulated depreciation	$ 4,251	$ 3,221

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Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Jan. 01, 2013	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Quarterly Financial Information Disclosure [Abstract]
Sales	$ 1,220,882	$ 1,179,818	$ 1,086,996	$ 1,169,586	$ 1,018,133	$ 777,780	$ 733,770	$ 605,240	$ 4,657,282	$ 3,134,923	$ 2,190,752
Gross profit	141,719	158,406	128,808	84,244	80,100	96,601	50,565	46,864	513,177	274,130	198,749
Net income	45,736	42,416	65,662	51,923	26,872	19,614	(7,651)	4,201	205,737	43,036	16,701
Net income available to limited partners	$ 42,392	$ 39,669	$ 62,875	$ 50,054	$ 26,052	$ 19,182	$ (7,498)	$ 4,117	$ 194,990	$ 41,853	$ 16,367
Limited partners’ interest basic net income per unit	0.73	0.69	1.14	0.97					3.51	0.98	0.46
Limited partners’ interest diluted net income per unit	0.73	0.69	1.14	0.97					3.50	0.98	0.46
Limited partners’ interest basic and diluted net income (loss) per unit					$ 0.50	$ 0.46	$ (0.19)	$ 0.11		$ 0.98
Weighted average limited partner units outstanding — basic	57,746,000	57,746,000	55,028,000	51,685,000	51,589,000	41,828,000	39,886,000	36,875,000	55,559,000	42,599,000	35,335,000
Weighted average limited partner units outstanding — diluted	57,898,000	57,826,000	55,074,000	51,736,000	51,600,000	41,837,000	39,886,000	36,895,000	55,677,000	42,644,000	35,351,000

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Long-Term Debt (Details Textual) (USD $)	12 Months Ended						12 Months Ended		1 Months Ended	12 Months Ended	0 Months Ended	12 Months Ended		12 Months Ended					12 Months Ended													0 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012 D	Jun. 29, 2012 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012	Jun. 21, 2012 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012	Dec. 31, 2012 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012 Maximum	Dec. 31, 2012 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the year ended December 31, 2012 Minimum	Sep. 30, 2011 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012	Dec. 31, 2012 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012	Apr. 27, 2011 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012 Restructuring of Long-term debt	Dec. 31, 2012 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012 Restructuring of Long-term debt	Apr. 21, 2011 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012 Restructuring of Long-term debt	Dec. 31, 2012 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012 Superior Acquisition	Apr. 21, 2012 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012 Superior Acquisition	Sep. 19, 2011 Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.91% for the year ended December 31, 2012 Superior Acquisition	Dec. 31, 2012 Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	Dec. 31, 2011 Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	Dec. 31, 2012 Senior secured revolving credit facility	Dec. 31, 2012 Senior secured revolving credit facility Maximum	Dec. 31, 2012 Senior secured revolving credit facility Minimum	Apr. 30, 2011 Prior term loan	Dec. 31, 2012 Estimate of Fair Value, Fair Value Disclosure Senior secured revolving credit facility	Dec. 31, 2011 Estimate of Fair Value, Fair Value Disclosure Senior secured revolving credit facility	Dec. 31, 2012 Prime	Dec. 31, 2012 Libor	Apr. 21, 2011 Libor Prior term loan	Apr. 21, 2011 Base Rate Prior term loan	Apr. 30, 2011 Letter of Credit [Member] Prior term loan	Dec. 31, 2012 Senior secured revolving credit facility	Dec. 31, 2011 Senior secured revolving credit facility	Apr. 21, 2011 Senior secured revolving credit facility Prior term loan	Apr. 30, 2011 Senior secured revolving credit facility Prior term loan
Long-Term Debt (Textual) [Abstract]
Senior secured revolving agreement due date				Aug. 01, 2020				Jun. 28, 2013				May 01, 2019		May 01, 2019					Jun. 01, 2016
Long-term debt interest payment period				semiannually						semiannually									monthly
Senior notes					$ 275,000,000								$ 400,000,000			$ 200,000,000
Senior notes sold on												Apr. 21, 2011		Sep. 19, 2011
Debt instrument percentage of discount price						9825.00%									9300.00%
Net proceeds from sales of Notes				262,565,000					180,296,000		388,999,000
Redemption percentage				35.00%						35.00%
Redemption price				109.625%						109.375%
Minimum percentage of Notes 2020 outstanding after August 1, 2015				65.00%						65.00%
Redemption occurs within days of the date of the closing of such public or private equity offering				120						120
Holder of the 2020 Notes will have the right to require that the Company repurchase all or portion in cash purchase price equal to in percentage of the principle, plus any accrued and unpaid interest				101.00%						101.00%
Exchange offer registration statement to become effective days							180 days
Reasonable best efforts to complete the exchange offer not later than in days				60
Company fails to satisfy obligations on timely basis, the annual interest borne by the 2020 Notes will be increased by percentage per annum							1.00%
Margin basis point																									0.00%	2.25%	0.00%	3.00%
Debt extinguishment costs	0	(15,130,000)	0
Customary letter of credit fee, including a fronting fee per annum on the stated amount of each outstanding letter of credit																			0.125%
Unutilized commitments fee to the lender under the revolving credit facility																				0.50%	0.375%
Available for additional borrowings based on specified availability limitations																														355,091,000	340,715,000
Financial covenant availability under the revolving credit facility falls below the greater																			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.
Percentage of lesser of the borrowing agreement																			12.50%
Covenant compliance required cash available																			46,364,000
Fixed charge coverage ratio																				1	1
Capital lease and other obligations																	5,512,000	786,000
Senior secured revolving credit facility	850,000,000	850,000,000																	577,450,000			435,000,000								680,000,000
Line of Credit Facility, Current Borrowing Capacity																													50,000,000				385,000,000
Repayments of Debt																																369,486
Line of Credit Facility, Amount Outstanding																							$ 0	$ 0
Long-Term Debt (Additional Textual) [Abstract]
Current interest rate of senior secured revolving credit facility	prime plus a basis points margin or LIBOR plus a basis points margin

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Employee Benefit Plans - Amounts Recognized in Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Total recognized in other comprehensive loss (income)	$ 2,959	$ 3,714	$ 144
Classified in accumulated other comprehensive loss	(11,526)	(8,567)
Amounts that will be amortized from accumulated other comprehensive income in next fiscal year	(817)
Pension Plans, Defined Benefit
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net loss	4,216	3,334	695
New prior service cost	0	0
Amortization or curtailment recognition of prior service credit	(578)	(281)	(274)
Amortization or curtailment recognition of prior service credit	0	0	0
Total recognized in other comprehensive loss (income)	3,638	3,053	421
Total recognized in net periodic benefit and other comprehensive loss (income)	5,800	3,921	1,081
Classified in accumulated other comprehensive loss	11,927	8,289
Future amortization of net prior service credit	8
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net loss	106	624	30
New prior service cost	(81)	0	(345)
Amortization or curtailment recognition of prior service credit	(820)	2	3
Amortization or curtailment recognition of prior service credit	116	35	35
Total recognized in other comprehensive loss (income)	(679)	661	(277)
Total recognized in net periodic benefit and other comprehensive loss (income)	(7,377)	834	(292)
Classified in accumulated other comprehensive loss	(401)	278
Future amortization of net prior service credit	$ (35)

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Schedule of Changes in Projected Benefit Obligations

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,
	2012						2011
	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	$	55,265		$	7,734		$	24,761		$	446
Projected benefit obligation attributable to acquisitions	4,900			—			26,218			6,477
Service cost	1,130			287			296			114
Interest cost	2,376			185			1,638			96
Plan curtailments	(3,685		)	(7,873		)	—			—
Benefits paid	(2,607		)	(80		)	(1,162		)	(81		)
Actuarial loss	7,897			106			3,554			624
Administrative expense	(40		)	—			(40		)	—
Plan amendments	—			(81		)	—			—
Employee contributions	—			51			—			58
Benefit obligation at end of year	$	65,236		$	329		$	55,265		$	7,734
Change in plan assets:
Fair value of plan assets at beginning of year	$	36,042		$	—		$	16,039		$	—
Fair value of pension assets attributable to acquisitions	3,178			—			17,718			—
Benefit payments	(2,607		)	(80		)	(1,162		)	(81		)
Actual return on assets	1,917			—			1,568			—
Administrative expense	(40		)	—			(40		)	—
Employee contributions	—			51			—			58
Employer contribution	3,076			29			1,919			23
Fair value of plan assets at end of year	$	41,566		$	—		$	36,042		$	—
Funded status — benefit obligation in excess of plan assets	$	(23,670	)	$	(329	)	$	(19,223	)	$	(7,734	)
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	$	(23,670	)	$	(329	)	$	(19,223	)	$	(7,734	)
Prior service credit	—			(240		)	—			(275		)
Unrecognized net actuarial loss (gain)	11,927			(161		)	8,289			553
Accumulated other comprehensive (income) loss	11,927			(401		)	8,289			278
Net amount recognized at end of year	$	(11,743	)	$	(730	)	$	(10,934	)	$	(7,456	)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets

Selected information for the Company’s Pension Plan with an accumulated benefit obligation in excess of plan assets were as follows:

	Year Ended December 31,
	2012		2011
Projected benefit obligation	$	65,236	$	55,265
Accumulated benefit obligation	$	63,429	$	52,543
Fair value of plan assets	$	41,566	$	36,042

Components of net periodic pension and other post retirement benefits cost

The components of net periodic pension cost and other post retirement benefits cost 2012, 2011 and 2010 were as follows:

	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011			2010
Service cost	$	1,130		$	296		$	84		$	287		$	114		$	—
Interest cost	2,376			1,638			1,336			185			96			23
Expected return on assets	(1,704		)	(1,347		)	(1,034		)	—			—			—
Amortization of net (gain) loss	578			281			274			(7		)	(2		)	(3		)
Amortization of prior service cost	—			—			—			(39		)	(35		)	(35		)
Curtailment gain recognized	(218		)	—			—			(6,983		)	—			—
Settlement gain recognized	—			—			—			(141		)	—			—
Net periodic pension cost	$	2,162		$	868		$	660		$	(6,698	)	$	173		$	(15	)

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)

The components of changes recognized in other comprehensive income for the Pension Plan and Other Plan for 2012, 2011 and 2010 were as follows:

	Pension Plan									Other Plan
	Year Ended December 31,									Year Ended December 31,
	2012			2011			2010			2012			2011		2010
Changes in plan assets and benefit obligations recognized in other comprehensive income:
Net loss	$	4,216		$	3,334		$	695		$	106		$	624	$	30
New prior service cost	—			—						(81		)	—		(345		)
Amounts recognized as a component of net periodic benefit cost:
Amortization or settlement recognition of net (loss) gain	(578		)	(281		)	(274		)	(820		)	2		3
Amortization or curtailment recognition of prior service credit	—			—			—			116			35		35
Total recognized in other comprehensive loss (income)	$	3,638		$	3,053		$	421		$	(679	)	$	661	$	(277	)
Total recognized in net periodic benefit and other comprehensive loss (income)	$	5,800		$	3,921		$	1,081		$	(7,377	)	$	834	$	(292	)

Schedule of Assumptions Used

The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2012 and 2011 were as follows:

	Benefit Obligations Assumptions
	2012		2011
Pension Plan:
Discount rate	3.83	%	4.59	%
Rate of compensation increase for Penreco Pension Plan	N/A		N/A
Rate of compensation increase for Superior Pension Plan	N/A		3.75	%
Rate of compensation increase for Montana Pension Plan	3.00	%	N/A
Other Plan:
Discount rate for Penreco Other Plan	3.33	%	4.04	%
Discount rate for Superior Other Plan	N/A		4.65	%
Immediate trend rate for Penreco Other Plan (1)	7.70	%	8.00	%
Immediate trend rate for Superior Other Plan (2)	N/A		8.00	%
Ultimate trend rate for Penreco Other Plan (1)	4.50	%	4.50	%
Ultimate trend rate for Superior Other Plan (2)	N/A		4.50	%
Year that the rate reaches ultimate trend rate for Penreco Other Plan (1)	2029		2029
Year that the rate reaches ultimate trend rate for Superior Other Plan (2)	N/A		2029

(1) For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% in 2029 for the Penreco Other Plan and remain at that level thereafter.

(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% in 2029 for the Superior Other Plan and remain at that level thereafter. Effective July 1, 2012, the Company amended the Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012.

The significant weighted average assumptions used to determine the net periodic benefit cost for the years ended December 31, 2012 and 2011 were as follows:

	Net Periodic Benefit Cost Assumptions
	2012		2011		2010
Pension Plan:
Discount rate for Penreco Pension Plan	4.63	%	5.50	%	6.04	%
Discount rate for Superior Pension Plan	4.55	%	4.71	%	N/A
Discount rate for Montana Pension Plan	3.89	%	N/A		N/A
Expected return on plan assets for Penreco Pension Plan (1)	6.00	%	6.50	%	7.50	%
Expected return on plan assets for Superior Pension Plan (1)	3.00	%	6.50	%	N/A
Expected return on plan assets for Montana Pension Plan (1)	6.00	%	N/A		N/A
Rate of compensation increase for Penreco Pension Plan	N/A		N/A		N/A
Rate of compensation increase for Superior Pension Plan	3.75	%	3.75	%	N/A
Rate of compensation increase for Montana Pension Plan	3.00	%	N/A		N/A
Other Plan:
Discount rate for Penreco Other Plan	4.04	%	4.54	%	5.55	%
Discount rate for Superior Other Plan	4.65	%	4.82	%	N/A
Immediate trend rate (2)	8.00	%	8.20	%	8.40	%
Ultimate trend rate for Penreco Other Plan (2)	4.50	%	4.50	%	4.50	%
Ultimate trend rate for Superior Other Plan (2)	4.50	%	5.00	%	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)	2029		2020		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 2012. 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.

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

An increase or decrease by one percentage point in the assumed healthcare cost trend rates would have the following effect on the post retirement benefit obligation and service and interest cost components of benefit costs for the Other Plan as of December 31, 2012:

	1% Point Increase		1% Point Decrease
Increase (decrease) in:
Effect on total of service and interest cost components of benefit costs	$	110	$	(85	)
Effect on post retirement benefit obligation	$	5	$	(4	)

Schedule of Allocation of Plan Assets

The Company’s Pension Plan asset allocations, as of December 31, 2012 and 2011 by asset category, are as follows:

	2012		2011
	Pension Benefits		Pension Benefits
Cash and cash equivalents (1)	47	%	62	%
Equity	14	%	11	%
Foreign equities	5	%	2	%
Fixed income	20	%	18	%
Balanced fund	7	%	—	%
Commingled fund	7	%	7	%
	100	%	100	%

(1) The Superior Pension Plan assets are included in cash and cash equivalents and such assets will be invested in 2013 based upon the current investment policy.

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	%

Schedule of Pension Plan assets measured at fair value

The Company’s Pension Plan assets measured at fair value at December 31, 2012 and 2011 were as follows:

	Fair Value of Pension Assets at December 31,
	2012				2011
	Level 1		Level 2		Level 1		Level 2
Cash and cash equivalents	$	19,295	$	—	$	22,243	$	—
Equity	5,900		—		4,000		—
Foreign equities	2,268		—		691		—
Commingled fund	—		2,731		—		2,462
Balanced fund	2,961		—		—		—
Fixed income	8,411		—		6,646		—
	$	38,835	$	2,731	$	33,580	$	2,462

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Acquisitions (Details Textual) (USD $)	12 Months Ended			12 Months Ended				1 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Pro forma	Dec. 31, 2011 Pro forma	Dec. 31, 2012 9 3/8% Senior Notes	Dec. 31, 2012 9 5/8% Senior Notes	Sep. 30, 2011 Superior Acquisition	Dec. 31, 2012 Superior Acquisition	Dec. 31, 2012 Missouri Acquisition	Dec. 31, 2012 TruSouth Acquisition	Dec. 31, 2012 Royal Purple Acquisition	Dec. 31, 2012 Montana Acquisition
Business Combination (Textual) [Abstract]
Total purchase price									$ 413,173,000	$ 19,575,000	$ 26,827,000	$ 331,239,000
Proceeds from public offering of common units, net								193,538,000
Business acquisition cost of acquired entity									2,717,000	505,000	179,000	426,000
Goodwill										1,478,000	392,000	109,165,000	27,643,000
Adjustments to increase intangible amortization				10,864,000	20,300,000
Total purchase price, net of cash acquired													191,550,000
Income tax liability included in purchase													27,643,000
Interest at a fixed rate						937.50%	962.50%
Goodwill	187,013,000	48,335,000	48,335,000
Acquisition related costs													3,267,000
Acquisitions	$ 138,678,000	$ 0

XML

Segments and Related Information

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Segments and Related Information

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, synthetic lubricants, asphalt and other by-products. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The specialty products segment also blends and markets through the Company’s brand Royal Purple. 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, Canada, Idaho, Iowa, Louisiana, Michigan, Minnesota, Montana, North Dakota, South Dakota, 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 and Montana Acquisitions have been included since the date of acquisition, September 30, 2011 and October 1, 2012, respectively. The assets and results of operations from such assets acquired as a result of the Missouri, TruSouth and Royal Purple Acquisitions have been included in the specialty products segment since their dates of acquisition, January 3, 2012, January 6, 2012 and July 3, 2012, respectively.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2. 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, 2012	Specialty Products		Fuel Products			Combined Segments		Eliminations			Consolidated Total
Sales:
External customers	$	2,231,602	$	2,425,680		$	4,657,282	$	—		$	4,657,282
Intersegment sales	1,153,095		73,545			1,226,640		(1,226,640		)	—
Total sales	$	3,384,697	$	2,499,225		$	5,883,922	$	(1,226,640	)	$	4,657,282
Depreciation and amortization	84,648		20,377			105,025		—			105,025
Operating income	125,710		160,218			285,928		—			285,928
Reconciling items to net income:
Interest expense											(85,573		)
Gain on derivative instruments											5,665
Other											470
Income tax expense											(753		)
Net income											$	205,737
Capital expenditures	$	41,686	$	15,367		$	57,053	$	—		$	57,053
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		)
Loss on derivative instruments											(23,547		)
Other											(147		)
Income tax expense											(598		)
Net income											$	16,701
Capital expenditures	$	35,001	$	—		$	35,001	$	—		$	35,001

	December 31,
	2012		2011
Segment assets:
Specialty products	$	1,569,796	$	1,159,040
Fuel products	683,249		573,018
Total assets	$	2,253,045	$	1,732,058

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2012, 2011 and 2010. All of the Company’s long-lived assets are domestically located.

c. Product Information

The Company offers specialty products primarily in six general categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products, fuels and asphalt and other 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,
	2012				2011				2010
Specialty products:
Lubricating oils	$	1,007,928	22	%	$	947,798	30	%	$	759,701	35	%
Solvents	491,114		11	%	495,934		16	%	396,894		18	%
Waxes	142,765		3	%	143,111		5	%	124,964		6	%
Packaged and synthetic specialty products	161,673		3	%	—		—	%	—		—	%
Fuels	2,029		—	%	3,432		—	%	5,507		—	%
Asphalt and other by-products	426,093		9	%	217,351		7	%	121,806		5	%
Total	2,231,602		48	%	1,807,626		58	%	1,408,872		64	%
Fuel products:
Gasoline	1,174,859		25	%	619,630		20	%	304,544		14	%
Diesel	941,047		20	%	513,334		16	%	330,756		15	%
Jet fuel	183,953		4	%	148,036		5	%	135,796		6	%
Heavy fuel oils and other	125,821		3	%	46,297		1	%	10,784		1	%
Total	2,425,680		52	%	1,327,297		42	%	781,880		36	%
Consolidated sales	$	4,657,282	100	%	$	3,134,923	100	%	$	2,190,752	100	%

d. Major Customers

During the years ended December 31, 2012, 2011 and 2010, the Company had no customer that represented 10% or greater of consolidated sales.

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2012

Business Acquisition [Line Items]

Unaudited pro forma financial information

Results of Sales and Earnings

The following financial information reflects the results of sales and operating income of the Superior Acquisition that are included in the consolidated statements of operations for the year ended December 31, 2011 and the results of sales and operating income of the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions that are included in the consolidated statements of operations for the year ended December 31, 2012:

	Year Ended December 31,
	2012		2011
Sales	$	1,670,899	$	341,152
Operating income	$	186,406	$	17,963

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of the Company as if the Superior, Royal Purple and Montana Acquisitions had taken place on January 1, 2011.

	Year Ended December 31,
	2012		2011
Sales	$	5,064,795	$	4,804,528
Net income	$	234,601	$	103,114
Limited partners’ interest net income per unit — basic	$	3.86	$	1.75
Limited partners’ interest net income per unit — diluted	$	3.85	$	1.75

Superior Acquisition

Business Acquisition [Line Items]

Allocation of aggregate purchase price to assets acquired and liabilities assumed

The 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

Missouri Acquisition

Business Acquisition [Line Items]

Allocation of aggregate purchase price to assets acquired and liabilities assumed

The allocation of the aggregate purchase price to assets acquired is as follows:

	Allocation of Purchase Price
Inventories	$	2,775
Property, plant and equipment	9,955
Goodwill	1,478
Other intangible assets	5,367
Total purchase price	$	19,575

Components of intangible asset

The component of the intangible asset listed in the table above as of January 3, 2012, based upon a third party appraisal, was as follows:

	Amount		Life (Years)
Customer relationships	$	5,367	20

TruSouth Acquisition

Business Acquisition [Line Items]

Allocation of aggregate purchase price to assets acquired and liabilities assumed

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

	Allocation of Purchase Price
Accounts receivable	$	5,217
Inventories	7,976
Prepaid expenses and other current assets	272
Property, plant and equipment	17,682
Goodwill	392
Other intangible assets	2,545
Accounts payable	(2,672		)
Accrued salaries, wages and benefits	(151		)
Other current liabilities	(918		)
Long-term debt	(3,516		)
Total purchase price, net of cash acquired	$	26,827

Components of intangible asset

The components of intangible assets listed in the table above as of January 6, 2012, based upon a third party appraisal, were as follows:

	Amount		Life (Years)
Customer relationships	$	1,775	16
Tradenames	675		9
Non-competition agreements	95		2
Total	$	2,545
Weighted average amortization period			14

Royal Purple Acquisition

Business Acquisition [Line Items]

Allocation of aggregate purchase price to assets acquired and liabilities assumed

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

	Allocation of Purchase Price
Accounts receivable	$	15,159
Inventories	19,299
Prepaid expenses and other current assets	236
Deposits	13
Property, plant and equipment	10,579
Goodwill	109,165
Other intangible assets	183,398
Accounts payable	(3,804		)
Accrued salaries, wages and benefits	(1,698		)
Other taxes payable	(198		)
Other current liabilities	(910		)
Total purchase price, net of cash acquired	$	331,239

Components of intangible asset

The components of intangible assets listed in the table above as of July 3, 2012, based upon a third party appraisal, were as follows:

	Amount		Life (Years)
Customer relationships	$	118,683	20
Tradenames - Royal Purple retail	14,790		Indefinite
Tradenames	5,746		10
Trade secrets	44,179		12
Total	$	183,398
Weighted average amortization period			18

Montana Acquisition

Business Acquisition [Line Items]

Allocation of aggregate purchase price to assets acquired and liabilities assumed

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

	Allocation of Purchase Price
Accounts receivable	$	28,973
Inventories	43,682
Prepaid expenses and other current assets	23,105
Deposits	256
Property, plant and equipment	125,472
Goodwill	27,643
Other noncurrent assets, net	327
Accounts payable	(8,402		)
Accrued salaries, wages and benefits	(1,448		)
Deferred income tax liability	(27,643		)
Accrued income taxes payable	(15,571		)
Other taxes payable	(3,015		)
Other current liabilities	(107		)
Pension and postretirement benefit obligations	$	(1,722	)
Total purchase price, net of cash acquired	$	191,550

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Employee Benefit Plans - Pension Assets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 38,835	$ 33,580
Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	2,731	2,462
Cash and cash equivalents | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	19,295	22,243
Cash and cash equivalents | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0	0
Equity [Member] | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	5,900	4,000
Equity [Member] | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0	0
Foreign equities [Member] | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	2,268	691
Foreign equities [Member] | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0	0
Commingled fund | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0	0
Commingled fund | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	2,731	2,462
Balanced fund | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	2,961	0
Balanced fund | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0	0
Fixed income | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	8,411	6,646
Fixed income | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 0	$ 0

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Acquisitions (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Result of sales and operating income
Operating income	$ 285,928	$ 125,292	$ 71,490
Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	1,670,899	341,152
Result of sales and operating income
Operating income	$ 186,406	$ 17,963

XML

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	$ 1,284,747	$ 1,073,782
Less accumulated depreciation	(297,872)	(231,681)
Property, plant and equipment, net	986,875	842,101
Capitalized Computer Software, Net	15,007	6,037
Interest expense incurred	86,327	49,339	30,886
Capitalized interest	754	592	389
Depreciation expense	74,292	55,536	51,365
Land
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	11,229	8,857
Building and improvements
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	28,063	19,729
Building and improvements | Minimum
Property, Plant and Equipment, Net, by Type
Depreciable lives	10 years
Building and improvements | Maximum
Property, Plant and Equipment, Net, by Type
Depreciable lives	40 years
Machinery and equipment
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	1,172,970	1,012,318
Machinery and equipment | Minimum
Property, Plant and Equipment, Net, by Type
Depreciable lives	10 years
Machinery and equipment | Maximum
Property, Plant and Equipment, Net, by Type
Depreciable lives	20 years
Furniture and fixtures
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	7,624	5,732
Furniture and fixtures | Minimum
Property, Plant and Equipment, Net, by Type
Depreciable lives	5 years
Furniture and fixtures | Maximum
Property, Plant and Equipment, Net, by Type
Depreciable lives	10 years
Assets under capital leases
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	11,071	4,201
Less accumulated depreciation	(4,251)	(3,221)
Depreciation expense	1,030	1,050	1,050
Assets under capital leases | Minimum
Property, Plant and Equipment, Net, by Type
Depreciable lives	1 year
Assets under capital leases | Maximum
Property, Plant and Equipment, Net, by Type
Depreciable lives	4 years
Construction-in-progress
Property, Plant and Equipment, Net, by Type
Construction in Progress, Gross	53,790	22,945
Software developed or obtained
Property, Plant and Equipment, Net, by Type
Depreciable lives	3 years
Amortization	$ 967	$ 416	$ 262

XML

Consolidated Statements of Comprehensive Income (Loss) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Other Comprehensive Income [Abstract]
Net income	$ 205,737	$ 43,036	$ 16,701
Cash flow hedges:
Cash flow hedge (income) loss reclassified to net income	154,085	104,020	(11,104)
Change in fair value of cash flow hedges	(215,132)	(34,160)	(29,015)
Defined benefit pension and retiree health benefit plans	(2,959)	(3,714)	(144)
Total other comprehensive income (loss)	(64,006)	66,146	(40,263)
Comprehensive income (loss) attributable to partners’ capital	$ 141,731	$ 109,182	$ (23,562)

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Employee Benefit Plans - Defined Benefit Plans (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain recognized	$ 218	$ 0	$ 0
Employer contribution	3,076	1,919
Estimated future employer contributions in next fiscal year	4,402
Other Post Retirement Employee Benefits
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain recognized	6,983	0	0
Employer contribution	29	23
Estimated future employer contributions in next fiscal year	59
Pension Plan | Domestic Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employee's compensation period used in benefit calculation	60 months
Montana Plan | Domestic Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employee's compensation period used in benefit calculation	36 months
Superior Plan | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain recognized	218
Superior Plan | Other Post Retirement Employee Benefits
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain recognized	$ 6,983

XML

Acquisitions

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Acquisitions

Acquisitions

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 but excluding the over-allotment option exercised), (ii) net proceeds of $180,296 from the Company’s September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings under the Company’s revolving credit facility. The Company acquired the following assets:

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

• 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.

The Superior refinery produces gasoline, diesel, asphalt and heavy fuel oils 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. 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 general and administrative expenses in the consolidated statements of operations.

The 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

Missouri Acquisition

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., including a manufacturing facility located in Louisiana, Missouri for aggregate consideration of approximately $19,575 (“Missouri Acquisition”). The Missouri Acquisition was financed with borrowings under the Company’s revolving credit facility and cash on hand. The Company believes the Missouri Acquisition provides greater diversity to its specialty products segment. The assets acquired and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Missouri Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $505 which are reflected in general and administrative expenses in the consolidated statements of operations.

The Company recorded $1,478 of goodwill as a result of the Missouri Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired is as follows:

	Allocation of Purchase Price
Inventories	$	2,775
Property, plant and equipment	9,955
Goodwill	1,478
Other intangible assets	5,367
Total purchase price	$	19,575

The component of the intangible asset listed in the table above as of January 3, 2012, based upon a third party appraisal, was as follows:

	Amount		Life (Years)
Customer relationships	$	5,367	20

TruSouth Acquisition

On January 6, 2012, the Company completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC (“TruSouth”), a specialty petroleum packaging and distribution company located in Shreveport, Louisiana for aggregate consideration of approximately $26,827, net of cash acquired (“TruSouth Acquisition”). The TruSouth Acquisition 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. The Company believes the TruSouth Acquisition provides greater diversity to its specialty products segment. The assets acquired and liabilities assumed have been included in the Company’s consolidated balance sheets and results of operations have been included in the Company’s consolidated statements of operations since the date of acquisition. In connection with the TruSouth Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of $179 which are reflected in general and administrative expenses in the consolidated statements of operations.

The Company recorded $392 of goodwill as a result of the TruSouth Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:

	Allocation of Purchase Price
Accounts receivable	$	5,217
Inventories	7,976
Prepaid expenses and other current assets	272
Property, plant and equipment	17,682
Goodwill	392
Other intangible assets	2,545
Accounts payable	(2,672		)
Accrued salaries, wages and benefits	(151		)
Other current liabilities	(918		)
Long-term debt	(3,516		)
Total purchase price, net of cash acquired	$	26,827

The components of intangible assets listed in the table above as of January 6, 2012, based upon a third party appraisal, were as follows:

	Amount		Life (Years)
Customer relationships	$	1,775	16
Tradenames	675		9
Non-competition agreements	95		2
Total	$	2,545
Weighted average amortization period			14

Royal Purple Acquisition

On July 3, 2012, the Company completed the acquisition of Royal Purple, Inc. (“Royal Purple”), a Texas corporation which was converted into a Delaware limited liability company at closing, for aggregate consideration of approximately $331,239, net of cash acquired (“Royal Purple Acquisition”). Royal Purple is a leading independent formulator and marketer of premium industrial and consumer lubricants to a diverse customer base across several large markets including oil and gas, chemicals and refining, power generation, manufacturing and transportation, food and drug manufacturing and automotive aftermarket. The Royal Purple Acquisition was financed with net proceeds of $262,565 from the Company’s June 2012 private placement of 9 5/8% senior notes due August 1, 2020 and cash on hand. The Company believes the Royal Purple Acquisition increases its position in the specialty lubricants market, expands its geographic reach, increases its asset diversity and enhances its specialty products segment. The assets acquired and liabilities assumed and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Royal Purple Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $426 which are reflected in general and administrative expenses in the consolidated statements of operations.

The Company recorded $109,165 of goodwill as a result of the Royal Purple Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment.

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

	Allocation of Purchase Price
Accounts receivable	$	15,159
Inventories	19,299
Prepaid expenses and other current assets	236
Deposits	13
Property, plant and equipment	10,579
Goodwill	109,165
Other intangible assets	183,398
Accounts payable	(3,804		)
Accrued salaries, wages and benefits	(1,698		)
Other taxes payable	(198		)
Other current liabilities	(910		)
Total purchase price, net of cash acquired	$	331,239

The components of intangible assets listed in the table above as of July 3, 2012, based upon a third party appraisal, were as follows:

	Amount		Life (Years)
Customer relationships	$	118,683	20
Tradenames - Royal Purple retail	14,790		Indefinite
Tradenames	5,746		10
Trade secrets	44,179		12
Total	$	183,398
Weighted average amortization period			18

Montana Acquisition

On October 1, 2012, the Company completed the acquisition from Connacher Oil and Gas Limited (“Connacher”) of all the shares of common stock of Montana Refining Company, Inc. (“Montana”) and an insignificant affiliated company for aggregate consideration of approximately $191,550, net of cash acquired and excluding certain purchase price adjustments (“Montana Acquisition”). Montana produces gasoline, diesel, jet fuel and asphalt, which are marketed primarily into local markets in Washington, Montana, Idaho and Alberta, Canada. The Montana Acquisition was funded primarily with cash on hand with the balance through borrowings under the Company’s revolving credit facility. The Company believes the Montana Acquisition further diversifies its crude oil feedstock slate, operating asset base and geographic presence. The assets acquired and liabilities assumed and results of operations have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. In connection with the Montana Acquisition, during the year ended December 31, 2012, the Company incurred acquisition costs of approximately $3,267 which are reflected in general and administrative expenses in the consolidated statements of operations.

Immediately after closing the Montana Acquisition, the Company converted Montana Refining Company, Inc. into a Delaware limited liability company, Calumet Montana Refining, LLC. This conversion resulted in the recognition of a current income tax liability, with an expected payment of income taxes in early 2013, of approximately $27,643, which was offset by the derecognition of a deferred tax liability for a comparable amount which was assumed in connection with the acquisition.

The Company recorded $27,643 of goodwill as a result of the Montana Acquisition, all of which was recorded within the Company’s fuel products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its fuel products segment.

The Montana Acquisition purchase price allocation has not yet been finalized due to the timing of the closing of the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. The preliminary allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows:

	Allocation of Purchase Price
Accounts receivable	$	28,973
Inventories	43,682
Prepaid expenses and other current assets	23,105
Deposits	256
Property, plant and equipment	125,472
Goodwill	27,643
Other noncurrent assets, net	327
Accounts payable	(8,402		)
Accrued salaries, wages and benefits	(1,448		)
Deferred income tax liability	(27,643		)
Accrued income taxes payable	(15,571		)
Other taxes payable	(3,015		)
Other current liabilities	(107		)
Pension and postretirement benefit obligations	$	(1,722	)
Total purchase price, net of cash acquired	$	191,550

Results of Sales and Earnings

The following financial information reflects the results of sales and operating income of the Superior Acquisition that are included in the consolidated statements of operations for the year ended December 31, 2011 and the results of sales and operating income of the Superior, Missouri, TruSouth, Royal Purple and Montana Acquisitions that are included in the consolidated statements of operations for the year ended December 31, 2012:

	Year Ended December 31,
	2012		2011
Sales	$	1,670,899	$	341,152
Operating income	$	186,406	$	17,963

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of the Company as if the Superior, Royal Purple and Montana Acquisitions had taken place on January 1, 2011.

	Year Ended December 31,
	2012		2011
Sales	$	5,064,795	$	4,804,528
Net income	$	234,601	$	103,114
Limited partners’ interest net income per unit — basic	$	3.86	$	1.75
Limited partners’ interest net income per unit — diluted	$	3.85	$	1.75

The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Superior, Royal Purple and Montana Acquisitions. 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.

For the year ended December 31, 2012, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2020 Notes (defined below). The unaudited pro forma financial information reflects adjustments to increase amortization expense by $10,864 as a result of recording Royal Purple’s intangible assets.

For the year ended December 31, 2011, the unaudited pro forma financial information reflects adjustments to increase interest expense as a result of the issuance of the 2019 Notes and 2020 Notes (defined below), amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund a portion of the Superior and Montana Acquisitions and the repayment of borrowings under the prior term loan from the net proceeds of the 2019 Notes issued in April 2011. The unaudited pro forma financial information also reflects adjustments to increase amortization expense by $20,300 as a result of recording Royal Purple’s intangible assets.

Fair Value Measurements of Acquisitions

The fair value of the property, plant and equipment and intangible assets from acquisitions are based upon the discounted cash flow method that involves inputs that are not observable in the market (Level 3). Goodwill assigned represents the amount of consideration transferred in excess of the fair value assigned to individual assets acquired and liabilities assumed.

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Commitments and Contingencies - Environmental (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Loss Contingencies [Line Items]
Estimates costs of equipment upgrades and conduct other discrete	$ 3,000
Indemnification liability maximum	22,000
Required minimum liability	6,600
Environmental settlement	Dec. 23, 2010
Settlement agreement with the LDEQ	Jan. 31, 2012
Specified environmental liabilities first	5,000
Maximum
Loss Contingencies [Line Items]
Capital expenditures	6,000
Environmental remediation expense	6,000
Specified environmental liabilities first required to contribute up to	1,000
Minimum
Loss Contingencies [Line Items]
Capital expenditures	2,000
Environmental remediation expense	2,000
Global Settlement
Loss Contingencies [Line Items]
Settlement agreement, environmental studies period	3 years
WDNR-Superior
Loss Contingencies [Line Items]
Capital expenditures	2,379	2,270
Environmental remediation expense	2,379	2,270
LDEQ-Shreveport
Loss Contingencies [Line Items]
Capital expenditures	4,200	4,000
Environmental remediation expense	4,200	4,000
Enviornmental-Cotton Valley
Loss Contingencies [Line Items]
Capital expenditures	395	338	541
Environmental remediation expense	$ 395	$ 338	$ 541

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Fair Value Measurements (Details Textual) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Fair Value Measurements (Textual) [Abstract]
Asset was reduced result of applying the applicable credit default spread	$ 100	$ 1,297
Liabilities was reduced result of applying the applicable credit default spread	$ 185	$ 165
Reviews for goodwill impairment annually on	Oct. 01, 2012

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Derivatives (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	$ (215,132)	$ (34,160)
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	154,085	104,020
Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	36,993	(13,297)
Derivative instruments not designated as hedges | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	(3,310)	(2,109)
Derivative instruments not designated as hedges | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	(28,018)	(2,886)
Fuel Product | Crude oil swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(99,960)	133,060
Fuel Product | Crude oil swaps | Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	99,672	(8,159)
Fuel Product | Gasoline swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(15,981)	(38,289)
Fuel Product | Gasoline swaps | Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	(52,038)	(1,850)
Fuel Product | Diesel swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(59,260)	(53,622)
Fuel Product | Diesel swaps | Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	(10,518)	(573)
Fuel Product | Jet fuel swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(39,931)	(77,288)
Fuel Product | Jet fuel swaps | Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	(123)	(2,715)
Fuel Product | Derivative instruments not designated as hedges | Crude oil swaps | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	(30,488)	0
Fuel Product | Derivative instruments not designated as hedges | Crude oil swaps | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	(39,967)	0
Fuel Product | Derivative instruments not designated as hedges | Gasoline swaps | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	22,110	0
Fuel Product | Derivative instruments not designated as hedges | Gasoline swaps | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	519	0
Fuel Product | Derivative instruments not designated as hedges | Diesel swaps | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	10,895	0
Fuel Product | Derivative instruments not designated as hedges | Diesel swaps | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	8,912	0
Fuel Product | Derivative instruments not designated as hedges | Jet fuel swaps | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	(1,719)	0
Fuel Product | Derivative instruments not designated as hedges | Jet fuel swaps | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	0	0
Fuel Product | Derivative instruments not designated as hedges | Jet fuel collars | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	0	(746)
Fuel Product | Derivative instruments not designated as hedges | Jet fuel collars | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	0	726
Fuel Product | Cost of sales | Crude oil swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	(49,874)	(110,945)
Fuel Product | Sales | Gasoline swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	38,388	29,468
Fuel Product | Sales | Diesel swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	62,966	79,810
Fuel Product | Sales | Jet fuel swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	104,482	102,473
Specialty Product | Crude oil swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	0
Specialty Product | Crude oil swaps | Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	0	0
Specialty Product | Natural gas swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	0
Specialty Product | Natural gas swaps | Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	0	0
Specialty Product | Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	1,979
Specialty Product | Interest rate swaps | Unrealized/Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	0	0
Specialty Product | Derivative instruments not designated as hedges | Crude oil swaps | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	0	932
Specialty Product | Derivative instruments not designated as hedges | Crude oil swaps | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	1,649	(662)
Specialty Product | Derivative instruments not designated as hedges | Natural gas swaps | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	(5,442)	(171)
Specialty Product | Derivative instruments not designated as hedges | Natural gas swaps | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	3,221	(3,221)
Specialty Product | Derivative instruments not designated as hedges | Interest rate swaps | Realized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	(732)	(2,124)
Specialty Product | Derivative instruments not designated as hedges | Interest rate swaps | Unrealized Gain
Derivative instruments not designated as cash flow hedges
Amount of Gain (Loss) Recognized in Derivative Instruments	1,011	271
Specialty Product | Cost of sales | Crude oil swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	(1,877)	2,512
Specialty Product | Cost of sales | Natural gas swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	0	0
Specialty Product | Interest expense | Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	$ 0	$ 702

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

Changes in goodwill balances are as follows:

	Year Ended December 31,
	2012						2011
	Specialty		Fuel				Specialty		Fuel
	Products		Products		Total		Products		Products		Total
Beginning balance:	$	48,335	$	—	$	48,335	$	48,335	$	—	$	48,335
Acquisitions	111,035		27,643		138,678		—		—		—
Accumulated impairment losses	—		—		—		—		—		—
Ending balance:	$	159,370	$	27,643	$	187,013	$	48,335	$	—	$	48,335

Schedule of Other Intangible Assets

Other intangible assets consist of the following:

	Weighted Average Life (Years)	December 31, 2012					December 31, 2011
		Gross Amount		Accumulated Amortization			Gross Amount		Accumulated Amortization
Customer relationships	20	$	154,307	$	(22,612	)	$	28,482	$	(12,936	)
Supplier agreements	4	21,519		(21,519		)	21,519		(19,926		)
Tradenames - Royal Purple Retail	Indefinite	14,790		—			—		—
Tradenames	9	6,421		(550		)	—		—
Trade secrets	12	44,179		(3,116		)	—		—
Patents	12	1,573		(1,112		)	1,573		(966		)
Non-competition agreements	5	5,827		(5,780		)	5,732		(4,182		)
Distributor agreements	3	2,019		(2,019		)	2,019		(2,019		)
Royalty agreements	19	4,499		(1,343		)	4,499		(1,120		)
	16	$	255,134	$	(58,051	)	$	63,824	$	(41,149	)

Schedule of Estimated Future Amortization Expense

The Company estimates that amortization of intangible assets for the next five years will be as follows:

Year	Amortization Amount
2013	$	25,401
2014	$	24,297
2015	$	22,165
2016	$	20,217
2017	$	17,669
2018	$	14,904

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Derivatives (Details 7) (Specialty Product, Non cash flow hedges, Natural gas swaps)	Dec. 31, 2012 MMBTU
Derivative [Line Items]
Million Metric British Thermal Units	4,200,000
Natural Gas Swap Contracts by Expiration Dates
Average price	3.97
First Quarter 2012
Derivative [Line Items]
Million Metric British Thermal Units	1,200,000
Natural Gas Swap Contracts by Expiration Dates
$/MMBtu	3.90
Second Quarter 2012
Derivative [Line Items]
Million Metric British Thermal Units	1,200,000
Natural Gas Swap Contracts by Expiration Dates
$/MMBtu	3.93
Third Quarter 2012
Derivative [Line Items]
Million Metric British Thermal Units	1,200,000
Natural Gas Swap Contracts by Expiration Dates
$/MMBtu	4.03
Fourth Quarter 2012
Derivative [Line Items]
Million Metric British Thermal Units	600,000
Natural Gas Swap Contracts by Expiration Dates
$/MMBtu	4.08

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Description of the Business (Details)	12 Months Ended
	Dec. 31, 2012
Limited Partners
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of units	57,529,778
Incentive distribution rights	98.00%
General partner [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of units	1,174,077
Incentive distribution rights	2.00%

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Transactions with Related Parties

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

Transactions with Related Parties

Transactions with Related Parties

During the years ended December 31, 2012, 2011 and 2010, the Company had product sales to related parties owned by a limited partner of $9,309, $16,500 and $4,727, respectively. Trade accounts and other receivables from related parties at December 31, 2012 and 2011 were $139 and $1,818, 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”) and director’s and officers’ liability insurance premiums discussed below, during the years ended December 31, 2012, 2011 and 2010 of $7,181, $1,768 and $1,480, respectively. Accounts payable to related parties, excluding accounts payable related to the Legacy Resources agreements discussed below, at December 31, 2012 and 2011 were $2,230 and $1,393, 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 the Company’s 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 Resources (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 Resources, 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, 2012 and 2011 and 2010, the Company had crude oil purchases of $1,120, $229,793 and $591,777, respectively, from Legacy Resources. Accounts payable to Legacy Resources at December 31, 2012 and 2011 were $96 and $574, respectively.

Nicholas J. Rutigliano, a member of the board of directors of the Company’s general partner, founded and is the president of Tobias Insurance Group, Inc. (“Tobias”), a commercial insurance brokerage business that has historically placed the Company’s directors’ and officers’ liability insurance. The total premiums paid to Tobias by the Company for the years ended December 31, 2012, 2011 and 2010 were $510, $566 and $638, 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, 2012, 2011 and 2010.

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Segments and Related Information (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Jan. 01, 2013	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Major product category sales
Sales	$ 1,220,882	$ 1,179,818	$ 1,086,996	$ 1,169,586	$ 1,018,133	$ 777,780	$ 733,770	$ 605,240	$ 4,657,282	$ 3,134,923	$ 2,190,752
Specialty Product
Segment Reporting Information [Line Items]
Number of products									6
Major product category sales
Sales									3,384,697	2,886,964	2,184,238
Fuel Product
Major product category sales
Sales									2,499,225	1,373,416	821,290
Product Concentration Risk
Major product category sales
Sales									4,657,282	3,134,923	2,190,752
Sales, percentage					100.00%				100.00%	100.00%	100.00%
Product Concentration Risk | Specialty Product
Major product category sales
Sales									2,231,602	1,807,626	1,408,872
Sales, percentage					58.00%				48.00%	58.00%	64.00%
Product Concentration Risk | Specialty Product | Lubricating oils
Major product category sales
Sales									1,007,928	947,798	759,701
Sales, percentage					30.00%				22.00%	30.00%	35.00%
Product Concentration Risk | Specialty Product | Solvents
Major product category sales
Sales									491,114	495,934	396,894
Sales, percentage					16.00%				11.00%	16.00%	18.00%
Product Concentration Risk | Specialty Product | Waxes
Major product category sales
Sales									142,765	143,111	124,964
Sales, percentage					5.00%				3.00%	5.00%	6.00%
Product Concentration Risk | Specialty Product | Packaged and synthetic specialty products
Major product category sales
Sales									161,673	0	0
Sales, percentage					0.00%				3.00%	0.00%	0.00%
Product Concentration Risk | Specialty Product | Fuels
Major product category sales
Sales									2,029	3,432	5,507
Sales, percentage					0.00%				0.00%	0.00%	0.00%
Product Concentration Risk | Specialty Product | Asphalt and other by-products
Major product category sales
Sales									426,093	217,351	121,806
Sales, percentage					7.00%				9.00%	7.00%	5.00%
Product Concentration Risk | Fuel Product
Major product category sales
Sales									2,425,680	1,327,297	781,880
Sales, percentage					42.00%				52.00%	42.00%	36.00%
Product Concentration Risk | Fuel Product | Gasoline
Major product category sales
Sales									1,174,859	619,630	304,544
Sales, percentage					20.00%				25.00%	20.00%	14.00%
Product Concentration Risk | Fuel Product | Diesel
Major product category sales
Sales									941,047	513,334	330,756
Sales, percentage					16.00%				20.00%	16.00%	15.00%
Product Concentration Risk | Fuel Product | Jet fuel
Major product category sales
Sales									183,953	148,036	135,796
Sales, percentage					5.00%				4.00%	5.00%	6.00%
Product Concentration Risk | Fuel Product | Heavy fuel oils and other
Major product category sales
Sales									$ 125,821	$ 46,297	$ 10,784
Sales, percentage					1.00%				3.00%	1.00%	1.00%