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

Form 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


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

		For the fiscal year ended December 31, 2011

		OR

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

Commission File number 000-51734

Calumet Specialty Products Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)


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

2780 Waterfront Pkwy E. Drive

Suite 200

Indianapolis, Indiana 46214

(317) 328-5660

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

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


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

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

NONE.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

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

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

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

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


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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

NONE.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

FORM 10-K — 2011 ANNUAL REPORT

Table of Contents


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

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

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

PART IV
Item 15.	Exhibits		177

FORWARD-LOOKING STATEMENTS

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

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

PART I

Items 1 and 2. Business and Properties

Overview

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

Our Primary Operating Assets

Our primary operating assets consist of:

•

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

•

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

•

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

•

Princeton Refinery. Our refinery located in Princeton, Louisiana (“Princeton”) and acquired in 1990 produces specialty lubricating oils, including process oils, base oils, transformer oils and refrigeration oils that are used in a variety of industrial and automotive applications. The Princeton refinery has aggregate crude oil throughput capacity of approximately 10,000 bpd.

•

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

•

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

•

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

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

Business Strategies

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

•

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

•

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

•

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

•

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

Competitive Strengths

We believe that we are well positioned to execute our business strategies successfully based on the following competitive strengths:

•

We offer our customers a diverse range of specialty products. We offer a wide range of over 1,500 specialty products. We believe that our ability to provide our customers with a more diverse selection of products than our competitors generally gives us an advantage in competing for new business. We believe that we are the only specialty products manufacturer that produces all four of naphthenic lubricating oils, paraffinic lubricating oils, waxes and solvents. A contributing factor in our ability to produce numerous specialty products is our ability to ship products between our facilities for product upgrading in order to meet customer specifications.

•

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

•

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

•

We have an experienced management team. Our management has a proven track record of enhancing value through the acquisition, exploitation and integration of refining assets and the development and marketing of specialty products. Our senior management team has an average of over 25 years of industry experience. Our team’s extensive experience and contacts within the refining industry provide a strong foundation and focus for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing and enhancing the profitability of new assets.

Recent Acquisitions

Superior Acquisition

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

•

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

•

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

•

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

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

Hercules Synthetic Lubricants Business

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

TruSouth Oil

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

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

Partnership Structure and Management

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

Our Operating Assets and Contractual Arrangements

General

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

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


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

Total		36,850		32,221		28,906

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

Total		34,059		25,093		29,886

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

(1)

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

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

(3)


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

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

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

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

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

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

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

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

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

Shreveport Refinery

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

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


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

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

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

(2)

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

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

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

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

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

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

Superior Refinery

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

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


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

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

(2)

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

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

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

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

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

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

Cotton Valley Refinery

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

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


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

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

(2)

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

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

The Cotton Valley refinery configuration is flexible, which allows us to respond to market changes and customer demands by modifying its product mix. The reconfigured fractionation train also allows the refinery to satisfy demand fluctuations efficiently without large finished product inventory requirements.

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

Princeton Refinery

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

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


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

(1)

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

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

Karns City Facility

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

Dickinson Facility

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

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


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

(1)	Includes Karns City and Dickinson facilities only.

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

(3)

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

LyondellBasell Agreements

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

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


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

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

(2)

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

Terminals

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

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

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

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

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

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

Other Logistics Assets

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

Our Crude Oil and Feedstock Supply

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

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

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

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

Our cost to acquire crude oil and feedstocks and the prices for which we ultimately can sell refined products depend on a number of factors beyond our control, including regional and global supply of and demand for crude oil and other feedstocks and specialty and fuel products. These in turn are dependent upon, among other things, the availability of imports, overall economic conditions, production levels of domestic and foreign suppliers, U.S. relationships with foreign governments, political affairs and the extent of governmental regulation. We have historically been able to pass on the costs associated with increased crude oil and feedstock prices to our specialty products customers, although the increase in selling prices for specialty products typically lags the rising cost of crude oil. From time to time, we use a hedging program to manage a portion of this commodity price risk. Please read Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk — Crude Oil Price Volatility and Hedging Policy” for a discussion of our crude oil hedging program for our specialty products segment.

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

Our Products, Markets and Customers

Products

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

Representative Sample of End Use Applications by Product¹


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

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

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

We have an experienced marketing department with average industry tenure of approximately 20 years. Our salespeople regularly visit customers and our marketing department works closely with both the laboratories at our refineries and our technical services department to help create specialized blends that will work optimally for our customers.

Markets

Specialty Products. The specialty products market represents a small portion of the overall petroleum refining industry in the United States. Of the nearly 150 refineries currently in operation in the U.S., only a small number of the refineries are considered specialty products producers and only a few compete with us in terms of the number of products produced.

Our specialty products are utilized in applications across a broad range of industries, including in:

•

industrial goods such as metalworking fluids, belts, hoses, sealing systems, batteries, hot melt adhesives, pressure sensitive tapes, electrical transformers, refrigeration compressors and drilling fluids;

•

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

•

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

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

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

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

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

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

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

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

Customers

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

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

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

Competition

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

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

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

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

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

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

Our ability to compete effectively depends on our responsiveness to customer needs and our ability to maintain competitive prices and product offerings. We believe that our flexibility and customer responsiveness differentiate us from many of our larger competitors. However, it is possible that new or existing competitors could enter the markets in which we operate, which could negatively affect our financial performance.

Environmental and Occupational Health and Safety Matters

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

application of specific health and safety criteria addressing worker protection and imposing substantial liabilities on us for pollution resulting from our operations. Certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed.

Failure to comply with environmental laws and regulations may result in the triggering of administrative, civil and criminal measures, including the assessment of monetary penalties, the imposition of remedial obligations and the issuance of injunctions limiting or prohibiting some or all of our operations. On occasion, we receive notices of violation or enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. In particular, the Louisiana Department of Environmental Quality (“LDEQ”) initiated enforcement actions in prior years for the following alleged violations (the “Alleged LDEQ Violations”): (i) a May 2001 notification received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations, as identified in the course of our Leak Detection and Repair program, and also for failure to submit various reports related to the facility’s air emissions; (ii) a December 2002 notification received by the Cotton Valley refinery from the LDEQ regarding alleged violations for excess emissions, as identified in the LDEQ’s file review of the Cotton Valley refinery; (iii) a December 2004 notification received by the Cotton Valley refinery from the LDEQ regarding alleged violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency; and (iv) an August 2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations, as identified by LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emission levels.

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

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

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, in connection with accidental spills or releases associated with our operations, we cannot assure our unitholders that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with these requirements will not have a material adverse effect on us, there can be no assurance that our environmental compliance expenditures will not become material in the future.

Air Emissions

Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws. The Clean Air Act Amendments of 1990 require most industrial operations in the U.S. to incur capital expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. Under the Clean Air Act, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. In addition, the petroleum refining sector has come under stringent new EPA regulations, imposing maximum achievable control technology (“MACT”) on refinery equipment emitting certain listed hazardous air pollutants. Some of our facilities have been included within the categories of sources regulated by MACT rules. In addition, air permits are required for our refining and terminal operations that result in the emission of regulated air contaminants. These permits incorporate stringent control technology requirements and are subject to extensive review and periodic renewal. We believe that we are in substantial compliance with the Clean Air Act and similar state and local laws.

The Clean Air Act authorizes the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with the fuel product’s final use. For example, in December 1999, the EPA promulgated regulations limiting the sulfur content allowed in gasoline. These regulations required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those western U.S. states exhibiting lesser air quality problems. Similarly, the EPA promulgated regulations that limit the sulfur content of highway diesel beginning

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

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

Climate Change

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

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

Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and

operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our operations, we generate wastes or handle substances that may be regulated as hazardous substances, and we could become subject to liability under CERCLA and comparable state laws.

We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state laws, which impose requirements related to the handling, storage, treatment, and disposal of solid and hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes. In addition, our operations also generate solid wastes, which are regulated under RCRA and state laws. We believe that we are in substantial compliance with the existing requirements of RCRA and similar state and local laws, and the cost involved in complying with these requirements is not material.

We currently own or operate, and have in the past owned or operated, properties that for many years have been used for refining and terminal activities. These properties have in the past been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes have been released on or under the properties owned or operated by us. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

Voluntary remediation of subsurface contamination is in process at each of our refinery sites. These projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, we believe that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on our financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. We incurred approximately $0.3 million and $0.5 million in 2011 and 2010, respectively, of such capital expenditures at our Cotton Valley refinery.

Water Discharges

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. Such discharges are prohibited, except in accordance with the terms of a permit issued by the EPA or the appropriate state agencies. Any unpermitted release of pollutants, including crude oil or hydrocarbon specialty oils as well as refined products, could result in penalties, as well as significant remedial obligations. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. We believe that we are in substantial compliance with the requirements of the Clean Water Act and similar state laws.

The primary federal law for oil spill liability is the Oil Pollution Act of 1990, as amended (“OPA”), which addresses three principal areas of oil pollution — prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including refineries, terminals, and associated facilities that may affect waters of the U.S. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages from oil spills. We believe that we are in substantial compliance with OPA and similar state laws.

Occupational Health and Safety

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

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

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

Other Environmental and Maintenance Items

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

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

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

Insurance

Our operations are subject to certain hazards of operations, including fire, explosion and weather-related perils. We maintain insurance policies, including business interruption insurance for each of our facilities, with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

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

Seasonality

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

Properties

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


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

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

Office Facilities

In addition to our refineries and terminals discussed above, we occupy approximately 32,800 square feet of office space in Indianapolis, Indiana and approximately 1,600 square feet of office space in El Dorado, Arkansas, both of which are under leases. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.

Employees

As of February 27, 2012, our general partner employs approximately 920 people who provide direct support to our operations. Of these employees, approximately 480 are covered by collective bargaining agreements. Employees at the Superior, Cotton Valley, Princeton and Dickinson facilities are covered by separate collective bargaining agreements with the International Union of Operating Engineers. The Superior and Princeton refineries’ collective bargaining agreements expire on July 1, 2012 and October 31, 2014, respectively. The Cotton Valley refinery’s and Dickinson facility’s collective bargaining agreements will both expire on March 31, 2013. Employees at the Shreveport refinery are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union which expires on April 30, 2013. The Karns City facility employees are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber Manufacturing, Energy, Allied Industrial and Service Workers International Union that will expire on January 31, 2015. None of the employees at the TruSouth or Missouri facilities or at the, Burnham, Rhinelander, Crookston or Duluth terminals are covered by collective bargaining agreements. Our general partner considers its employee relations to be good, with no history of work stoppages.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are located at 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, Indiana 46214 and our telephone number is (317) 328-5660. Our website is located at http://www.calumetspecialty.com.

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

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Annual Report on Form 10-K;

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Quarterly Reports on Form 10-Q;

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Current Reports on Form 8-K;

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

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Charters for the Audit, Compensation and Conflicts Committees; and

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Code of Business Conduct and Ethics.

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

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

Item 1A.

Risk Factors

Risks Relating to our Business

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

We may not have sufficient available cash from operations each quarter to enable us to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay expenses, including payments to our general partner, and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which is primarily dependent upon our producing and selling quantities of fuel and specialty products, or refined products, at margins that are high enough to cover our fixed and variable expenses. Crude oil costs, fuel and specialty products prices and, accordingly, the cash we generate from operations, will fluctuate from quarter to quarter based on, among other things:

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

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

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

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the marketing of alternative and competing products;

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the extent of government regulation;

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results of our hedging activities; and

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overall economic and local market conditions.

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

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

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our debt service requirements;

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fluctuations in our working capital needs;

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our ability to borrow funds and access capital markets;

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

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

Refining margins are volatile, and a reduction in our refining margins will adversely affect the amount of cash we will have available for distribution to our unitholders and for payments of our debt obligations.

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

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

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

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

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

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

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

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

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

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

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

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

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

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sell assets, including equity interests in our subsidiaries;

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

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incur or guarantee additional indebtedness or issue preferred units;

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create or incur certain liens;

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make certain acquisitions and investments;

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redeem or repay other debt or make other restricted payments;

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enter into transactions with affiliates;

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

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create unrestricted subsidiaries;

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enter into sale and leaseback transactions;

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

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engage in certain business activities.

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

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

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

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

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

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

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

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

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

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions to our unitholders, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to accomplish any of these remedies on satisfactory terms, or at all. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information regarding our indebtedness.

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

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

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

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

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

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

To the extent that our suppliers reduce the volumes of crude oil and other feedstocks that they supply us as a result of declining production or competition or otherwise, our revenues, net income and cash available for distribution to unitholders and payments of our debt obligations would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks on comparable terms from other suppliers, which may not be possible in areas where the supplier that reduces its volumes is the primary supplier in the area. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We have no control over the level of drilling activity in the fields that supply our refineries, the amount of reserves underlying the wells in these fields, the rate at which production from a well will decline or the production decisions of producers. A material

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

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

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

The price volatility of fuel and utility services may result in decreases in our earnings, profitability and cash flows.

The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect our net income and cash flows. Fuel and utility prices are affected by factors outside of our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile.

For example, daily prices for natural gas as reported on the New York Mercantile Exchange (“NYMEX”) ranged between $2.99 and $4.85 per million British thermal unit, or MMBtu, in 2011 and between $3.29 and $6.01 per MMBtu in 2010. Typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a material adverse effect on our results of operations. Fuel and utility costs constituted approximately 19.6% and 21.6% of our total operating expenses included in cost of sales for the years ended December 31, 2011 and 2010, respectively. If our natural gas costs rise, it will adversely affect the amount of cash we will have available for distribution to our unitholders.

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

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

Although we maintain insurance policies, including personal and property damage and business interruption insurance for each of our facilities with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent, we cannot ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or significant interruption of operations. Our business interruption insurance will not apply unless a business interruption exceeds 90 days. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. In addition, we are not fully insured against all risks incident to our business because certain risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures. For example, we are not insured for environmental accidents at all of our facilities. If we were to incur a significant liability for which we were not fully insured, it could diminish our ability to make distributions to our unitholders.

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

There is inherent risk of incurring significant environmental costs and liabilities in the operation of our crude oil and specialty hydrocarbon refineries, terminals, and related facilities due to our handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to our operations, and as a result of historical operations and waste disposal practices of prior owners of our facilities. We currently own or operate properties that for many years have been used for industrial activities, including refining or terminal storage operations, sometimes by third parties over whom we had no control with respect to their operations or waste disposal activities. Petroleum hydrocarbons or wastes have been released on, under or from the properties owned or operated by us. Joint and several strict liability may be incurred in connection with such releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities. Neither the owners of our general partner nor their affiliates have indemnified us for any environmental liabilities, including those arising from non-compliance or pollution, that may be discovered at, or arise from operations on, the assets they contributed to us in connection with the closing of our initial public offering. Private parties, including the owners of properties adjacent to our operations and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover some or any of these costs from insurance or other sources of indemnity. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition, and results of operations.

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

Our crude oil and specialty hydrocarbon refining, terminal and related facility operations are subject to stringent and complex federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose numerous obligations that are applicable to our operations, including the obligation to obtain permits to conduct regulated activities, the incurrence of significant capital expenditures for air pollution control equipment or otherwise limit or prevent releases of pollutants from our refineries, terminal, and related facilities, the expenditure of significant monies in the application of specific health and safety criteria addressing worker protection, the requirement to maintain information about hazardous materials used or produced in our operations and to provide this information to employees, state and local government authorities, and local residents and the incurrence of substantial costs and liabilities for pollution resulting from our operations or from those of prior owners of our facilities. Numerous governmental authorities, such as the EPA, OSHA, and state agencies, such as the LDEQ and WDNR, have the power to enforce compliance with these laws and regulations and the permits

issued under them, often requiring difficult and costly actions. Failure to comply with these laws, regulations, permits and orders may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. On occasion, we receive notices of violation, enforcement proceedings and regulatory inquiries from governmental agencies alleging non-compliance with applicable environmental and occupational health and safety laws and regulations. Please read Items 1 and 2 “Business and Properties — Environmental and Occupational Health and Safety Matters” for additional information regarding our communications with the LDEQ and OSHA.

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

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

If we do not successfully execute our growth through acquisitions, our future growth and ability to increase distributions to our unitholders will be limited.

Our ability to grow depends on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to consummate acquisitions on favorable terms, (3) unable to obtain financing for these acquisitions on economically acceptable terms, or (4) outbid by competitors, then our future growth and ability to increase distributions to our unitholders will be limited. Furthermore, any acquisition, including our recent acquisition of the Superior Business, involves potential risks, including, among other things:

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

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a significant increase in our indebtedness and working capital requirements;

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

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

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

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customer or key employee losses at the acquired businesses; and

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significant changes in our capitalization and results of operations.

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

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

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

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

We face substantial competition from other refining companies.

The refining industry is highly competitive. Our competitors include large, integrated, major or independent oil companies that, because of their more diverse operations, larger refineries and stronger capitalization, may be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers. For example, if a competitor attempts to increase market share by reducing prices, our operating results and cash available for distribution to our unitholders and payments of our debt obligations could be reduced.

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

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

Distributions to unitholders and payments of our debt obligations could be adversely affected by a decrease in the demand for our specialty products.

Changes in our customers’ products or processes may enable our customers to reduce consumption of the specialty products that we produce or make our specialty products unnecessary. Should a customer decide to use a different product due to price, performance or other considerations, we may not be able to supply a product that meets the customer’s new requirements. In addition, the demand for our customers’ end products could decrease, which could reduce their demand for our specialty products. Our specialty products customers are primarily in the industrial goods, consumer goods and automotive goods industries and we are therefore susceptible to overall economic conditions, which may change demand patterns and products in those industries. Consequently, it is important that we develop and manufacture new products to replace the sales of products that mature and decline in use. If we are unable to manage successfully the maturation of our existing specialty products and the introduction of new specialty products our revenues, net income and cash available for distribution to unitholders could be reduced and payments of our debt obligations.

Distributions to unitholders and payments of our debt obligations could be adversely affected by a decrease in demand for fuel products in the markets we serve.

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

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

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

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

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

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competitor actions; and

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availability of raw materials.

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

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

Because of the volatility of crude oil and refined products prices, our method of valuing our inventory may result in decreases in net income.

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value, if the market value of our inventory were to decline to an amount less than our cost, we would record a write-down of inventory and a non-cash charge to cost of sales. In a period of decreasing crude oil or refined product prices, our inventory valuation methodology may result in decreases in net income.

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

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

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

We rely primarily on sales generated from products processed at the facilities we own. Furthermore, the majority of our assets and operations are located in northwest Louisiana and northwest Wisconsin. Due to our lack of diversification in asset type and location, an adverse development in these businesses or areas, including adverse developments due to catastrophic events or weather, decreased supply of crude oil and feedstocks and/or decreased demand for refined petroleum products, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets in more diverse locations.

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

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

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.

Our specialty products provide precise performance attributes for our customers’ products. If a product fails to perform in a manner consistent with the detailed quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. A successful claim or series of claims against us could result in a loss of one or more customers and reduce our ability to make distributions to unitholders and payments of our debt obligations.

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

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

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

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

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

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

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

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

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

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties of our derivative instruments. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we

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

Risks Inherent in an Investment in Us

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

The families of our chairman, chief executive officer and vice chairman, the Heritage Group, and certain of their affiliates own a 37.6% limited partner interest in us. In addition, The Heritage Group and the families of our chairman and chief executive officer and vice chairman own our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

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

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

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

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

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

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

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in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

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

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

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

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

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

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

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Generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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

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

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

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

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

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

Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby control the decisions taken by the board of directors.

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs.

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs. We can provide no assurance that our general partner will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If our general partner fails to provide us with adequate personnel, our operations could be adversely impacted and our cash available for distribution to unitholders and payments of our debt obligations could be reduced.

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

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units. The issuance of additional common units or other equity securities of equal or senior rank to the common units will have the following effects:

•

our unitholders’ proportionate ownership interest in us may decrease;

•

the amount of cash available for distribution on each unit may decrease;

•

the relative voting strength of each previously outstanding unit may be diminished;

•

the market price of the common units may decline; and

•

the ratio of taxable income to distributions may increase.

Our general partner’s determination of the level of cash reserves may reduce the amount of available cash for distribution to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement also permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These reserves will affect the amount of cash available for distribution to unitholders.

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

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

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

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Any such reimbursement will be determined by our general partner and will reduce the cash available for distribution to unitholders and payments of our debt obligations. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence.”

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

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

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

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

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

•

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

•

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

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

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

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

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

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

•

our quarterly distributions;

•

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

•

changes in commodity prices or refining margins;

•

loss of a large customer;

•

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

•

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

•

general economic conditions;

•

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

•

future sales of our common units; and

•

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

Tax Risks to Common Unitholders

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

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

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

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

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

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

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

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

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Because our unitholders are treated as partners in us for U.S. federal income tax purposes we allocate a share of our taxable income to our unitholders which could be different in amount than the cash we distribute, and our unitholders may be required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us.

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

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

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

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

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

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

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

We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level income taxes.

We conduct all or a portion of our operations in which we market finished petroleum products to certain customers through a subsidiary that is organized as a corporation. We may elect to conduct additional operations through this corporate subsidiary in the future. This corporate subsidiary is obligated to pay corporate income taxes, which reduce the corporation’s cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that this corporation has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

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

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

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

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

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

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

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

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

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

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

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, non-U.S. taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file tax returns and pay taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We do business in 38 states. The states we operate in, with the exception of Texas and Florida, currently impose a personal income tax as well as an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is the responsibility of our common unitholders to file all required U.S. federal, state, local and non-U.S. tax returns.

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

Item 1B.

Unresolved Staff Comments

None.

Item 3.

Legal Proceedings

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

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

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

Item 5.

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

Market Information

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


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

(1)

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

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

Cash Distribution Policy

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

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

•

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

•

provide for the proper conduct of our business;

•

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

•

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

•

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

Intent to Distribute the Minimum Quarterly Distribution. We distribute to the holders of common units on a quarterly basis at least the minimum quarterly distribution of $0.45 per unit, or $1.80 in aggregate per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under our debt instruments, including our credit agreement and the indentures governing our 2019 Notes. Please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for a discussion of the restrictions in our debt instruments that restrict our ability to make distributions. On February 14, 2012, we paid a quarterly cash distribution of $0.53 per unit on all outstanding units totaling approximately $28.2 million for the quarter ended December 31, 2011 to all unitholders of record as of the close of business on February 3, 2012.

General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest is represented by 1,051,628 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.495 per unit. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest, and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on units that it owns. Our general partner did not earn incentive distribution rights during the year ended December 31, 2010. Our general partner earned incentive distribution rights of approximately $0.3 million during the year ended December 31, 2011.

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

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


	Total Quarterly Distribution Target Amount Per Common Unit	Marginal Percentage Interest in Distributions
		Unitholders			General Partner
Minimum Quarterly Distribution	$0.45		98	%		2	%
First Target Distribution	up to $0.495		98	%		2	%
Second Target Distribution	above $0.495 up to $0.563		85	%		15	%
Third Target Distribution	above $0.563 up to $0.675		75	%		25	%
Thereafter	above $0.675		50	%		50	%

Equity Compensation Plans

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

Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

Item 6.

Selected Financial Data

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

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

We derived the information in the following table from, and the information should be read together with, and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in Item 8 “Financial Statements and Supplementary Data” except for operating data, such as sales volume, feedstock runs and facility production. The following table also should be read together with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


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

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

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

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

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

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

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

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


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

(1)

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

(3)

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

Non-GAAP Financial Measures

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

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

•

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

•

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

•

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

•

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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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

Item 7.

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

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

Overview

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

2011 Update

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

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

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

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

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

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

Superior Acquisition

•

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

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

Key Performance Measures

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

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

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

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

•

sales volumes;

•

production yields; and

•

specialty products and fuel products gross profit.

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

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

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

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

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

Results of Operations

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


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

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

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

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

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

(1)

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

(2)

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

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

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

(3)

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

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

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


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

Gross profit		274,130			198,749			173,102

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

Operating income		125,292			71,490			67,360

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

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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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

Liquidity and Capital Resources

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

Cash Flows from Operating, Investing and Financing Activities

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

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

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


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

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

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

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

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

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

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

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

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

Capital Expenditures

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

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


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

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

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

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

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

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

Debt and Credit Facilities

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

•

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

•

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

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

Amended and Restated Senior Secured Revolving Credit Facility

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

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

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

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

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


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

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

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

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

9³/8% Senior Notes

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

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

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

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

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

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


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

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

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

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

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

Registration of 2019 Notes

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

Termination of Senior Secured First Lien Credit Facility

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

Amendments to Master Derivative Contracts

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

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

Collateral Trust Agreement

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

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

Equity Transactions

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

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

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

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

Seasonality Impacts on Liquidity

Asphalt demand is typically lower in the first and fourth quarters of the year as compared to the second and third quarters due to the seasonality of annual road construction. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months. This seasonality causes significant changes to our working capital requirements, which causes significant changes in borrowings under our revolving credit facility and our liquidity during such periods.

Contractual Obligations and Commercial Commitments

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


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

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

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

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

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

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

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

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

Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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


Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Revenue Recognition

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

The cost of inventories is determined using the last-in, first-out (LIFO) method and valued at the lower of cost or market. Inventoriable costs include crude oil and other feedstocks, labor and refining overhead costs.	Judgment is required in determining the market value of inventory, as the geographic location impacts market prices, and quoted market prices may not be available for the particular location of our inventory. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value, if the market value of our inventory were to decline to an amount less than our cost, we would record a write-down of inventory and a non-cash charge to cost of sales. In a period of decreasing crude oil or refined product prices, our inventory valuation methodology may result in decreases in net income. We review our inventory balances quarterly for excess inventory levels or obsolete inventory and write down, if necessary, the inventory to net realizable value.	We have not made any material changes in the accounting methodology we use to establish our markdown or inventory loss adjustments during the past three fiscal years. The replacement cost of our inventory, based on current market values, would have been $87.6 million and $55.9 million higher at December 31, 2011 and 2010, respectively. We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions we use to calculate our inventory. If commodity prices were to decrease by 10% below our December 31, 2011 inventory values, our net income would have negatively impacted by approximately $58.5 million.


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

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

Description

Judgments and Uncertainties

Effect if Actual Results Differ
from Assumptions

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

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

Recent Accounting Pronouncements

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

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

Crude Oil Price Volatility and Hedging Policy

We are exposed to significant fluctuations in the price of crude oil, our principal raw material. Given the historical volatility of crude oil prices, this exposure can significantly impact product costs and gross profit. Holding all other variables constant, and excluding the impact of our current hedges, we expect a $1.00 change in the per barrel price of crude oil would change our specialty product segment cost of sales by $11.3 million and our fuel product segment cost of sales by $12.8 million based on our sales volumes for 2011 and would change our specialty product segment cost of sales by $10.8 million and our fuel product segment cost of sales by $9.6 million based on our sales volumes for 2010.

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

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

Natural Gas Price Volatility and Hedging Policy

Since natural gas purchases comprise a significant component of our cost of sales, changes in the price of natural gas also significantly affect our profitability and our cash flows. Holding all other cost and revenue variables constant, and excluding the impact of our current hedges, we expect a $0.50 change per MMBtu (one million British Thermal Units) in the price of natural gas would change our cost of sales by $4.9 million and $4.0 million based on our results for the years ended December 31, 2011 and 2010, respectively.

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

Fuel Products Selling Price Volatility and Hedging Policy

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

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

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

Pension Assets Volatility and Investment Policy

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

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

Interest Rate Risk and Existing Interest Rate Derivative Instruments

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


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

(1)

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

(2)

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

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

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

Existing Commodity Derivative Instruments

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

Fuel Products Segment

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

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


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

Totals		16,536,000
Average price						$	89.07

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