CLMT 10-Q Quarterly Report March 31, 2011

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

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10-Q 1 c16691e10vq.htm FORM 10-Q Form 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011


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

FOR THE TRANSITION PERIOD FROM TO

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		(I.R.S. Employer
Incorporation or Organization)		Identification Number)

2780 Waterfront Parkway East Drive, Suite 200
Indianapolis, Indiana		46214
(Address of principal executive officers)		(Zip code)

Registrant’s telephone number including area code (317) 328-5660

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

Indicate by check mark 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 Registration S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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 o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(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 o No þ

At May 6, 2011, there were 39,779,778 common units outstanding.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three Months Ended March 31, 2011

Table of Contents


	Page

Part I

Item 1. Financial Statements

Condensed Consolidated Balance Sheets		5

Unaudited Condensed Consolidated Statements of Operations		6

Unaudited Condensed Consolidated Statements of Partners’ Capital		7

Unaudited Condensed Consolidated Statements of Cash Flows		8

Notes to Unaudited Condensed Consolidated Financial Statements		9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30

Item 3. Quantitative and Qualitative Disclosures About Market Risk		45

Item 4. Controls and Procedures		46

Part II

Item 1. Legal Proceedings		47

Item 1A. Risk Factors		47

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		50

Item 3. Defaults Upon Senior Securities		50

Item 4. Removed and Reserved		50

Item 5. Other Information		50

Item 6. Exhibits		51

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly 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 of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes and (iii) future compliance with our debt covenants, as well as other matters discussed in this Quarterly Report that are not purely historical data, are forward-looking statements. These statements discuss future expectations or state other “forward-looking” information and involve risks and uncertainties. When considering these forward-looking statements, unitholders should keep in mind the risk factors and other cautionary statements included in this Quarterly Report and in our Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on February 22, 2011 (our “2010 Annual Report”). These risk factors and other factors noted throughout this Quarterly Report and in our 2010 Annual Report could cause our actual results to differ materially from those contained in any forward-looking statement. These factors include, but are not limited to:

•

the overall demand for specialty hydrocarbon products, fuels and other refined products;

•

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

•

the impact of fluctuations and rapid increases or decreases in crude oil and crack spread prices, including the resulting impact on our liquidity;

•

the results of our hedging and other risk management activities;

•

our ability to comply with financial covenants contained in our debt instruments;

•

the availability of, and our ability to consummate, acquisition or combination opportunities and impact of any completed acquisitions;

•

labor relations;

•

our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;

•

successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships;

•

environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

•

maintenance of our credit ratings and ability to receive open credit lines from our suppliers;

•

demand for various grades of crude oil and resulting changes in pricing conditions;

•

fluctuations in refinery capacity;

•

the effects of competition;

•

continued creditworthiness of, and performance by, counterparties;

•

the impact of current and future laws, rulings and governmental regulations, including guidance related to the Dodd-Frank Wall Street Reform and Consumer Protection Act;

•

shortages or cost increases of power supplies, natural gas, materials or labor;

•

hurricane or other weather interference with business operations;

•

fluctuations in the debt and equity markets;

•

accidents or other unscheduled shutdowns; and

•

general economic, market or business conditions.

Other factors described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Our forward looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward looking statement. Please also read Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part II Item 1A “Risk Factors” of this Quarterly Report.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

References in this Quarterly 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 in this Quarterly Report to “our general partner” refer to Calumet GP, LLC, the general partner of the Company.

PART I


Item 1.		*Financial Statements*

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2011			December 31, 2010
	(Unaudited)
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	15,330		$	37
Accounts receivable:
Trade		184,795			157,185
Other		461			776

		185,256			157,961
Inventories		171,929			147,110
Prepaid expenses and other current assets		1,495			1,909
Deposits		31,994			2,094

Total current assets		406,004			309,111
Property, plant and equipment, net		606,262			612,433
Goodwill		48,335			48,335
Other intangible assets, net		27,918			29,666
Other noncurrent assets, net		19,879			17,127

Total assets	$	1,108,398		$	1,016,672

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	160,173		$	146,730
Accounts payable — related party		45,509			27,985
Accrued salaries, wages and benefits		5,364			7,559
Taxes payable		7,095			7,174
Other current liabilities		4,592			16,605
Current portion of long-term debt		968			4,844
Derivative liabilities		146,746			32,814

Total current liabilities		370,447			243,711
Pension and postretirement benefit obligations		8,703			9,168
Other long-term liabilities		1,077			1,083
Long-term debt, less current portion		356,865			364,431

Total liabilities		737,092			618,393
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (39,779,778 units and 35,279,778 units issued and outstanding at March 31, 2011 and December 31, 2010, respectively)		488,233			407,773
General partner’s interest		19,841			18,125
Accumulated other comprehensive loss		(136,768	)		(27,619	)

Total partners’ capital		371,306			398,279

Total liabilities and partners’ capital	$	1,108,398		$	1,016,672

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months Ended
	March 31,
	2011			2010
	(In thousands, except per unit data)
Sales	$	605,240		$	484,616
Cost of sales		558,376			452,941

Gross profit		46,864			31,675

Operating costs and expenses:
Selling, general and administrative		10,528			7,170
Transportation		23,075			20,246
Taxes other than income taxes		1,360			1,025
Other		535			327

Operating income		11,366			2,907

Other income (expense):
Interest expense		(7,481	)		(7,434	)
Realized gain (loss) on derivative instruments		386			(561	)
Unrealized loss on derivative instruments		(417	)		(7,758	)
Other		617			(59	)

Total other expense		(6,895	)		(15,812	)

Net income before income taxes		4,471			(12,905	)
Income tax expense		270			162

Net income (loss)	$	4,201		$	(13,067	)

Allocation of net income (loss):
Net income (loss)	$	4,201		$	(13,067	)
Less:
General partner’s interest in net income (loss)		84			(261	)
Holders of incentive distribution rights		—			—

Net income (loss) available to limited partners	$	4,117		$	(12,806	)

Weighted average limited partner units outstanding — basic		36,875			35,351

Weighted average limited partner units outstanding — diluted		36,895			35,351

Limited partner unitholders’ basic and diluted net income (loss) per unit	$	0.11		$	(0.36	)

Cash distributions declared per limited partner unit	$	0.475		$	0.455

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Accumulated Other			Partners’ capital
	Comprehensive			General			Limited Partners
	Loss			Partner			Common			Subordinated			Total
	(In thousands)
Balance at December 31, 2010	$	(27,619	)	$	18,125		$	390,843		$	16,930		$	398,279
Distributions to partners		—			(338	)		(10,469	)		(6,141	)		(16,948	)
Subordinated unit conversion		—			—			10,789			(10,789	)		—
Comprehensive loss:
Net income		—			84			4,117			—			4,201
Cash flow hedge loss reclassified to net income		19,514			—			—			—			19,514
Change in fair value of cash flow hedges		(128,724	)		—			—			—			(128,724	)
Defined benefit pension and retiree health benefit plans		61			—			—			—			61

Comprehensive loss											—			(104,948	)
Proceeds from public equity offering, net		—			—			92,366			—			92,366
Contribution from Calumet GP, LLC		—			1,970			—			—			1,970
Units repurchased for phantom unit grants		—			—			(620	)		—			(620	)
Issuance of phantom units		—			—			578			—			578
Amortization of vested phantom units		—			—			629			—			629

Balance at March 31, 2011	$	(136,768	)	$	19,841		$	488,233		$	—		$	371,306

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Operating activities
Net income (loss)	$	4,201		$	(13,067	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		14,432			14,404
Amortization of turnaround costs		3,213			2,140
Non-cash interest expense		998			947
Provision for doubtful accounts		135			(91	)
Unrealized loss on derivative instruments		417			7,758
Other non-cash activities		1,338			936
Changes in assets and liabilities:
Accounts receivable		(27,430	)		(17,438	)
Inventories		(24,819	)		26,256
Prepaid expenses and other current assets		414			313
Derivative activity		4,305			1,071
Turnaround costs		(5,587	)		(940	)
Deposits		(29,900	)		5,248
Accounts payable		30,074			28,466
Accrued salaries, wages and benefits		(2,195	)		(630	)
Taxes payable		(79	)		(645	)
Other liabilities		(12,019	)		2,442
Pension and postretirement benefit obligations		(404	)		161

Net cash provided by (used in) operating activities		(42,906	)		57,331
Investing activities
Additions to property, plant and equipment		(6,566	)		(5,669	)
Proceeds from sale of equipment		59			89

Net cash used in investing activities		(6,507	)		(5,580	)
Financing activities
Proceeds from borrowings — revolving credit facility		289,791			215,056
Repayments of borrowings — revolving credit facility		(300,623	)		(248,000	)
Repayments of borrowings — term loan credit facility		(963	)		(963	)
Payments on capital lease obligations		(267	)		(372	)
Proceeds from equity offering, net		92,366			793
Contribution from Calumet GP, LLC		1,970			18
Change in bank overdraft		—			(1,650	)
Common units repurchased for vested phantom unit grants		(620	)		(248	)
Distributions to partners		(16,948	)		(16,397	)

Net cash provided by (used in) financing activities		64,706			(51,763	)

Net increase (decrease) in cash and cash equivalents		15,293			(12	)
Cash and cash equivalents at beginning of period		37			49

Cash and cash equivalents at end of period	$	15,330		$	37

Supplemental disclosure of cash flow information
Interest paid	$	7,185		$	6,944
Income taxes paid	$	—		$	8

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

1. Description of the Business

Calumet Specialty Products Partners, L.P. (the “Company”) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of March 31, 2011, the Company had 39,779,778 common units and 811,832 general partner units outstanding. The number of common units outstanding includes 13,066,000 common units that converted from subordinated units on February 16, 2011. There are no longer any subordinated units outstanding. Refer to Note 9 for additional information. The general partner owns 2% of the Company while the remaining 98% is owned by limited partners. The Company is engaged in the production and marketing of crude oil-based specialty lubricating oils, white mineral oils, solvents, petrolatums, waxes and fuels. The Company owns facilities located in Shreveport, Louisiana (“Shreveport”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”) and Dickinson, Texas (“Dickinson”) and a terminal located in Burnham, Illinois (“Burnham”).

The unaudited condensed consolidated financial statements of the Company as of March 31, 2011 and for the three months ended March 31, 2011 and 2010 included herein have been prepared, without audit, pursuant to the rules and regulations of the SEC. Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP) in the United States of America (the “U.S.”) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three months ended March 31, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2010 Annual Report. The Company issued these unaudited condensed consolidated financial statements by filing them with the SEC and have evaluated subsequent events up to the time of filing. Refer to Note 15 for additional information on these subsequent events.

2. New Accounting Pronouncements

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

3. Inventories

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

Inventories consist of the following:


	March 31,		December 31,
	2011		2010
Raw materials	$	10,755	$	12,885
Work in process		57,183		49,006
Finished goods		103,991		85,219

	$	171,929	$	147,110

The replacement cost of these inventories, based on current market values, would have been $76,948 and $55,855 higher as of March 31, 2011 and December 31, 2010, respectively.

4. Commitments and Contingencies

From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxation and regulatory authorities, such as the Louisiana Department of Environmental Quality (“LDEQ”), the U.S. Environmental Protection Agency (“EPA”), the Internal Revenue Service and the Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company. During the first quarter of 2011 the Company recorded $800 of other income related to proceeds received from its insurance claim related to the failure of an environmental operating unit at its Shreveport refinery in the first quarter of 2010. The Company is still working with its insurers to settle the claim, which could result in additional proceeds being received in future periods. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position, results of operations or cash flows.

Environmental

The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations can impair the Company’s operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company can release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, and imposing substantial liabilities for pollution resulting from its operations. Certain environmental laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes, or other materials have been released or disposed.

Failure to comply with environmental laws and regulations may result in the triggering of administrative, civil and criminal measures, including the assessment of monetary penalties, the imposition of remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the Company’s operations. On occasion, the Company receives notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. For example, the LDEQ initiated enforcement actions in prior years for the following alleged violations: (i) a May 2001 notification received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations, as identified in the course of the Company’s Leak Detection and Repair program, and also for failure to submit various reports related to the facility’s air emissions; (ii) a December 2002 notification received by the Company’s Cotton Valley refinery from the LDEQ regarding alleged violations for excess emissions, as identified in the LDEQ’s file review of the Cotton Valley refinery; (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 the LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emissions levels. On December 23, 2010, the Company entered into a settlement agreement with the LDEQ that consolidated the terms of its settlement of the aforementioned violations with the Company’s agreement to voluntarily participate in the LDEQ’s “Small Refinery and Single Site Refinery Initiative” described below.

In 2010, the Company entered into a settlement agreement with the LDEQ regarding the Company’s voluntary participation in the LDEQ’s “Small Refinery and Single Site Refinery Initiative.” This state initiative is patterned after the EPA’s “National Petroleum Refinery Initiative,” which is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. The agreement, voluntarily entered into by the Company, requires the Company to make a $1,000 payment to the LDEQ and complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries. The Company estimates implementation of these requirements will result in approximately $11,000 to $15,000 of capital expenditures, expenditures related to additional personnel and environmental studies over the next five years. This agreement also fully settles the aforementioned alleged environmental and permit violations at the Company’s Shreveport, Cotton Valley and Princeton refineries and stipulates that no further civil penalties over alleged past violations at those refineries will be pursued by the LDEQ. The required investments are expected to include projects resulting in (i) nitrogen oxide and sulfur dioxide emission reductions from heaters and boilers and the application of New Source Performance Standards for sulfur recovery plants and flaring devices, (ii) control of incidents related to acid gas flaring, tail gas and hydrocarbon flaring, (iii) electrical reliability improvements to reduce flaring, (iv) flare refurbishment at the Shreveport refinery, (v) enhancement of the Benzene Waste National Emissions Standards for Hazardous Air Pollutants programs and the Leak Detection and Repair programs at the Company’s three Louisiana refineries and (vi) Title V audits and targeted audits of certain regulatory compliance programs. During negotiations with the LDEQ, the Company voluntarily initiated projects for certain of these requirements prior to the settlement with the LDEQ, and currently anticipates completion of these projects over the next five years. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the settlement to have a material adverse effect on the Company’s financial results or operations. The Company estimates that the total additional capital expenditures above already planned levels will be approximately $1,000 to $3,000. Before the terms of this settlement agreement are deemed final, they will require the concurrence of the Louisiana Attorney General, which concurrence is anticipated to be granted during 2011.

Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. The Company incurred approximately $204 of capital expenditures at its Cotton Valley refinery during the first quarter of 2011 and estimates that it will incur another $546 of capital expenditures at its Cotton Valley refinery during the remainder of 2011 in connection with these activities. The Company incurred approximately $541 of capital expenditures at its Cotton Valley refinery during 2010.

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

Health, Safety and Maintenance

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

The Company has completed studies to assess the adequacy of its process safety management practices at its Shreveport refinery with respect to certain consensus codes and standards. The Company expects to incur between $5,000 and $8,000 of capital expenditures in total during 2011, 2012 and 2013 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards. The Company believes that its operations are in substantial compliance with OSHA and similar state laws.

Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program which is targeting all U.S. refineries for review. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the “Shreveport Citation”) to the Company as a result of the Shreveport inspection which included a proposed civil penalty amount of $173. The Company contested the Shreveport Citation and associated penalty amount and agreed to a final penalty amount of $119 that was paid in January 2011. Similarly, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under OSHA’s National Emphasis Program in the first quarter of 2011. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $208. The Company has contested the Cotton Valley Citation and associated penalties and is currently in negotiations with OSHA to reach a settlement allowing an extended abatement period for a new refinery flare system study and for completion of facility siting modifications, including relocation and hardening of structures.

Standby Letters of Credit

The Company has agreements with various financial institutions for standby letters of credit which have been issued to domestic vendors. As of March 31, 2011 and December 31, 2010, the Company had outstanding standby letters of credit of $84,893 and $90,725, respectively, under its senior secured revolving credit facility (the “revolving credit facility”), which were issued to domestic vendors. The maximum amount of letters of credit the Company can issue is limited to its borrowing capacity under its revolving credit facility or $300,000, whichever is lower. As of March 31, 2011 and December 31, 2010, the Company had availability to issue letters of credit of $225,640 and $145,454, respectively, under its revolving credit facility. As discussed in Note 5, as of March 31, 2011 the Company also had a $50,000 prefunded letter of credit outstanding under its senior secured first lien credit facility for its fuel products hedging program. Refer to Note 15 for additional information related to the termination and replacement of this letter of credit in April 2011.

5. Long-Term Debt

Long-term debt consisted of the following:


	March 31,			December 31,
	2011			2010
Borrowings under senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 4.00% (4.31% and 4.29% at March 31, 2011 and December 31, 2010, respectively), interest and principal payments quarterly with remaining borrowings due January 2015, effective interest rate of 5.39% and 5.45% for the periods ended March 31, 2011 and December 31, 2010, respectively	$	366,423		$	367,385
Borrowings under senior secured revolving credit agreement with third-party lenders, interest at prime plus 0.25% (3.50% and 3.75% at March 31, 2011 and December 31, 2010, respectively), interest payments monthly, borrowings due January 2013		—			10,832
Capital lease obligations, at various interest rates, interest and principal payments quarterly through November 2013		1,539			1,781
Less unamortized discount on senior secured first lien term loan with third-party lenders		(10,129	)		(10,723	)

Total long-term debt		357,833			369,275
Less current portion of long-term debt		968			4,844

	$	356,865		$	364,431

The Company’s $435,000 senior secured first lien credit facility included a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. The Company terminated its term loan on April 21, 2011 in connection with the issuance and sale of senior notes, as further discussed below. The term loan bore interest at a rate equal to (i) with respect to a LIBOR Loan, the LIBOR Rate plus 400 basis points (the Applicable Rate defined in the term loan credit agreement) and (ii) with respect to a Base Rate Loan, the Base Rate plus 300 basis points (as defined in the term loan credit agreement). At March 31, 2011, the term loan bore interest at 4.31%. Please refer to “Amendments to Master Derivative Contracts” below on information on termination and replacement of the $50,000 prefunded letter of credit to support crack spread hedging.

Lenders under the term loan facility had a first priority lien on the Company’s fixed assets and a second priority lien on its cash, accounts receivable, inventory and other personal property. The term loan facility required quarterly principal payments of $963 through September 30, 2014, with the remaining balance due at maturity on January 3, 2015.

The Company’s revolving credit facility has a maximum availability of up to $375,000, subject to borrowing base limitations. The revolving credit facility, which is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations, currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. As of March 31, 2011, the margin was 25 basis points for prime and 175 basis points for LIBOR; however, the margin fluctuates based on quarterly measurement of the Company’s Consolidated Leverage Ratio (as defined in the credit agreement). The revolving credit facility matures on January 3, 2013.

The borrowing capacity at March 31, 2011 under the revolving credit facility was $310,533, with $225,640 available for additional borrowings based on collateral and specified availability limitations. The revolving credit facility agreement was amended on April 21, 2011, as further discussed below. Prior to that date, the lenders under the revolving credit facility had a first priority lien on the Company’s cash, accounts receivable, inventory and other personal property and a second priority lien on the Company’s fixed assets. Please read “Seventh Amendment to Revolving Credit Facility” below for more information on how the collateral securing the Company’s obligations under the revolving credit facility changed after April 21, 2011.

Compliance with the financial covenants under the Company’s credit agreements is tested quarterly based upon performance over the most recent four fiscal quarters. As of March 31, 2011, the Company was in compliance with all financial covenants under its credit agreements.

9 3/8% Senior Notes

On April 21, 2011, the Company issued and sold $400,000 in aggregate principal amount of the Company’s 9 3/8% senior notes due May 1, 2019 (the “2019 Notes”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers. The 2019 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $389,000 net of underwriters’ fees and expenses, which the Company used to repay in full borrowings outstanding under its existing senior secured first lien term loan facility, as well as all accrued interest and fees, and for general partnership purposes. Interest on the 2019 Notes will be paid semi-annually 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 guaranteed on a senior unsecured basis by all of the Company’s operating subsidiaries and the Company’s future operating subsidiaries.

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

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


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

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

The indenture governing the 2019 Notes contains covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 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 indenture governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.

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

Registration Rights Agreement

In connection with the issuance and sale of the 2019 Notes, on April 21, 2011, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with the initial purchasers of the 2019 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2019 Notes can offer to exchange the 2019 Notes issued in the April 2011 offering for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. The Company must use reasonable best efforts to cause the exchange offer registration statement to become effective by April 20, 2012 and remain effective until 180 days after the closing of the exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2019 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

Termination of Term Loan Facility and Letter of Credit

On April 21, 2011, the Company used approximately $369,486 of the net proceeds from the issuance and sale of the 2019 Notes to repay in full its term loan and terminated the entire senior secured first lien credit facility, including the term loan and $50,000 prefunded letter of credit. The Company did not incur any material early termination penalties in connection with its termination of the senior secured first lien credit facility. Further, the Company will record in the second quarter of 2011 approximately $16,162 in extinguishment charges related to the write-off of both unamortized debt issuance costs and the discount associated with the term loan.

Seventh Amendment to Revolving Credit Facility

On April 15, 2011, the Company’s revolving credit facility was amended to, among other things, (i) permit the issuance of the 2019 Notes; (ii) upon consummation of the issuance of the 2019 Notes 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 as follows:


Consolidated	Margin on Base Rate			Margin on LIBOR
Leverage Ratio	Revolving Loans			Revolving Loans
< 2.75 to 1.0		0.50	%		2.00	%
≥ 2.75 to 1.0 but < 3.25 to 1.0		0.75	%		2.25	%
≥ 3.25 to 1.0		1.00	%		2.50	%

Amendments to Master Derivative Contracts

In connection with the issuance and sale of the 2019 Notes, on April 21, 2011, the Company entered into certain (“Amendments”) to the Company’s master derivatives contracts to provide new credit support arrangements to secure the Company’s payment obligations under these contracts following the issuance and sale of the 2019 Notes. Under the new credit support arrangements, the Company’s payment obligations under all of the Company’s master derivatives contracts for commodity hedging will be secured by a first priority lien on the Company’s real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). The Company also issued to one counterparty a $25,000 letter of credit under the revolving credit facility to replace a prefunded $50,000 letter of credit previously issued under the first lien senior secured credit facility that secured, in part, the Company’s payment obligations prior to the Company’s termination of the first lien senior credit facility. In the event the counterparty’s exposure to the Company exceeds $150,000, the Company will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges up to the aforementioned maximum volume. The Company’s master derivatives contracts will continue to impose a number of covenant limitations on the Company’s operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.

In connection with the Amendments, on April 21, 2011, the Company entered into a collateral sharing agreement with each of its secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties. The collateral sharing agreement also governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by the Company to the secured hedging counterparties under their respective master derivatives contracts. Under the collateral sharing agreement, the Company has the ability to add secured hedging counterparties to the collateral sharing agreement. The collateral pledged under this agreement consists primarily of property, plant and equipment.

As of March 31, 2011, maturities of the Company’s long-term debt, based upon the April 21, 2011 debt issuance, are as follows:


Year	Maturity
2011	$	751
2012		551
2013		237
2014		—
2015		—
Thereafter		366,423

Total	$	367,962

6. Derivatives

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

The Company recognizes all derivative instruments at their fair values (see Note 8) as either assets or liabilities on the condensed consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The Company recorded the following derivative assets and liabilities at their fair values as of March 31, 2011 and December 31, 2010:


	Derivative Assets				Derivative Liabilities
	March 31, 2011		December 31, 2010		March 31, 2011			December 31, 2010
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	—	$	—	$	249,167		$	134,916
Gasoline swaps		—		—		(121,465	)		(14,149	)
Diesel swaps		—		—		(244,636	)		(53,744	)
Jet fuel swaps		—		—		(27,087	)		(96,556	)
Interest rate swaps:		—		—		(1,634	)		(2,681	)

Total derivative instruments designated as hedges		—		—		(145,655	)		(32,214	)

Derivative instruments not designated as hedges:
Fuel products segment:
Jet fuel crack spread collars (1)		—		—		—			20
Specialty products segment: (2)
Crude oil collars		—		—		—			—
Natural gas swaps		—		—		—			—
Crude oil swaps		—		—		—			662
Interest rate swaps: (3)		—		—		(1,091	)		(1,282	)

Total derivative instruments not designated as hedges		—		—		(1,091	)		(600	)

Total derivative instruments	$	—	$	—	$	(146,746	)	$	(32,814	)


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

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

(3)		The Company refinanced its long-term debt in January 2008 and, as a result, the interest rate swap that was designated as a hedge of the interest payments under the previous debt agreement no longer qualified for hedge accounting. To offset the effect of this interest rate swap, the Company entered into another interest rate swap. These two derivative instruments are netted on this line item and the Company is settling this net position over the term of the derivative instruments.

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

For derivative instruments not designated as cash flow hedges and the portion of any cash flow hedge that is determined to be ineffective, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations.

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


	Amount of Gain (Loss)
	Recognized in
	Accumulated Other						Amount of (Gain) Loss Reclassified from
	Comprehensive Income (Loss)						Accumulated Other Comprehensive							Amount of Gain (Loss) Recognized in Net
	on Derivatives						Income (Loss) into Net Income (Loss)							Income (Loss) on Derivatives
	(Effective Portion)						(Effective Portion)							(Ineffective Portion)
								Three Months Ended							Three Months Ended
	March 31,						Location of (Gain)	March 31,						Location of Gain	March 31,
Type of Derivative	2011			2010			Loss	2011			2010			(Loss)	2011			2010
Fuel products segment:
Crude oil swaps	$	136,946		$	16,481		Cost of sales	$	(19,101	)	$	(17,508	)	Unrealized/ Realized	$	1,219		$	(6,473	)
Gasoline swaps		(19,110	)		(5,841	)	Sales		6,239			5,184		Unrealized/ Realized		(461	)		(1,535	)
Diesel swaps		(96,322	)		(8,566	)	Sales		18,113			5,808		Unrealized/ Realized		(557	)		(1,181	)
Jet fuel swaps		(150,583	)		(7,224	)	Sales		13,561			—		Unrealized/ Realized		(476	)		—
Specialty products segment:
Crude oil collars		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Crude oil swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Natural gas swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Interest rate swaps:		345			(949	)	Interest expense		702			786		Unrealized/ Realized		—			—

Total	$	(128,724	)	$	(6,099	)		$	19,514		$	(5,730	)		$	(275	)	$	(9,189	)

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


	Amount of Gain (Loss) Recognized in						Amount of Gain (Loss) Recognized
	Realized Gain (Loss) on Derivatives						in Unrealized Gain (Loss) on Derivatives
	Three Months Ended						Three Months Ended
	March 31,						March 31,
Type of Derivative	2011			2010			2011			2010
Fuel products segment:
Crude oil swaps	$	—		$	(2,235	)	$	—		$	1,572
Gasoline swaps		—			3,394			—			(2,042	)
Diesel swaps		—			(325	)		—			325
Jet fuel swaps		—			—			—			—
Jet fuel collars		(562	)		—			543			(126	)
Specialty products segment:
Crude oil collars		—			(771	)		—			977
Crude oil swaps		932			24			(662	)		51
Natural gas swaps		—			(35	)		—			—
Interest rate swaps:		(199	)		(200	)		192			261

Total	$	171		$	(148	)	$	73		$	1,018

The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company executes all of its derivative instruments with large financial institutions that have ratings of at least A2 and A by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark to market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed upon thresholds in its contracts with these counterparties. No such collateral was held by the Company as of March 31, 2011 or December 31, 2010. The Company’s contracts with these counterparties allow for netting of derivative instrument positions executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits on the Company’s condensed consolidated balance sheets and not netted against derivative assets or liabilities. As of March 31, 2011, the Company had provided its counterparties with $28,900 cash collateral above the $50,000 prefunded letter of credit provided to one counterparty to support crack spread hedging. As of December 31, 2010, the Company had provided its counterparties with no cash collateral or letters of credit above the $50,000 prefunded letter of credit provided to one counterparty to support crack spread hedging. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.

Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating was lowered below its current level by either Moody’s or S&P, such counterparties would have the right to reduce the applicable threshold to zero and demand full collateralization of the Company’s net liability position on outstanding derivative instruments. As of March 31, 2011 and December 31, 2010, there was a net liability of $1,712 and $388, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business. The effective portion of the hedges classified in accumulated other comprehensive loss is $131,976 as of March 31, 2011 and, absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2013 with balances being recognized as follows:


	Accumulated Other
	Comprehensive
Year	Loss
2011	$	(47,809	)
2012		(80,701	)
2013		(3,466	)

Total	$	(131,976	)

Based on fair values as of March 31, 2011, the Company expects to reclassify $69,587 of net losses on derivative instruments from accumulated other comprehensive income (loss) to earnings during the next twelve months due to actual crude oil purchases, gasoline, diesel and jet fuel sales, and the payment of variable interest associated with floating rate debt. However, the amounts actually realized will be dependent on the fair values as of the date of settlements.

Crude Oil Swap and Collar Contracts — Specialty Products Segment

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

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


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

Totals		70,800
Average price					$	83.34

Crude Oil Swap Contracts — Fuel Products Segment

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


					Average
	Barrels				Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Second Quarter 2011		1,774,000		19,495	$	77.03
Third Quarter 2011		1,610,000		17,500		77.38
Fourth Quarter 2011		1,334,000		14,500		77.71
Calendar Year 2012		5,626,000		15,372		86.63
Calendar Year 2013		1,125,000		3,082		101.50

Totals		11,469,000
Average price					$	84.27

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


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

Totals		11,423,000
Average price					$	81.41

Fuel Products Swap Contracts

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

Diesel Swap Contracts

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


					Average
					Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2011		637,000		7,000	$	89.57
Third Quarter 2011		552,000		6,000		91.74
Fourth Quarter 2011		552,000		6,000		91.74
Calendar Year 2012		1,651,000		4,511		101.08

Totals		3,392,000
Average price					$	95.88

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


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

Totals		3,931,000
Average price					$	94.03

Jet Fuel Swap Contracts

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


					Average
					Swap
Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2011		819,000		9,000	$	89.58
Third Quarter 2011		920,000		10,000		89.86
Fourth Quarter 2011		644,000		7,000		89.21
Calendar Year 2012		3,838,500		10,488		99.78
Calendar Year 2013		945,000		2,589		126.36

Totals		7,166,500
Average price					$	99.90

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


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

Totals		6,626,500
Average price					$	95.28

Gasoline Swap Contracts

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


					Average
					Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2011		318,000		3,495	$	85.95
Third Quarter 2011		138,000		1,500		85.50
Fourth Quarter 2011		138,000		1,500		85.50
Calendar Year 2012		136,500		373		89.04
Calendar Year 2013		180,000		493		110.38

Totals		910,500
Average price					$	91.11

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


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

Totals		865,500
Average price					$	84.40

Jet Fuel Put Spread Contracts

At March 31, 2011 the Company had the following jet fuel put options related to jet fuel crack spreads in its fuel products segment, none of which are designated as hedges.


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

Totals		184,000
Average price					$	4.75	$	7.00

At December 31, 2010, the Company had the following jet fuel put options related to jet fuel crack spreads in its fuel products segment, none of which are designated as hedges.


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

Totals		814,000
Average price					$	4.17	$	6.23

Natural Gas Swap Contracts

Natural gas purchases comprise a significant component of the Company’s cost of sales; therefore, changes in the price of natural gas also significantly affect its profitability and cash flows. The Company utilizes swap contracts to manage natural gas price risk and volatility of cash flows. The Company’s policy is generally to enter into natural gas derivative contracts to hedge approximately 50% or more of its upcoming fall and winter months’ anticipated natural gas requirement for a period no greater than three years forward. At March 31, 2011 and December 31, 2010, the Company had no derivatives outstanding related to natural gas purchases.

Interest Rate Swap Contracts

The Company’s profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of the Company’s interest rate risk management activities is to hedge its exposure to changes in interest rates. Historically, the Company’s policy has been to enter into interest rate swap agreements to hedge up to 75% of its interest rate risk related to variable rate debt.

During 2010, the Company entered into forward swap contracts to manage interest rate risk related to a portion of its current variable rate senior secured first lien term loan. The Company hedged the future interest payments related to $100,000 of the total outstanding term loan indebtedness for the period from February 15, 2011 to February 15, 2012 pursuant to these forward swap contracts. These swap contracts are designated as cash flow hedges of the future payments of interest with three-month LIBOR fixed at an average rate during the hedge period of 2.03%.

In 2009, the Company hedged the future interest payments related to $200,000 of the total outstanding term loan indebtedness for the period from February 15, 2010 to February 15, 2011. This swap contract is designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at an average rate during the hedge period of 0.94%.

In 2008, the Company entered into a forward swap contract to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan which closed January 3, 2008. The Company hedged the future interest payments related to $150,000 and $50,000 of the total outstanding term loan indebtedness in 2009 and 2010, respectively, pursuant to this forward swap contract. This swap contract is designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at 3.09% and 3.66% per annum in 2009 and 2010, respectively.

In 2006, the Company entered into a forward swap contract to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan. Due to the repayment of $19,000 of the outstanding balance of the Company’s then existing term loan facility in August 2007 and subsequent refinancing of the remaining term loan balance, this 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 is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. In the first quarter of 2008, the Company fixed its unrealized loss on this interest rate swap derivative instrument by entering into an offsetting interest rate swap expiring December 2012 which is not designated as a cash flow hedge.

7. Fair Value of Financial Instruments

The Company’s financial instruments which require fair value disclosure consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and indebtedness. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The fair value of the Company’s term loan was $366,423 and $355,445 at March 31, 2011 and December 31, 2010, respectively. The carrying values of borrowings under the Company’s senior secured revolving credit facility were $0 and $10,832 at March 31, 2011 and December 31, 2010, respectively, and approximate their fair values. In addition, based upon fees charged for similar agreements, the face values of outstanding standby letters of credit approximated their fair values at March 31, 2011 and December 31, 2010.

8. Fair Value Measurements

The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded, and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants, and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.

As of March 31, 2011, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to crude oil, gasoline, diesel, jet fuel and interest rates and investments associated with the Company’s non-contributory defined benefit plan (“Pension Plan”).

The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least A2 and A by Moody’s and S&P, respectively. To estimate the fair values of the Company’s derivative instruments, the entity uses the market approach. Under this approach, the fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, jet fuel and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the Company obtains this data through surveying its counterparties and performing various analytical tests to validate the data. The Company determines the fair value of its crude oil option contracts utilizing a standard option pricing model based on inputs that can be derived from information available in publicly quoted markets, or are quoted by counterparties to these contracts. In situations where the Company obtains inputs via quotes from its counterparties, it verifies the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. The Company also includes an adjustment for non-performance risk in the recognized measure of fair value of all of the Company’s derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When the Company is in a net asset position, it uses its counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. The Company uses its own peer group’s estimated CDS when it is in a net liability position. As a result of applying the applicable CDS, at March 31, 2011 and December 31, 2010, the Company’s liability was reduced by approximately $2,439 and $687, respectively. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for gasoline, jet fuel and diesel, the Company has categorized these derivative instruments as Level 3. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds.

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

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


	Fair Value Measurements
	Level 1		Level 2 (a)		Level 3			Total
Assets:
Cash and cash equivalents	$	15,330	$	—	$	—		$	15,330
Crude oil swaps		—		—		249,167			249,167
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Pension plan investments		14,703		2,032		—			16,735

Total assets at fair value	$	30,033	$	2,032	$	249,167		$	281,232

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(121,465	)		(121,465	)
Diesel swaps		—		—		(244,636	)		(244,636	)
Jet fuel swaps		—		—		(27,087	)		(27,087	)
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(2,725	)		(2,725	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(395,913	)	$	(395,913	)


(a)		Transferred from Level 1 to Level 2 because of lack of observable market data in the underlying investments.

The Company’s financial assets and liabilities measured at fair value at December 31, 2010 were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Cash and cash equivalents	$	37	$	—	$	—		$	37
Crude oil swaps		—		—		135,578			135,578
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Crude oil options		—		—		—			—
Jet fuel options		—		—		20			20
Pension plan investments		16,039		—		—			16,039

Total assets at fair value	$	16,076	$	—	$	135,598		$	151,674

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(14,149	)		(14,149	)
Diesel swaps		—		—		(53,744	)		(53,744	)
Jet fuel swaps		—		—		(96,556	)		(96,556	)
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(3,963	)		(3,963	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(168,412	)	$	(168,412	)

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the three months ended March 31, 2011 and March 31, 2010:


	Three Months Ended
	March 31,
	2011			2010
Fair value at January 1,	$	(32,814	)	$	26,138
Realized losses (gains)		(386	)		561
Unrealized losses		(417	)		(7,758	)
Change in fair value of cash flow hedges		(128,724	)		(6,099	)
Settlements		15,595			(7,362	)
Transfers in (out) of Level 3		—			—

Fair value at March 31,	$	(146,746	)	$	5,480

Total (losses) gains included in net income attributable to changes in unrealized (losses) gains relating to financial assets and liabilities held as of March 31	$	(417	)	$	(7,758	)

All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives, cost of sales for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in the unaudited condensed consolidated financial statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments are recorded in earnings immediately in unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 6 for further information on derivative instruments.

9. Partners’ Capital

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

On February 24, 2011, the Company completed an equity offering of its common units in which it sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $92,366 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $3,915. The Company’s general partner contributed $1,970 to retain its 2% general partner interest.

10. Comprehensive Loss

Comprehensive loss for the Company includes the change in fair value of cash flow hedges and the minimum pension liability adjustment that have not been recognized in net income. Comprehensive loss for the three months ended March 31, 2011 and 2010 was as follows:


	Three Months Ended
	March 31,
	2011			2010
Net income (loss)	$	4,201		$	(13,067	)
Cash flow hedge gain reclassified to net income (loss)		19,514			(5,730	)
Change in fair value of cash flow hedges		(128,724	)		(6,099	)
Defined benefit pension and retiree health benefit plans		61			405

Total comprehensive loss	$	(104,948	)	$	(24,491	)

11. Unit-Based Compensation and Distributions

A summary of the Company’s nonvested phantom units as of March 31, 2011 and the changes during the three months ended March 31, 2011 is presented below:


				Weighted Average
				Grant Date
Nonvested Phantom Units	Grant			Fair Value
Nonvested at December 31, 2010		105,492		$	17.68
Granted		40,673			21.35
Vested		(43,573	)		19.39
Forfeited		—			—

Nonvested at March 31, 2011		102,592		$	18.41

For the three months ended March 31, 2011 and 2010, compensation expense of $629 and $147, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. As of March 31, 2011 and 2010, there was a total of $1,888 and $869, respectively, of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately three years.

The Company’s distribution policy is as defined in its partnership agreement. For the three months ended March 31, 2011 and 2010, the Company made distributions of $16,948 and $16,397, respectively, to its partners.

12. Employee Benefit Plans

The components of net periodic pension and other post retirement benefits cost for the three months ended March 31, 2011 and 2010 were as follows:


	For the Three Months Ended March 31,
	2011						2010
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	24		$	—		$	21		$	—
Interest cost		333			5			334			6
Expected return on assets		(264	)		—			(259	)		—
Amortization of net (gain) loss		70			(1	)		69			(1	)
Prior service cost		—			(9	)		—			(9	)

Net periodic benefit cost	$	163		$	(5	)	$	165		$	(4	)

During the three months ended March 31, 2011 and 2010, the Company made contributions of $562 and $0 to its non-contributory defined benefit plan (its “Pension Plan”) and expects to make total contributions to its Pension Plan in 2011 of $1,685.


	March 31, 2011				December 31, 2010
	Pension Benefits				Pension Benefits
	Level 1		Level 2		Level 1		Level 2
Cash	$	3,593	$	—	$	347	$	—
Equity		4,208		—		7,784		—
Foreign equities		833		—		1,890		—
Commingled fund		—		2,032		—		—
Fixed income		6,069		—		6,018		—

	$	14,703	$	2,032	$	16,039	$	—

13. Transactions with Related Parties

On March 24, 2011, Calumet Lubricants Co., Limited Partnership (“Calumet Lubricants”), a wholly owned subsidiary of the Company, entered into Amendment No. 5 (the “Princeton Amendment”) to that certain Crude Oil Supply Agreement, effective as of April 30, 2008 (as amended since such date, the “Princeton Crude Oil Supply Agreement”), by and between Calumet Lubricants and Legacy Resources Co., L.P. (“Legacy”), under which Legacy supplies the Company’s Princeton refinery with all of the refinery’s crude oil requirements on a just-in-time basis. The Princeton Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Princeton Crude Oil Supply Agreement and shortened the termination notice period set forth in the Princeton Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Princeton Amendment, on March 24, 2011, Calumet Lubricants provided notice to Legacy that it was exercising its contractual rights under the Princeton Crude Oil Supply Agreement, as amended by the Princeton Amendment, to terminate the Princeton Crude Oil Supply Agreement on May 31, 2011. The Company will not incur any material early termination penalties in connection with its termination of the Princeton Crude Oil Supply Agreement.

On March 24, 2011, Calumet Shreveport Fuels, LLC (“Calumet Shreveport Fuels”), a wholly owned subsidiary of the Company, entered into Amendment No. 5 (the “Shreveport Amendment”) to that certain Crude Oil Supply Agreement, effective as of September 1, 2009 (as amended since such date, the “Shreveport Crude Oil Supply Agreement”), by and between Calumet Shreveport Fuels and Legacy, under which Legacy supplies the Company’s Shreveport refinery with a portion of the refinery’s crude oil requirements on a just-in-time basis. The Shreveport Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Shreveport Crude Oil Supply Agreement and shortened the termination notice period set forth in the Shreveport Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Shreveport Amendment, on March 24, 2011, Calumet Shreveport Fuels provided notice to Legacy that it was exercising its contractual rights under the Shreveport Crude Oil Supply Agreement, as amended by the Shreveport Amendment, to terminate the Shreveport Crude Oil Supply Agreement on May 31, 2011. The Company will not incur any material early termination penalties in connection with its termination of the Shreveport Crude Oil Supply Agreement.

With the termination of the agreements, the Company will have one remaining crude oil supply agreement with Legacy, the Master Crude Oil Purchase and Sale Agreement, that was entered into on January 26, 2009. No crude oil is currently being purchased by the Company under this agreement.

Legacy is owned in part by three of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and vice chairman, F. William Grube, and the Company’s president and chief operating officer, Jennifer G. Straumins. During the three months ended March 31, 2011, the Company had crude oil purchases of $193,251 from Legacy. Accounts payable to Legacy at March 31, 2011 were $44,628.

14. Segments and Related Information

a. Segment Reporting

The Company has two reportable segments: Specialty Products and Fuel Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes and asphalt and other by-products. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The Fuel Products segment produces a variety of fuel and fuel-related products including gasoline, diesel and jet fuel. Because of the similar economic characteristics, certain operations have been aggregated for segment reporting purposes.

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


	Specialty		Fuel			Combined					Consolidated
Three Months Ended March 31, 2011	Products		Products			Segments		Eliminations			Total
Sales:
External customers	$	397,102	$	208,138		$	605,240	$	—		$	605,240
Intersegment sales		216,077		3,635			219,712		(219,712	)		—

Total sales	$	613,179	$	211,773		$	824,952	$	(219,712	)	$	605,240

Depreciation and amortization		18,643		—			18,643		—			18,643
Operating income (loss)		15,682		(4,316	)		11,366		—			11,366
Reconciling items to net income:
Interest expense												(7,481	)
Loss on derivative instruments												(31	)
Other												617
Income tax expense												(270	)

Net income											$	4,201

Capital expenditures	$	6,566	$	—		$	6,566	$	—		$	6,566


	Specialty			Fuel		Combined					Consolidated
Three Months Ended March 31, 2010	Products			Products		Segments		Eliminations			Total
Sales:
External customers	$	305,476		$	179,140	$	484,616	$	—		$	484,616
Intersegment sales		174,607			10,789		185,396		(185,396	)		—

Total sales	$	480,083		$	189,929	$	670,012	$	(185,396	)	$	484,616

Depreciation and amortization		17,491			—		17,491		—			17,491
Operating income (loss)		(2,638	)		5,545		2,907		—			2,907
Reconciling items to net loss:
Interest expense												(7,434	)
Loss on derivative instruments												(8,319	)
Other												(59	)
Income tax expense												(162	)

Net loss											$	(13,067	)

Capital expenditures	$	5,669		$	—	$	5,669	$	—		$	5,669


	March 31, 2011			December 31, 2010
Segment assets:
Specialty products	$	4,043,061		$	3,617,937
Fuel products		3,296,689			2,908,760

Combined segments		7,339,750			6,526,697
Eliminations		(6,231,352	)		(5,510,025	)

Total assets	$	1,108,398		$	1,016,672

b. Geographic Information

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

c. Product Information

The Company offers products primarily in five general categories consisting of lubricating oils, solvents, waxes, fuels and asphalt and by-products. Fuel products primarily consist of gasoline, diesel, jet fuel and by-products. The following table sets forth the major product category sales:


	Three Months Ended March 31,
	2011		2010
Specialty products:
Lubricating oils	$	209,052	$	164,048
Solvents		118,336		87,853
Waxes		34,307		26,246
Fuels		830		1,738
Asphalt and other by-products		34,577		25,591

Total	$	397,102	$	305,476

Fuel products:
Gasoline		95,781		75,883
Diesel		82,152		64,230
Jet fuel		26,773		37,564
By-products		3,432		1,463

Total	$	208,138	$	179,140

Consolidated sales	$	605,240	$	484,616

d. Major Customers

During the three months ended March 31, 2011 and 2010, the Company had no customer that represented 10% or greater of consolidated sales.

15. Subsequent Events

On April 8, 2011, the Company declared a quarterly cash distribution of $0.475 per unit on all outstanding units, or $19,311, for the quarter ended March 31, 2011. The distribution will be paid on May 13, 2011 to unitholders of record as of the close of business on May 3, 2011. This quarterly distribution of $0.475 per unit equates to $1.90 per unit, or $77,244 on an annualized basis.

The fair value of the Company’s derivatives has not changed materially subsequent to March 31, 2011. As of May 6, 2011, the Company had $28,400 in cash margin posted with one counterparty to support crack spread hedging.

On April 21, 2011 the Company issued and sold $400,000 in aggregate principal amount 9 3/8% Senior Notes due 2019. In connection therewith, on April 21, 2011, the Company paid in full and terminated its senior secured first lien credit facility, which included its term loan and $50,000 prefunded letter of credit facility to support crack spread hedging, and entered into certain amendments to the Company’s master derivatives contracts to provide new credit support arrangements to secure the Company’s payment obligations under these contracts. Additionally, in connection with the amendments to the master derivative contracts, the Company entered into a collateral sharing agreement with each of its secured hedging counterparties and an administrative agent for the benefit of the secured hedge counterparties. Refer to Note 5 for further discussion.


Item 2.		*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

The historical consolidated financial statements included in this Quarterly Report reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet,” the “Company,” “we,” “our,” “us”). The following discussion analyzes the financial condition and results of operations of Calumet for the three months ended March 31, 2011 and 2010. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Calumet in conjunction with our 2010 Annual Report and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.

Overview

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We own plants located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport, Louisiana, Karns City, Pennsylvania and a terminal located in Burnham, Illinois. 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 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 and jet fuel. In connection with our production of specialty products and fuel products, we also produce asphalt and a limited number of other by-products.

First Quarter 2011 Update

For the three months ended March 31, 2011 and 2010, 54.9% and 52.8%, respectively, of our sales volume and 102.2% and 74.0%, respectively, of our gross profit was generated from our specialty products segment while, for the same period, 45.1% and 47.2%, respectively, of our sales volume and (2.2)% and 26.0%, respectively, of our gross profit was generated from our fuel products segment.

We noted continued improvement in our specialty products segment during the first quarter of 2011. The trend of increased demand for our specialty products has continued, with specialty products segment sales volume increasing 7.9% for the quarter ended March 31, 2011 compared to the same period in 2010. Specialty products segment generated a gross profit margin of 12.1% in the first quarter of 2011 under these improved product demand conditions, as compared to a gross profit margin of 7.7% for the same period in the prior year.

While fuel products refining margins significantly strengthened during the first quarter, our fuel products segment did not fully realize the impact of these higher crack spreads due to planned turnaround activities at our Shreveport refinery and weather-related unplanned downtime during the first quarter, which resulted in a higher percentage of our fuel products segment sales being hedged at crack spreads that were significantly lower than current market prices. We recorded realized crack spread derivative losses of $18.8 million during the first quarter in our fuel products segment. We expect to benefit more significantly going forward from the higher crack spread market environment as our overall production rates have increased subsequent to the completion of the first quarter turnaround activities at the Shreveport refinery.

Our first quarter 2011 production increased by 12.8% over our production levels for the first quarter of 2010, due primarily to the increases in production rates at our Shreveport refinery due to better fuel refining crack spreads in the first quarter of 2011, as well as the impact of the failure of an environmental operating unit in the first quarter of 2010 with no similar activity in 2011, partially offset by a planned turnaround during the first quarter of 2011. Production levels at our other facilities, which focus on the production of specialty products, also increased quarter over quarter to take advantage of higher specialty products demand.

We used $42.9 million in cash flows from operating activities during the first quarter of 2011 primarily due to increased working capital requirements resulting from increased run rates at our Shreveport facility subsequent to the completion of turnaround activities during the quarter and due to higher commodity prices in general. We expect additional use of operating cash flows during the second quarter of 2011 related to increased crude oil inventory levels as a result of terminating certain just-in-time inventory supply arrangements with a related party, Legacy, effective May 31, 2011. We plan to continue focusing our efforts on generating positive cash flows from operations which we expect will be used to (i) improve our liquidity position, (ii) pay quarterly distributions to our unitholders, (iii) service our debt obligations and (iv) provide funding for general partnership purposes.

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. Please read Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.” As of March 31, 2011, we have hedged approximately 11.5 million barrels of fuel products through March 2013 at an average refining margin of $13.74 per barrel with average refining margins ranging from a low of $11.89 per barrel in 2011 to a high of $22.30 per barrel in 2013. Please refer to Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” and Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Existing Commodity Derivative Instruments” for detailed information regarding our derivative instruments.

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 2/1/1 or 3/2/1 market crack spread due to many factors, including 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 at the Shreveport refinery to the fuel products segment, operating costs including fixed costs, derivative activity to hedge our fuel products segment revenues and cost of crude oil reflected in gross profit and our local market pricing differential in Shreveport, Louisiana as compared to U.S. Gulf Coast postings.

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 for the Three Months Ended March 31, 2011 and 2010

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


	Three Months Ended March 31,
	2011		2010
	(In bpd)
Total sales volume (1)		53,556		51,700
Total feedstock runs (2)		56,085		48,331
Facility production: (3)
Specialty products:
Lubricating oils		13,779		11,279
Solvents		10,127		8,070
Waxes		1,059		1,009
Fuels		633		1,150
Asphalt and other by-products		8,024		5,766

Total		33,622		27,274

Fuel products:
Gasoline		8,964		8,777
Diesel		10,763		8,986
Jet fuel		3,165		5,254
By-products		556		297

Total		23,448		23,314

Total facility production (3)		57,070		50,588


(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.

(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 feedstock runs for the three months ended March 31, 2011 compared to the same quarter in 2010 is due primarily to the decision to increase crude oil run rates at our facilities during the entire first quarter of 2011 because of favorable economics of running additional barrels, partially offset by a planned turnaround at our Shreveport refinery.

(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 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 feedstock and production of finished products and volume loss. The increase in production of specialty products in the first quarter of 2011 compared to the same quarter in 2010 is due primarily to higher throughput rates at our Princeton and Shreveport refineries quarter over quarter, as well as increased volumes under our agreements with LyondellBasell, partially offset by planned turnaround at activities our Shreveport refinery during the first quarter of 2011.

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 (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated in accordance with GAAP, please read “—Non-GAAP Financial Measures.”


	Three Months Ended March 31,
	2011			2010
	(In thousands)
Sales	$	605,240		$	484,616
Cost of sales		558,376			452,941

Gross profit		46,864			31,675

Operating costs and expenses:
Selling, general and administrative		10,528			7,170
Transportation		23,075			20,246
Taxes other than income taxes		1,360			1,025
Other		535			327

Operating income		11,366			2,907

Other income (expense):
Interest expense		(7,481	)		(7,434	)
Realized gain (loss) on derivative instruments		386			(561	)
Unrealized loss on derivative instruments		(417	)		(7,758	)
Other		617			(59	)

Total other expense		(6,895	)		(15,812	)

Net income (loss) before income taxes		4,471			(12,905	)
Income tax expense		270			162

Net income (loss)	$	4,201		$	(13,067	)

Adjusted EBITDA	$	34,653		$	20,123

Distributable Cash Flow	$	18,222		$	7,085

Non-GAAP Financial Measures

We include in this Quarterly 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 (loss) and net cash provided (used in) 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 plus interest expense (including debt issuance and extinguishment costs), taxes and depreciation and amortization. We define Adjusted EBITDA for any period as: (1) net income 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; (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; (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 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 that are presented in this Quarterly Report have been updated to reflect the calculation of “Consolidated Cash Flow” contained in the indenture governing our 2019 Notes. 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 Quarterly Report for prior periods have been updated to reflect the use of the new calculations and are not materially different from the amounts previously reported. Please refer to “Liquidity and Capital Resources — Debt and Credit Facilities” within this item 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, operating income, net cash provided by 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 table presents a reconciliation of both net income (loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.


	Three Months Ended
	March 31,
	2011		2010
	(In thousands)
Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA and Distributable Cash Flow:
Net income (loss)	$	4,201	$	(13,067	)
Add:
Interest expense		7,481		7,434
Depreciation and amortization		14,432		14,404
Income tax expense		270		162

EBITDA	$	26,384	$	8,933

Add:
Unrealized loss on derivatives	$	417	$	7,758
Realized gain on derivatives, not included in net income		3,743		1,070
Amortization of turnaround costs		3,213		2,140
Non-cash equity based compensation		896		222

Adjusted EBITDA	$	34,653	$	20,123

Less:
Replacement capital expenditures (1)		4,091		5,449
Cash interest expense (2)		6,483		6,487
Turnaround costs		5,587		940
Income tax expense		270		162

Distributable Cash Flow	$	18,222	$	7,085


(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.


	Three Months Ended
	March31,
	2011			2010
	(In thousands)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities:
Distributable Cash Flow	$	18,222		$	7,085
Add:
Replacement capital expenditures (1)		4,091			5,449
Turnaround costs		5,587			940
Cash interest expense (2)		6,483			6,487
Income tax expense		270			162

Adjusted EBITDA	$	34,653		$	20,123

Less:
Unrealized loss on derivative instruments		417			7,758
Realized gains on derivatives, not included in net income		3,743			1,070
Non-cash equity based compensation		896			222
Amortization of turnaround costs		3,213			2,140

EBITDA	$	26,384		$	8,933

Add:
Unrealized loss on derivative instruments		417			7,758
Cash interest expense (2)		(6,483	)		(6,487	)
Non-cash equity based compensation		896			222
Amortization of turnaround costs		3,213			2,140
Income tax expense		(270	)		(162	)
Provision for doubtful accounts		135			(91	)
Changes in assets and liabilities:
Accounts receivable		(27,430	)		(17,438	)
Inventory		(24,819	)		26,256
Other current assets		(29,486	)		5,561
Turnaround costs		(5,587	)		(940	)
Derivative activity		4,305			1,071
Accounts payable		30,074			28,466
Other liabilities		(14,293	)		1,167
Other, including changes in noncurrent assets and liabilities		38			875

Net cash provided by (used in) operating activities	$	(42,906	)	$	57,331


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

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

Changes in Results of Operations for the Three Months Ended March 31, 2011 and 2010

Sales. Sales increased $120.6 million, or 24.9%, to $605.2 million in the three months ended March 31, 2011 from $484.6 million in the same period in 2010. Sales for each of our principal product categories in these periods were as follows:


	Three Months Ended March 31,
	2011		2010		% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	209,052	$	164,048		27.4	%
Solvents		118,336		87,853		34.7	%
Waxes		34,307		26,246		30.7	%
Fuels (1)		830		1,738		(52.2	)%
Asphalt and by-products (2)		34,577		25,591		35.1	%

Total specialty products	$	397,102	$	305,476		30.0	%

Total specialty products sales volume (in barrels)		2,648,000		2,455,000		7.9	%
Average specialty products sales price per barrel	$	149.96	$	124.43		20.5	%
Fuel products:
Gasoline	$	95,781	$	75,883		26.2	%
Diesel		82,152		64,230		27.9	%
Jet fuel		26,773		37,564		(28.7	)%
By-products (3)		3,432		1,463		134.6	%

Total fuel products	$	208,138	$	179,140		16.2	%

Total fuel products sales volume (in barrels)		2,172,000		2,198,000		(1.2	)%
Average fuel products sales price per barrel (4)	$	95.83	$	81.50		17.6	%
Total sales	$	605,240	$	484,616		24.9	%

Total sales volume (in barrels)		4,820,000		4,653,000		3.6	%


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

(4)		Average fuel products sales price per barrel includes impact of hedging contracts.

Specialty products segment sales for the three months ended March 31, 2011 increased $91.6 million, or 30.0%, as a result of an increase in the average selling price per barrel of $25.53, or 20.5%, and a 7.9% increase in sales volume as compared to the same period in 2010. Specialty products average selling prices per barrel increased in all product categories, with lubricating oils and solvents experiencing the most significant increases, driven by improving overall demand and a 21.3% increase in the average cost of crude oil per barrel for the 2011 period as compared to the same period in 2010. The increased volume is due primarily to improving overall specialty products demand as a result of improved economic conditions.

Fuel products segment sales for the three months ended March 31, 2011 increased $29.0 million, or 16.2%, due primarily to an increase in the average selling price per barrel (excluding the impact of hedging activities) of $26.81, or 31.0%, driven by market conditions compared to a 21.4% increase in the average price of crude oil per barrel. The average selling price per barrel increased for all fuel products, with diesel selling prices experiencing the most significant increases driven by improved market pricing. This increase was partially offset by a 1.2% decrease in sales volume due primarily to decreased volume of jet fuel as a result of planned turnaround activities at the Shreveport refinery during the first quarter 2011. Also contributing to the change was a $26.9 million increase in 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 hedges.

Gross Profit. Gross profit increased $15.2 million, or 48.0%, to $46.9 million in the three months ended March 31, 2011 from $31.7 million in the same period in 2010. Gross profit for our specialty products and fuel products segments was as follows:


	Three Months Ended March 31,
	2011			2010			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products	$	47,891		$	23,426			104.4	%
Percentage of sales		12.1	%		7.7	%
Specialty products gross profit per barrel	$	18.09		$	9.54			89.6	%
Fuel products	$	(1,027	)	$	8,249			112.4	%
Percentage of sales		(0.5	)%		4.6	%
Fuel products gross profit per barrel	$	(0.47	)	$	3.75			(112.5	)%
Total gross profit	$	46,864		$	31,675			48.0	%
Percentage of sales		7.7	%		6.5	%

The increase in specialty products segment gross profit of $24.5 million was due primarily to a 20.5% increase in the average selling price per barrel as further discussed above, partially offset by a 21.3% increase in the average cost of crude oil per barrel. Also, specialty products sales volumes increased 7.9%, due primarily to improvements in overall specialty products demand as a result of improved economic conditions.

Fuel products segment gross profit was negatively impacted by a 1.2% decrease in fuel products sales volume, as a result of planned turnaround activities at our Shreveport refinery in the first quarter of 2011, weather-related unplanned downtime and increased realized losses from our fuel products hedging program partially offset by selling prices (excluding the impact of hedging activities) for our fuel products increasing by 31.0%, as compared to a 21.4% increase in the cost of crude oil. Our fuels hedging program resulted in a decrease of $25.3 million of gross profit in 2011, as compared to 2010, as we had outstanding hedges that approximated 80% of our diesel and jet fuel sales related to the 2011 period. As a result, we did not benefit materially from the increase in market crack spreads for diesel and jet fuel. In addition, by-product production increased in 2011 as compared to 2010, due primarily to an increase quarter over quarter in sour crude oil run rates resulting from the turnaround of the sweet crude oil unit which resulted in a reduction in gross profit in our fuel products segment of approximately $5.5 million. Finally, we experienced higher operating costs during 2011, primarily driven by increased maintenance costs.

Selling, general and administrative. Selling, general and administrative expenses increased $3.4 million or 46.8% to $10.5 million in 2011 from $7.2 million in 2010. This increase is due primarily to increased accrued incentive compensation costs of $1.2 million in 2011 compared to 2010, as well as increased overall salaries and wages.

Transportation. Transportation expenses increased $2.8 million, or 14.0%, to $23.1 million in the three months ended March 31, 2011 from $20.2 million in the same period in 2010. This increase is due primarily to increased sales volumes of lubricating oils, solvents and waxes, as well as higher freight costs.

Realized gain (loss) on derivative instruments. Realized gain (loss) on derivative instruments increased $0.9 million to a gain of $0.4 million in the three months ended March 31, 2011 from a loss of $0.6 million for the three months ended March 31, 2010. This increase was due primarily to increased realized gains of approximately $1.7 million in our specialty products segment related to crude oil derivatives not designated as hedges due to the increase in crude oil prices in 2011. Partially offsetting these increased gains were realized crack spread derivative gains of $0.9 million incurred in the prior period, with minimal comparable activity during the three months ended March 31, 2011.

Unrealized gain (loss) on derivative instruments. Unrealized loss on derivative instruments decreased $7.3 million, to $0.4 million in the three months ended March 31, 2011 from a loss of $7.8 million in the three months ended March 31, 2010. The increased gain is due primarily to an increase in gain ineffectiveness during the quarter ended March 31, 2011 with significant loss ineffectiveness in the prior period.

Liquidity and Capital Resources

The following should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” included under Part I Item 7 in our 2010 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 5 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for additional discussion related to long-term debt.

Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions to our unitholders 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 and capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. We expect to fund future capital expenditures with current cash flow from operations and borrowings under our revolving credit facility. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and borrowings under our existing revolving credit facility and may require us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.

Cash Flows

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity to meet our financial commitments, debt service obligations and anticipated capital expenditures. However, we are subject to business and operational risks that could materially adversely affect our cash flows. A material decrease in our cash flow from operations including a significant, sudden decrease in crude oil prices would likely produce a corollary material adverse effect on our borrowing capacity under our revolving credit facility and potentially our ability to comply with the covenants under our credit facilities. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which would be funded by borrowings under our revolving credit facility.

The following table summarizes our primary sources and uses of cash in each of the periods presented:


	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Net cash provided by (used in) operating activities	$	(42,906	)	$	57,331
Net cash used in investing activities	$	(6,507	)	$	(5,580	)
Net cash provided by (used in) financing activities	$	64,706		$	(51,763	)

Operating Activities. Operating activities used cash of $42.9 million during the three months ended March 31, 2011 compared to cash provided of $57.3 million during the same period in 2010. The change was due primarily to increases in working capital requirements of $67.6 million, due primarily to the increase in crude oil prices and throughput rates at our Shreveport refinery, partially offset by increased net income.

Investing Activities. Cash used in investing activities increased to $6.5 million during the three months ended March 31, 2011 compared to $5.6 million during the three months ended March 31, 2010. This increase is due primarily to increased capital expenditures primarily for capital improvements.

Financing Activities. Financing activities provided cash of $64.7 million for the three months ended March 31, 2011 compared to cash used of $51.8 million during the three months ended March 31, 2010. The increase is due primarily to the net proceeds from the public offering of $92.4 million during the first quarter of 2011, partially offset by increased repayment of borrowings under the revolving credit facility.

On April 8, 2011, we declared a quarterly cash distribution of $0.475 per unit on all outstanding units, or $19.3 million, for the quarter ended March 31, 2011. The distribution will be paid on May 13, 2011 to unitholders of record as of the close of business on May 3, 2011. This quarterly distribution of $0.475 per unit equates to $1.90 per unit, or $77.2 million on an annualized basis.

Capital Expenditures

Our capital expenditure requirements consist of capital improvement expenditures, replacement capital expenditures and environmental capital expenditures. Capital improvement expenditures include expenditures to acquire assets to grow our business, 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.


	Three Months Ended March 31,
	2011		2010
	(In thousands)
Capital improvement expenditures	$	2,475	$	220
Replacement capital expenditures		2,862		3,337
Environmental capital expenditures		1,229		2,112

Total	$	6,566	$	5,669

We anticipate that future capital expenditure requirements will be provided primarily through cash from operations and available borrowings under our revolving credit facility. We estimate our replacement and environmental capital expenditures will be approximately $6.0 million per quarter for the remainder of 2011, with total capital expenditures below 2010 levels. These estimated amounts for 2011 include a portion of the $11.0 million to $15.0 million in environmental projects to be spent over the next five years as required by our settlement with the LDEQ under the “Small Refinery and Single Site Refining Initiative.” Please read Note 4 of Part I Item 1 “Financial Statements — Commitments and Contingencies — Environmental” for additional information.

Debt and Credit Facilities

As of March 31, 2011, our credit facilities consisted of:

•

a $375.0 million senior secured revolving credit facility, subject to borrowing base restrictions, with a standby letter of credit sublimit of $300.0 million; and

•

a $435.0 million senior secured first lien credit facility consisting of a $385.0 million term loan and a $50.0 million prefunded letter of credit to support crack spread hedging. In connection with the execution of the above senior secured first lien credit facility, we incurred total debt issuance costs of $23.4 million, including $17.4 million of issuance discounts.

Borrowings under the revolving credit facility were limited to a borrowing base that was determined based on advance rates of percentages of eligible accounts receivable and inventory (as defined by the revolving credit facility 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. Our borrowing base at March 31, 2011 was $310.5 million. The borrowing base cannot exceed the total commitments of the lender group. The lender group under our revolving credit facility is comprised of a syndicate of nine lenders with total commitments of $375.0 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 prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of March 31, 2011, this margin was at 25 basis points for prime and 175 basis points for LIBOR; however, it fluctuates based on measurement of our Consolidated Leverage Ratio. The revolving credit facility, which matures in January 2013, has a first priority lien on our cash, accounts receivable and inventory and a second priority lien on our fixed assets. On March 31, 2011, we had availability on our revolving credit facility of $225.6 million, based upon a $310.5 million borrowing base and $84.9 million in outstanding standby letters of credit.

Amounts outstanding on our revolving credit facility do materially fluctuate 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 first quarter of 2011 was $105.6 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 March 31, 2011, availability for additional borrowings under our revolving credit facility was approximately $68.8 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, credit agreement covenants, contingencies and anticipated capital expenditures.

The credit facilities require us to satisfy certain financial and other covenants, including:


	Requirement	Level at March 31, 2011
Consolidated Leverage Ratio	< 3.75 to 1		2.6 to 1
Consolidated Interest Coverage Ratio	> 2.75 to 1		4.6 to 1

Compliance with the financial covenants pursuant to our credit agreements is measured quarterly based upon performance over the most recent four fiscal quarters, and as of March 31, 2011, we believe we were in compliance with all financial covenants under the credit agreements in place at March 31, 2011 and have adequate liquidity to conduct our business.

On April 21, 2011, we issued and sold $400 million in aggregate principal amount of our 9 3/8% 2019 Notes in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers. The 2019 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. We received proceeds of $389.0 million net of underwriters’ fees and expenses, which we used to repay in full borrowings outstanding under our existing senior secured first lien term loan facility, as well as all accrued interest and fees, and for general partnership purposes. Interest on the 2019 Notes will be paid semi-annually 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 guaranteed on a senior unsecured basis by all of our operating subsidiaries and 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 indenture governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

The indenture governing the 2019 Notes contains 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 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 indenture 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 issuance and sale of the 2019 Notes, on April 21, 2011, we entered into a registration rights agreement 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 can offer to exchange the 2019 Notes issued in this offering for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. We must use reasonable best efforts to cause the exchange offer registration statement to become effective by April 20, 2012 and remain effective until 180 days after the closing of the exchange. Additionally, we have agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, we must use reasonable best efforts to file a shelf registration statement for the resale of the 2019 Notes. If we fail to satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

On April 21, 2011, we used approximately $369.5 million of the net proceeds from the issuance and sale of the 2019 Notes to repay in full our term loan facility and terminated the senior secured first lien credit facility. We did not incur any material early termination penalties in connection with our termination of the senior secured first lien credit facility. Further, we will record in the second quarter of 2011 approximately $16.2 million in extinguishment charges related to the write-off of both unamortized debt issuance costs and the discount associated with the term loan.

Borrowings under the senior secured first lien credit facility were used (i) to finance a portion of the acquisition of Penreco in 2008, (ii) to fund the anticipated growth in working capital and remaining capital expenditures associated with our Shreveport refinery expansion project completed in 2008, (iii) to refinance our then-existing term loan facility, (iv) to issue a $50.0 million letter credit to secure our obligations under one of our master derivatives contracts and (v) for general partnership purposes. Each lender under the senior secured first lien credit facility had a first priority lien on our fixed assets and a second priority lien on our cash, accounts receivable and inventory. The senior secured first lien credit facility would have matured in January 2015.

On April 15, 2011, our revolving credit facility was amended to, among other things, (i) permit the issuance of the 2019 Notes; (ii) upon consummation of the issuance of the 2019 Notes 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 as follows:


	Margin on Base Rate			Margin on LIBOR
Consolidated Leverage Ratio	Revolving Loans			Revolving Loans
< 2.75 to 1.0		0.50	%		2.00	%
> 2.75 to 1.0 but < 3.25 to 1.0		0.75	%		2.25	%
> 3.25 to 1.0		1.00	%		2.50	%

Derivatives

As of March 31, 2011, we had provided our counterparties with approximately $28.9 million cash collateral above the $50.0 million prefunded letter of credit provided to one counterparty to support crack spread hedging. 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.

In connection with the issuance and sale of the 2019 Notes, on April 21, 2011, we entered into certain Amendments to our master derivatives contracts to provide new credit support arrangements to secure our payment obligations under these contracts following the issuance and sale of the 2019 Notes. Under the new credit support arrangements, our payment obligations will be 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 letter of credit under the revolving credit facility to replace a prefunded $50.0 million letter of credit previously issued under the first lien senior secured facility that secured, in part, our payment obligations prior to our termination of the letter of credit facility. In the event the counterparty’s exposure to us exceeds $150.0 million, we will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges up to the aforementioned maximum volume. Our master derivatives contracts will 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.

As of May 6, 2011, we had $28.4 million in cash margin posted with one counterparty to support crack spread hedging. All other credit support thresholds with our counterparties are at levels where it would take a substantial increase in fuel products crack spreads to require additional collateral to be posted. As a result, we do not expect further increases in fuel products crack spreads to significantly impact our liquidity.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of March 31, 2011 at current maturities and reflects only those line items that are materially changed since December 31, 2010:


			Payments Due by Period
			Less Than		1-3		3-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Operating activities:
Interest on long-term debt at contractual rates (1)	$	304,924	$	38,471	$	75,828	$	75,000	$	115,625
Operating lease obligations (2)		33,538		12,394		15,096		5,329		719
Letters of credit (3)		109,893		109,893		—		—		—
Purchase commitments (4)		1,043,921		584,509		355,665		103,747		—
Financing activities:
Capital lease obligations		1,539		968		571		—		—
Long-term debt obligations, excluding capital lease obligations		366,423		—		—		—		366,423

Total obligations	$	1,860,238	$	746,235	$	447,160	$	184,076	$	482,767


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

(2)		We have various operating leases for the use of land, storage tanks, pressure stations, railcars, equipment, precious metals and office facilities that extend through August 2017.

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

(4)		Purchase commitments consist 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.

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 $79.4 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of March 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

For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Part I Item 7 of our 2010 Annual Report.

Recent Accounting Pronouncements

For additional discussion regarding recent accounting pronouncements, see Note 2 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements”.

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 equity 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 $92.4 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.


Item 3.		*Quantitative and Qualitative Disclosures About Market Risk*

The following should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part I Item 7A in our 2010 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for additional discussion related to derivative instruments and hedging activities.

Commodity Price Risk

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 March 31, 2011:


	In millions
Crude oil swaps	$	11.5
Diesel swaps	$	3.4
Jet fuel swaps	$	7.2
Gasoline swaps	$	0.9

Interest Rate Risk

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 our interest rate risk related to variable rate debt.

We are exposed to market risk from fluctuations in interest rates. As of March 31, 2011, we had approximately $366.4 million of variable rate debt. Holding other variables constant (such as debt levels), a one hundred basis point change in interest rates on our variable rate debt as of March 31, 2011 would be expected to have an impact on net income and cash flows for 2011 of approximately $3.7 million.

We have a $375.0 million revolving credit facility as of March 31, 2011, 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 March 31, 2011.

Existing Commodity Derivative Instruments

Fuel Products Segment

The following table provides a summary of the implied crack spreads for the crude oil, diesel, jet fuel and gasoline swaps as of March 31, 2011 disclosed in Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements,” all of which are designated as hedges.


					Implied Crack
Crude Oil and Fuel Products Swap Contracts by Expiration Dates	Barrels		BPD		Spread ($/Bbl)
Second Quarter 2011		1,774,000		19,495	$	11.89
Third Quarter 2011		1,610,000		17,500		12.75
Fourth Quarter 2011		1,334,000		14,500		12.16
Calendar Year 2012		5,626,000		15,372		13.27
Calendar Year 2013		1,125,000		3,082		22.30

Totals		11,469,000
Average price					$	13.74

At March 31, 2011, we had the following jet fuel put options related to jet fuel crack spreads in our fuel products segment, none of which are designated as hedges.


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

Totals		184,000
Average price					$	4.75	$	7.00

Specialty Products Segment

At March 31, 2011, we had no derivative positions outstanding related to crude oil purchases in our specialty products segment. Please refer to Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for detailed information on these derivatives. At March 31, 2011, we have provided $28.9 million of cash collateral in credit support to a hedging counterparty due to the decrease in fair market value of our derivative instruments since December 31, 2010.


Item 4.		*Controls and Procedures*

(a) Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2011 at the reasonable assurance level.

(b) Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting during the first fiscal quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II


Item 1.		*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. The information provided under Note 4 “Commitments and Contingencies” in Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” is incorporated herein by reference.


Item 1A.		*Risk Factors*

The risk factors included in our 2010 Annual Report have not materially changed other than as set forth below.

Our revolving credit facility, indenture governing our 2019 Notes and master derivative contracts contain operating and financial restrictions that may restrict our business and financing activities.

The operating and financial restrictions and covenants in our revolving credit facility, indenture governing our 2019 Notes, master derivative contracts 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:

•

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

•

incur or guarantee additional indebtedness or issue preferred units;

•

create or incur certain liens;

•

make certain acquisitions and investments;

•

make capital expenditures above specified amounts;

•

redeem or repay other debt or make other restricted payments;

•

make capital expenditures above specified amounts;

•

enter into transactions with affiliates;

•

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

•

create unrestricted subsidiaries;

•

enter into sale and leaseback transactions;

•

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

•

cease our commodity hedging program; and

•

engage in certain business activities.

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

Our ability to comply with the covenants and restrictions contained in the indenture, our revolving credit facility and our master derivative contracts 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 the indenture governing the 2019 Notes, our revolving credit facility, our master derivative contracts or any future indebtedness could result in an event of default under the indenture, our revolving credit facility or our future indebtedness, which, if not cured or waived, could have a material adverse affect on our business, financial condition and results of operations. In the event of any default on our indebtedness, our debt holders and lenders:

•

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

•

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

•

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

•

may prevent us from making debt service payments under our other agreements, any of which could result in an event of default under the notes.

Our revolving credit facility contains operating and financial restrictions similar to the above listed items. Financial covenants in our revolving credit facility agreement include a maximum consolidated leverage ratio of 3.75 to 1.00 and a minimum consolidated interest coverage ratio of 2.75 to 1.00. The failure to comply with any of these or other covenants would cause a default under our revolving credit facility. A default, if not waived, could result in acceleration of our debt, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if new financing were available, it may be on terms that are less attractive to us than our then existing credit facilities or it may not be on terms that are acceptable to us.

If the indebtedness under the 2019 Notes 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 will be secured by substantially all of our accounts receivable and inventory and our obligations under our master derivative contracts will be secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements), and if we are unable to repay our indebtedness under the credit facility or master derivative contracts, the lenders could seek to foreclose on these assets. Please read Part I Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information.

From time to time, our cash needs may exceed our internally generated cash flows, and our business could be materially and adversely affected if we were unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generation with proceeds from financing activities. We expect that our revolving credit facility will provide us with available financing to meet our ongoing cash needs.

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 payments of 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 payments of debt obligations, we may be required to adopt one or more alternatives, such as a refinancing of our indebtedness, including our 2019 Notes, or incurring borrowings under our revolving credit facility. We cannot assure you that we would be able to refinance our indebtedness or that the terms on which we could refinance our indebtedness would be favorable.

A change of control could result in us facing substantial repayment obligations under our revolving credit facility and our 2019 Notes.

Our revolving credit agreement and the indentures governing our 2019 Notes contain provisions relating to change of control of our managing general partner, our partnership and our operating subsidiaries. If these provisions are triggered, our outstanding bank indebtedness may become due. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under our credit facility would have the right to foreclose on our assets, which would have a material adverse effect on us. There is no restriction on the ability of our general partner to enter into a transaction which would trigger the change of control provisions.

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 and north Louisiana. In 2010, subsidiaries of Plains and Genesis Crude Oil, L.P. supplied us with approximately 49.6% and 4.6%, respectively, of our total crude oil supplies under term contracts and evergreen crude oil supply contracts. In addition, 41.5% of our total crude oil purchases in 2010 were from Legacy Resources, an affiliate of our general partner, to supply crude oil to our Princeton and Shreveport refineries. 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 terminable upon 90 days’ notice. Additionally, on March 24, 2011, we provided notice to Legacy Resources that we will exercise our contractual rights under our crude oil supply agreements with Legacy Resources to terminate these agreements effective May 31, 2011. After May 31, 2011, we expect to purchase the crude oil supply for the Princeton refinery and Shreveport refinery directly from third-party suppliers under evergreen supply contracts and on the spot market. These evergreen contracts are generally terminable on 30 days notice, and purchases on the spot market may expose us to changes in commodity prices. Please read Items 1 and 2 “Business and Properties — Crude Oil and Feedstock Supply.”

To the extent that our suppliers reduce the volumes of crude oil 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. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines, governmental moratoriums on drilling or production activities or otherwise, could result in a decline in the volume of crude oil we refine. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We have no control over the level of drilling activity in the fields that supply our refineries, the amount of reserves underlying the wells in these fields, the rate at which production from a well will decline or the production decisions of producers, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital.

In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors discussed in Part I Item 1A. “Risk Factors” in our 2010 Annual Report, which could materially affect our business, financial condition or future results. The risks described in this Quarterly Report and in our 2010 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 2.		*Unregistered Sales of Equity Securities and Use of Proceeds*

On February 24, 2011, in connection with our public equity offering of 4,500,000 common units completed on that date, we sold 811,832 general partner equivalent units to Calumet GP, LLC, our general partner, under an exemption provided by Section 4(2) of the Securities Act for an aggregate purchase price of approximately $2.0 million, so that our general partner could retain its 2% general partner interest following the closing of the public equity offering. The proceeds received by us from this sale were used for general partnership purposes.

The following table summarizes the purchases of equity securities by our general partner that were completed during the three months ended March 31, 2011.


					Total Number of
					Common Units		Maximum Number of
	Total Number of				Purchased as a		Common Units that
	Common Units		Average Price Paid		Part of Publicly		May Yet be
	Purchased		per Common Unit		Announced Plans		Purchased Under Plans
January 1, 2011 – January 31, 2011		—	$	—		—		—
February 1, 2011 – February 28, 2011		—		—		—		—
March 1, 2011 – March 31, 2011 (1)		29,516		20.9481		—		—

Total		29,516	$	20.9481		—		—


(1)		A total of 24,633 common units were purchased by our general partner, Calumet GP, LLC, related to the Calumet GP, LLC Long-Term Incentive Plan (the “LTIP”) and a total of 4,883 common units were purchased by Calumet GP, LLC, our general partner, related to the Calumet GP, LLC Executive Deferred Compensation Plan (“Deferred Compensation Plan”). The LTIP provides for the delivery of up to 783,960 common units to satisfy awards of phantom units, restricted units or unit options to the employees, consultants or directors of the Company. Such units may be newly issued by the Company or purchased in the open market. None of the common units were purchased pursuant to publicly announced plans or programs. The common units were purchased through a single broker in open market transactions. For more information on the LTIP and Deferred Compensation Plan, refer to Part III Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation — Long-Term, Unit-Based Awards” and to Part III Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation — Executive Deferred Compensation Plan” in our 2010 Annual Report.


Item 3.		*Defaults Upon Senior Securities*

None.


Item 4.		*Removed and Reserved*


Item 5.		*Other Information*

None.


Item 6.		*Exhibits*

The following documents are filed as exhibits to this Quarterly Report:


Exhibit
Number			Description

	3.1		Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

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

	3.3		Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

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

	3.5		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No 000-51734)).

	3.6		Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No 000-51734)).

	4.1		Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No 000-51734)).

	4.2		Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No 000-51734)).

	4.3		Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No 000-51734)).

	10.1		Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Lubricants Co., Limited Partnership and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.26 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).

	10.2		Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Lubricants Co., Limited Partnership and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.27 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).

	31.1	*	Sarbanes-Oxley Section 302 certification of F. William Grube.

	31.2	*	Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.

	32.1	*	Section 1350 certification of F. William Grube and R. Patrick Murray, II.


*		Filed herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
	By:	Calumet GP, LLC,
		its general partner

	By:	/s/ R. Patrick Murray, II
		R. Patrick Murray, II Vice President,
		Chief Financial Officer and Secretary of Calumet GP, LLC, general partner of Calumet Specialty Products Partners, L.P. (Authorized Person and Principal Accounting Officer)

Date: May 6, 2011

Index to Exhibits


Exhibit
Number			Description

	3.1		Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

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

	3.3		Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

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

	3.5		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No 000-51734)).

	3.6		Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No 000-51734)).

	4.1		Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No 000-51734)).

	4.2		Indenture, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and Wilmington Trust FSB, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No 000-51734)).

	4.3		Registration Rights Agreement, dated April 21, 2011, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors party thereto and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on April 26, 2011 (File No 000-51734)).

	10.1		Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Lubricants Co., Limited Partnership and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.26 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).

	10.2		Amendment No. 5 to Crude Oil Supply Agreement, dated as of March 24, 2011 and effective March 1, 2011, between Calumet Lubricants Co., Limited Partnership and Legacy Resources Co., L.P. (incorporated by reference to Exhibit 10.27 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 25, 2011 (File No 000-51734)).

	31.1	*	Sarbanes-Oxley Section 302 certification of F. William Grube.

	31.2	*	Sarbanes-Oxley Section 302 certification of R. Patrick Murray, II.

	32.1	*	Section 1350 certification of F. William Grube and R. Patrick Murray, II.


*		Filed herewith.

TABLE OF CONTENTS

Part I Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Removed and Reserved Item 5. Other Information Item 6. Exhibits

Exhibits

Exhibit 31.1 Exhibit 31.2 Exhibit 32.1

CLMT 10-Q Quarter ended March 31, 2011

Exhibits