CLMT 10-Q Quarterly Report March 31, 2010

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

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10-Q 1 h72805e10vq.htm FORM 10-Q e10vq

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, 2010


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

2780 Waterfront Parkway East Drive, Suite 200 Indianapolis, Indiana (Address of principal executive officers)		46214 (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 5, 2010, there were 22,213,778 common units and 13,066,000 subordinated units outstanding.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three Months Ended March 31, 2010

Table of Contents


	Page
Part I
Item 1. Financial Statements
Condensed Consolidated Balance Sheets		1
Unaudited Condensed Consolidated Statements of Operations		2
Unaudited Condensed Consolidated Statements of Partners’ Capital		3
Unaudited Condensed Consolidated Statements of Cash Flows		4
Notes to Unaudited Condensed Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3. Quantitative and Qualitative Disclosures About Market Risk		35
Item 4. Controls and Procedures		36
Part II
Item 1. Legal Proceedings		37
Item 1A. Risk Factors		37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		37
Item 3. Defaults Upon Senior Securities		37
Item 4. Reserved		37
Item 5. Other Information		38
Item 6. Exhibits		38
Exhibit 10.22
Exhibit 10.23
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
EX-10.22
EX-10.23
EX-31.1
EX-31.2
EX-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 and Section 21E of the Securities Exchange Act of 1934. Some of the information in this Quarterly Report may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. The statements regarding (i) expected settlements 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, (iii) future compliance with our debt covenants, (iv) expected increases in crude oil run rates at our facilities, and (v) future activities associated with our contractual arrangements with LyondellBasell, 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 26, 2010 (our “2009 Annual Report”). The risk factors in these documents and other factors noted throughout this Quarterly 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 impact on our liquidity;

	•		the results of our hedging and other risk management activities;

	•		our ability to comply with financial covenants contained in our credit agreements;

	•		the availability of, and our ability to consummate, acquisition or combination opportunities;

	•		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;

	•		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 read Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk.” We will not update these statements unless securities laws require us to do so.

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 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.

iii

PART I

Item 1. Financial Statements

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2010		December 31, 2009
	(Unaudited)
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	37	$	49
Accounts receivable:
Trade		137,719		116,914
Other		2,578		5,854

		140,297		122,768
Inventories		110,994		137,250
Derivative assets		10,150		30,904
Prepaid expenses and other current assets		1,498		1,811
Deposits		1,613		6,861

Total current assets		264,589		299,643
Property, plant and equipment, net		622,620		629,275
Goodwill		48,335		48,335
Other intangible assets, net		35,891		38,093
Other noncurrent assets, net		14,922		16,510

Total assets	$	986,357	$	1,031,856


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable	$	119,680	$	92,110
Accounts payable — related party		18,762		17,866
Accrued salaries, wages and benefits		5,870		6,500
Taxes payable		6,906		7,551
Other current liabilities		6,912		6,114
Current portion of long-term debt		4,924		5,009
Derivative liabilities		4,670		4,766

Total current liabilities		167,724		139,916
Pension and postretirement benefit obligations		9,189		9,433
Other long-term liabilities		1,105		1,111
Long-term debt, less current portion		362,462		396,049

Total liabilities		540,480		546,509
Commitments and contingencies Partners’ capital:
Common unitholders (22,213,778 units and 22,166,000 units, issued and outstanding at March 31, 2010 and December 31, 2009, respectively)		402,115		418,902
Subordinated unitholders (13,066,000 units issued and outstanding)		24,026		34,714
General partner’s interest		18,516		19,087
Accumulated other comprehensive income		1,220		12,644

Total partners’ capital		445,877		485,347

Total liabilities and partners’ capital	$	986,357	$	1,031,856

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,
	2010			2009
	(In thousands, except per unit data)
Sales	$	484,616		$	414,264
Cost of sales		452,941			335,293

Gross profit		31,675			78,971

Operating costs and expenses:
Selling, general and administrative		7,170			9,322
Transportation		20,246			15,155
Taxes other than income taxes		1,025			1,125
Other		327			418

Operating income		2,907			52,951

Other income (expense):
Interest expense		(7,434	)		(8,644	)
Realized loss on derivative instruments		(561	)		(8,470	)
Unrealized gain (loss) on derivative instruments		(7,758	)		39,739
Other		(59	)		144

Total other income (expense)		(15,812	)		22,769

Net income (loss) before income taxes		(12,905	)		75,720
Income tax expense		162			82

Net income (loss)	$	(13,067	)	$	75,638


Allocation of net income (loss):
Net income (loss)	$	(13,067	)	$	75,638
Less:
General partner’s interest in net income (loss)		(261	)		1,510
Holders of incentive distribution rights		—			—

Net income (loss) available to limited partners	$	(12,806	)	$	74,128
Weighted average limited partner units outstanding – basic and diluted		35,351			32,232
Common and subordinated unitholders’ basic and diluted net income (loss) per unit	$	(0.36	)	$	2.30
Cash distributions declared per common and subordinated unit	$	0.455		$	0.45

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
	Income			Partner			Common			Subordinated			Total
	(In thousands)
Balance at December 31, 2009	$	12,644		$	19,087		$	418,902		$	34,714		$	485,347
Comprehensive income (loss):
Net loss					(261	)		(8,063	)		(4,743	)		(13,067	)
Cash flow hedge gain reclassified to net income		(5,730	)											(5,730	)
Change in fair value of cash flow hedges		(6,099	)											(6,099	)
Defined benefit pension and retiree health benefit plans		405												405

Comprehensive loss														(24,491	)
Proceeds from public equity offering, net								793						793
Contribution from Calumet GP, LLC					18									18
Units repurchased for phantom unit grants								(248	)					(248	)
Amortization of vested phantom units								855						855
Distributions to partners					(328	)		(10,124	)		(5,945	)		(16,397	)

Balance at March 31, 2010	$	1,220		$	18,516		$	402,115		$	24,026		$	445,877

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Three Months Ended
	March 31,
	2010			2009
	(In thousands)
Operating activities
Net income (loss)	$	(13,067	)	$	75,638
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		15,351			16,135
Amortization of turnaround costs		2,140			1,597
Provision for doubtful accounts		(91	)		240
Unrealized (gain) loss on derivative instruments		7,758			(39,739	)
Other non-cash activity		935			106
Changes in assets and liabilities:
Accounts receivable		(17,438	)		6,998
Inventories		26,256			(30,452	)
Prepaid expenses and other current assets		313			684
Derivative activity		1,071			(7,228	)
Deposits		5,248			4,000
Other assets		(939	)		(76	)
Accounts payable		28,466			2,785
Accrued salaries, wages and benefits		(630	)		(92	)
Taxes payable		(645	)		2,009
Other liabilities		2,442			(287	)
Pension and postretirement benefit obligations		161			315

Net cash provided by operating activities		57,331			32,633
Investing activities
Additions to property, plant and equipment		(5,669	)		(4,945	)
Proceeds from disposal of property and equipment		89			—

Net cash used in investing activities		(5,580	)		(4,945	)
Financing activities
Repayments of borrowings— revolving credit facility		(32,944	)		(9,569	)
Repayments of borrowings, term loan credit facility		(963	)		(963	)
Payments on capital lease obligations		(372	)		(309	)
Proceeds from public equity offering, net		793			—
Contribution from Calumet GP, LLC		18			—
Change in bank overdraft		(1,650	)		(1,944	)
Common units repurchased for vested phantom unit grants		(248	)		(105	)
Distributions to partners		(16,397	)		(14,818	)

Net cash used in financing activities		(51,763	)		(27,708	)

Net decrease in cash and cash equivalents		(12	)		(20	)
Cash and cash equivalents at beginning of period		49			48

Cash and cash equivalents at end of period	$	37		$	28

Supplemental disclosure of cash flow information
Interest paid	$	6,944		$	7,917
Income taxes paid	$	8		$	—

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except operating, unit and per unit data)

1. Description of the Business

Calumet Specialty Products Partners, L.P. (the “Company”) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of March 31, 2010, the Company had 22,213,778 common units, 13,066,000 subordinated units, and 719,995 general partner equivalent units outstanding. 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, 2010 and for the three months ended March 31, 2010 and 2009 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 accounting principles generally accepted in the United States of America 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, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2009 Annual Report. We issued these unaudited condensed consolidated financial statements by filing with the SEC and have evaluated subsequent events up to the time of filing.

2. New Accounting Pronouncements

In January 2010, the FASB issued ASU No. 2010-06, “ Disclosures About Fair Value Measurements ”, 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. This ASU is effective for the first reporting period (including interim periods) beginning after December 15, 2009. The Company has adopted this standard effective January 1, 2010, however, adoption of this amendment did not have a material effect 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. Inventory 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,
	2010		2009
Raw materials	$	9,680	$	1,323
Work in process		42,936		51,304
Finished goods		58,378		84,623

	$	110,994	$	137,250

The replacement cost of these inventories, based on current market values, would have been $43,934 and $30,420 higher as of March 31, 2010 and December 31, 2009, respectively.

-5-

4. LyondellBasell Agreements

Effective November 4, 2009, the Company entered into agreements (the “LyondellBasell Agreements”) with Houston Refining LP, a wholly-owned subsidiary of LyondellBasell (“Houston Refining”), to form a long-term exclusive specialty products affiliation. The initial term of the LyondellBasell Agreements lasts until October 31, 2014. After October 31, 2014 the agreements are automatically extended for additional one-year terms unless either party provides 24 months’ notice of a desire to terminate either the initial term or any renewal term. Under the terms of the LyondellBasell Agreements, (i) the Company is the exclusive purchaser of Houston Refining’s naphthenic lubricating oil production at its Houston, Texas refinery and is required to purchase a minimum of approximately 3,000 barrels per day (“bpd”), and (ii) Houston Refining will process a minimum of approximately 800 bpd of white mineral oil for the Company at its Houston, Texas refinery, which will supplement the existing white mineral oil production at the Company’s Karns City and Dickinson facilities. The Company’s annual purchase commitment under these agreements is approximately $120,000. The Company also has exclusive rights to use certain LyondellBasell registered trademarks and tradenames including Tufflo, Duoprime, Duotreat, Crystex, Ideal and Aquamarine.

5. 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 taxing and regulatory authorities, such as the Louisiana Department of Environmental Quality (“LDEQ”), U.S. Environmental Protection Agency (“EPA”), Internal Revenue Service (“IRS”) and Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position, results of operations or cash flows.

Labor Matters

The Company entered into a new Cotton Valley collective bargaining agreement with the International Union of Operating Engineers that will expire on March 31, 2013. In addition, a new Shreveport collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial, and Service Workers International Union has been ratified by the local union and will expire on April 30, 2013.

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. In particular, the LDEQ has proposed penalties totaling approximately $400 and supplemental environmental capital projects 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. The Company anticipates that any penalties that may be assessed due to the alleged violations will be consolidated in a settlement agreement that the Company anticipates executing with the LDEQ in connection with the agency’s “Small Refinery and Single Site Refinery Initiative” described below. The Company has recorded a liability for the proposed penalties within other current liabilities on the unaudited condensed consolidated balance sheets. Environmental expenses are recorded within other expenses in the unaudited condensed consolidated statements of operations. In addition, the Company’s Shreveport refinery experienced the failure of an environmental operating unit in February 2010 and the refinery is operating under a variance from the LDEQ until the environmental operating unit is replaced, which the Company expects to occur at the beginning of the third quarter of 2010.

The Company is party to ongoing discussions on a voluntary basis with the LDEQ regarding the Company’s participation in that agency’s “Small Refinery and Single Site Refinery Initiative.” This state initiative is patterned after the EPA’s “National Petroleum Refinery Initiative,” which is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. The Company expects that the LDEQ’s primary focus under the state initiative will be on four compliance and enforcement concerns: (i) Prevention of Significant Deterioration/New Source Review; (ii) New Source Performance Standards for fuel gas combustion devices, including flares, heaters and boilers; (iii) Leak Detection and Repair requirements; and (iv) Benzene Waste Operations National Emission Standards for Hazardous Air Pollutants. The Company is in discussions with the LDEQ regarding its participation in this regulatory initiative and the Company anticipates that it will be entering into a settlement agreement with the LDEQ pursuant to which the Company will be required to make emissions reductions requiring capital investments between approximately $1,000 and $3,000 in total over a three to five year period at its three Louisiana refineries. Because the settlement agreement is also expected to resolve the aforementioned alleged air emissions issues and other violations at the Company’s Cotton Valley and Princeton refineries and consolidate any penalties associated with such issues, the Company further anticipates that a penalty of approximately $400 will be assessed in connection with this settlement agreement.

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 environmental regulatory 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 estimates that it will incur approximately $1,000 of external costs during 2010 at its Cotton Valley refinery in connection with continued remediation of groundwater impacts at that site.

The Company is indemnified by Shell Oil Company (“Shell”), 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 and Safety

The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and 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, 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 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 over the next three years to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment to maintain compliance with applicable requirements at the Shreveport refinery. The Company believes that operations are in substantial compliance with OSHA and similar state laws.

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, 2010 and December 31, 2009, the Company had outstanding standby letters of credit of $61,215 and $46,859, respectively, under its senior secured revolving credit facility. The maximum amount of letters of credit the Company can issue is limited to its availability under its revolving credit facility or $300,000, whichever is lower. As of March 31, 2010 and December 31, 2009, the Company had availability to issue letters of credit of $141,241 and $107,285, respectively, under its revolving credit facility. As discussed in Note 6, as of March 31, 2010 the Company also had a prefunded $50,000 letter of credit outstanding under its senior secured first lien letter of credit facility to support crack spread hedging, which bears interest at 4.0%.

6. Long-Term Debt

Long-term debt consisted of the following:


	March 31,			December 31,
	2010			2009
Borrowings under senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 4.00% (4.25% and 4.27% at March 31, 2010 and December 31, 2009, respectively), interest and principal payments quarterly through September 30, 2014 with remaining borrowings due January 2015, effective interest rate of 4.75% and 6.00% for the periods ended March 31, 2010 and December 31, 2009, respectively	$	370,273		$	371,235
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, 2010 and December 31, 2009, respectively), interest payments monthly, borrowings due January 2013		6,956			39,900
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly through January 2012		2,613			2,938
Less unamortized discount on senior secured first lien term loan with third-party lenders		(12,456	)		(13,015	)

Total long-term debt		367,386			401,058
Less current portion of long-term debt		4,924			5,009

	$	362,462		$	396,049

The Company’s $435,000 senior secured first lien term loan facility includes a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging, which bears interest at 4.0%. The term loan bears 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).

Lenders under the term loan facility have 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 requires quarterly principal payments of $963 until maturity on September 30, 2014, with the remaining balance due at maturity on January 3, 2015.

The Company’s senior secured 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, 2010, the margin is 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 senior secured revolving credit facility matures on January 3, 2013.

The borrowing capacity at March 31, 2010 under the revolving credit facility was $209,412 with $141,241 available for additional borrowings based on collateral and specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s cash, accounts receivable and inventory and a second priority lien on the Company’s fixed assets.

Compliance with the financial covenants pursuant to the Company’s credit agreements is tested quarterly based upon performance over the most recent four fiscal quarters and as of March 31, 2010 the Company was in compliance with all financial covenants under its credit agreements.

As of March 31, 2010, maturities of the Company’s long-term debt are as follows:


Year	Maturity
2010		3,719
2011		4,844
2012		4,401
2013		11,042
2014		3,850
Thereafter		351,986

Total	$	379,842

7. 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 had recorded the following derivative assets and liabilities at fair value as of March 31, 2010 and December 31, 2009:


	Derivative Assets						Derivative Liabilities
	March 31, 2010			December 31, 2009			March 31, 2010			December 31, 2009
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	150,194		$	134,587		$	—		$	—
Gasoline swaps		(39,294	)		(6,147	)		—			—
Diesel swaps		(70,144	)		(67,731	)		—			—
Jet fuel swaps		(34,579	)		(26,926	)		—			—
Specialty products segment:
Crude oil collars		—			—			—			—
Crude oil swaps		—			—			—			—
Natural gas swaps		—			—			—			—
Interest rate swaps:		—			—			(2,917	)		(2,752	)

Total derivative instruments designated as hedges		6,177			33,783			(2,917	)		(2,752	)

Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps (1)		(10,951	)		13,062			—			—
Gasoline swaps (1)		13,798			(16,165	)		—			—
Diesel swaps		—			—			—			—
Jet fuel crack spread collars (4)		249			375			—			—
Specialty products segment:
Crude oil collars (2)		825			(151	)		—			—
Crude oil swaps (2)		52			—						—
Natural gas swaps (2)		—			—			—			—
Interest rate swaps: (3)		—			—			(1,753	)		(2,014	)

Total derivative instruments not designated as hedges		3,973			(2,879	)		(1,753	)		(2,014	)

Total derivative instruments	$	10,150		$	30,904		$	(4,670	)	$	(4,766	)


(1)		The Company entered into derivative instruments to purchase the gasoline crack spread which do not qualify for hedge accounting. These derivatives were entered into to economically lock in a gain on a portion of the Company’s gasoline and crude oil swap contracts that are designated as hedges.

(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 designated as a hedge of the interest payments related to the previous debt agreement no longer qualified for hedge accounting. The Company entered into an offsetting interest rate swap to fix the value of this derivative instrument and is settling this net position over the term of the derivative instruments. These two derivative instruments are shown net on this line item.

(4)		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.

To the extent a derivative instrument is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income, 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, 2010 and 2009 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						Accumulated Other Comprehensive							Amount of Gain (Loss) Recognized in Net
	on Derivatives (Effective						Income into Net Income (Loss) (Effective							Income (Loss) on Derivatives (Ineffective
	Portion)						Portion)							Portion)
								Three Months Ended							Three Months Ended
	March 31,						Location of (Gain)	March 31,						Location of Gain	March 31,
Type of Derivative	2010			2009			Loss	2010			2009			(Loss)	2010			2009
Fuel products segment:
Crude oil swaps	$	16,481		$	(142,869	)	Cost of sales	$	(17,508	)	$	36,410		Unrealized/ Realized	$	(6,473	)	$	13,005
Gasoline swaps		(5,841	)		85,542		Sales		5,184			(20,667	)	Unrealized/ Realized		(1,535	)		2,644
Diesel swaps		(8,566	)		101,381		Sales		5,808			(18,482	)	Unrealized/ Realized		(1,181	)		7,745
Jet fuel swaps		(7,224	)		—		Sales		—			—		Unrealized/ Realized		—			—
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		—			1,428		Unrealized/ Realized		—			—
Interest rate swaps:		(949	)		(3,647	)	Interest expense		786			—		Unrealized/ Realized		—			—

Total	$	(6,099	)	$	40,407			$	(5,730	)	$	(1,311	)		$	(9,189	)	$	23,394

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2010 and 2009 related to its derivative instruments not designated as cash flow hedges:


	Amount of Gain (Loss) Recognized in						Amount of Gain (Loss) Recognized
	Realized Loss on Derivatives						in Unrealized Gain (Loss) on Derivatives
	Three Months Ended						Three Months Ended
	March 31,						March 31,
Type of Derivative	2010			2009			2010			2009
Fuel products segment:
Crude oil swaps	$	(2,235	)	$	11,510		$	1,572		$	(8,989	)
Gasoline swaps		3,394			(5,736	)		(2,042	)		13,829
Diesel swaps		(325	)		(1,664	)		325			1,664
Jet fuel swaps		—			—			—			—
Jet fuel collars		—			—			(126	)		(159	)
Specialty products segment:
Crude oil collars		(771	)		(14,261	)		977			12,172
Crude oil swaps		24			—			51			—
Natural gas swaps		(35	)		(1,507	)		—			1,223
Interest rate swaps:		(200	)		(204	)		261			(3	)

Total	$	(148	)	$	(11,862	)	$	1,018		$	19,737

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. The Company’s contracts with these counterparties allow for netting of derivative instrument positions executed under each contract. Collateral held by, or received from, counterparties is reported in deposits and other current liabilities, respectively, on the Company’s condensed consolidated balance sheets and not netted against derivative assets or liabilities. As of March 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, 2010, there is no net liability associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.

The effective portion of the hedges classified in accumulated other comprehensive income is $5,523 as of March 31, 2010, and absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2012 with balances being recognized as follows:


	Accumulated Other
	Comprehensive
Year	Income (Loss)
2010	$	15,552
2011		(5,079	)
2012		(4,950	)

Total	$	5,523

Based on fair values as of March 31, 2010, the Company expects to reclassify $14,063 of net gains on derivative instruments from accumulated other comprehensive income 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). As of March 31, 2010, the Company has hedged at levels approximating 16.5% of its expected specialty products production for the next quarter. 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, 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		Average		Average
					Bought Put		Swap		Sold Call
Crude Oil Put/Swap/Call Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)
April 2010		90,000		3,000	$	61.47	$	76.93	$	87.00
May 2010		155,000		5,000		67.68		82.66		92.66
June 2010		120,000		4,000		68.21		82.96		92.96

Totals		365,000
Average price					$	66.32	$	81.35	$	91.36


Crude Oil Swap Contracts by Expiration Dates	Barrels		BPD		$/Bbl
April 2010		45,000		1,500	$	82.74

At December 31, 2009, the Company had the following crude oil derivatives related to crude oil purchases in its specialty products segment, none of which were designated as hedges.



					Average		Average		Average
					Bought Put		Swap		Sold Call
Crude Oil Put/Swap/Call Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)
January 2010		186,000		6,000	$	68.32	$	80.43	$	90.43

Totals		186,000
Average price					$	68.32	$	80.43	$	90.43

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


	Barrels
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Second Quarter 2010		1,820,000		20,000	$	67.29
Third Quarter 2010		1,840,000		20,000		67.29
Fourth Quarter 2010		1,840,000		20,000		67.29
Calendar Year 2011		5,614,000		15,381		76.54
Calendar Year 2012		1,685,500		4,605		86.25

Totals		12,799,500
Average price					$	73.84

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


	Barrels
Crude Oil Swap Contracts by Expiration Dates	Sold		BPD		($/Bbl)
Second Quarter 2010		136,500		1,500	$	58.25
Third Quarter 2010		138,000		1,500		58.25
Fourth Quarter 2010		138,000		1,500		58.25

Totals		412,500
Average price					$	58.25

At December 31, 2009, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which were designated as hedges.


	Barrels
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 2010		1,800,000		20,000	$	67.29
Second Quarter 2010		1,820,000		20,000		67.29
Third Quarter 2010		1,840,000		20,000		67.29
Fourth Quarter 2010		1,840,000		20,000		67.29
Calendar Year 2011		5,614,000		15,381		76.54

Totals		12,914,000
Average price					$	71.31

At December 31, 2009, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges.


Crude Oil Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2010		135,000		1,500	$	58.25
Second Quarter 2010		136,500		1,500		58.25
Third Quarter 2010		138,000		1,500		58.25
Fourth Quarter 2010		138,000		1,500		58.25

Totals		547,500
Average price					$	58.25

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 and gasoline swap contracts for a period no greater than five years forward and for no more than 75% of forecasted fuel sales.

Diesel Swap Contracts

At March 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.


Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2010		1,183,000		13,000	$	80.41
Third Quarter 2010		1,196,000		13,000		80.41
Fourth Quarter 2010		1,196,000		13,000		80.41
Calendar Year 2011		2,371,000		6,496		90.58

Totals		5,946,000
Average price					$	84.47

At December 31, 2009, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which were designated as hedges.


Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2010		1,170,000		13,000	$	80.41
Second Quarter 2010		1,183,000		13,000		80.41
Third Quarter 2010		1,196,000		13,000		80.41
Fourth Quarter 2010		1,196,000		13,000		80.41
Calendar Year 2011		2,371,000		6,496		90.58

Totals		7,116,000
Average price					$	83.80

Jet Fuel Swap Contracts

At March 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.


Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Calendar Year 2011		2,514,000		6,888	$	88.51
Calendar Year 2012		1,549,000		4,232		98.62

Totals		4,063,000
Average price					$	92.36

At December 31, 2009, 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.


Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Calendar Year 2011		2,514,000		6,888	$	88.51

Totals		2,514,000
Average price					$	88.51

Gasoline Swap Contracts

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


Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2010		637,000		7,000	$	75.28
Third Quarter 2010		644,000		7,000		75.28
Fourth Quarter 2010		644,000		7,000		75.28
Calendar Year 2011		729,000		1,997		83.53
Calendar Year 2012		136,500		373		89.04

Totals		2,790,500
Average price					$	78.11

At March 31, 2010, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges.


	Barrels
Gasoline Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Second Quarter 2010		136,500		1,500	$	58.42
Third Quarter 2010		138,000		1,500		58.42
Fourth Quarter 2010		138,000		1,500		58.42

Totals		412,500
Average price					$	58.42

At December 31, 2009, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which were designated as hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2010		630,000		7,000	$	75.28
Second Quarter 2010		637,000		7,000		75.28
Third Quarter 2010		644,000		7,000		75.28
Fourth Quarter 2010		644,000		7,000		75.28
Calendar Year 2011		729,000		1,997		83.53

Totals		3,284,000
Average price					$	77.11

At December 31, 2009, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which were designated as hedges.


	Barrels
Gasoline Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 2010		135,000		1,500	$	58.42
Second Quarter 2010		136,500		1,500		58.42
Third Quarter 2010		138,000		1,500		58.42
Fourth Quarter 2010		138,000		1,500		58.42

Totals		547,500
Average price					$	58.42

Jet Fuel Put Spread Contracts

At March 31, 2010 and December 31, 2009, 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)
Calendar Year 2011		814,000		2,230	$	4.17	$	6.23

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 the Company’s 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, 2010 and December 31, 2009, the Company did not have any derivatives 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.

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 current 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 which is not designated as a cash flow hedge.

8. 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 $346,205 and $328,543 at March 31, 2010 and December 31, 2009, respectively. The carrying values of borrowings under the Company’s senior secured revolving credit facility were $6,956 and $39,900 at March 31, 2010 and December 31, 2009, 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, 2010 and December 31, 2009.

9. 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, 2010, 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, natural gas and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the Company obtains this data through surveying its counterparties and performing various analytical tests to validate the data. 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, 2010, the Company’s asset was increased by approximately $80 and its liability was reduced by $281. 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 consist of mutual funds that are publicly traded and for which market prices are readily available, thus these investments are categorized as Level 1.

The Company’s assets measured at fair value at March 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		—		—		139,295			139,295
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Natural gas swaps		—		—		—			—
Crude oil options		—		—		825			825
Jet fuel options		—		—		249			249
Pension Plan investments		14,134		—		—			14,134

Total assets at fair value	$	14,171	$	—	$	140,369		$	154,540

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(25,496	)		(25,496	)
Diesel swaps		—		—		(70,144	)		(70,144	)
Jet fuel swaps		—		—		(34,579	)		(34,579	)
Natural gas swaps		—		—		—			—
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(4,670	)		(4,670	)

Total liabilities at fair value	$	—	$	—	$	(134,889	)	$	(134,889	)

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, 2010:


	Derivative
	Instruments, Net
Fair value at January 1, 2010	$	26,138
Realized losses		561
Unrealized losses		(7,758	)
Comprehensive loss		(6,099	)
Purchases, issuances and settlements		(7,362	)
Transfers in (out) of Level 3		—

Fair value at March 31, 2010	$	5,480

Total gains (losses) included in net income (loss) attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of March 31, 2010	$	(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 7 for further information on derivative instruments.

10. Comprehensive Income (Loss)

Comprehensive income (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 (loss). Comprehensive income (loss) for the three months ended March 31, 2010 and 2009 was as follows:


	Three Months Ended
	March 31,
	2010			2009
Net income (loss)	$	(13,067	)	$	75,638
Cash flow hedge gain reclassified to net income (loss)		(5,730	)		(1,311	)
Change in fair value of cash flow hedges		(6,099	)		(20,072	)
Defined benefit pension and retiree health benefit plans		405			94

Total comprehensive income (loss)	$	(24,491	)	$	54,349

11. Unit-Based Compensation and Distributions

A summary of the Company’s nonvested phantom units as of March 31, 2010 and the changes during the three months ended March 31, 2010 is presented below:


				Weighted Average
				Grant Date
	Number of Units			Fair Value
Nonvested at December 31, 2009		57,493		$	12.42
Granted		55,325			18.85
Vested		(50,442	)		17.60
Forfeited		—			—

Nonvested at March 31, 2010		62,376		$	13.93

For the three months ended March 31, 2010 and 2009, compensation expense of $147 and $55, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. As of March 31, 2010 and 2009, there was a total of $869 and $638 of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately two years.

The Company’s distribution policy is as defined in its partnership agreement. For the three months ended March 31, 2010 and 2009, the Company made distributions of $16,397 and $14,818, 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, 2010 and 2009 were as follows:


	For the Three Months Ended
	March 31,
				2010			2009
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	21		$	—		$	63		$	2
Interest cost		334			6			332			11
Expected return on assets		(259	)		—			(187	)		—
Amortization of net (gain) loss		69			(1	)		95			(1	)
Prior service cost		—			(9	)		—			—

Net periodic benefit cost	$	165		$	(4	)	$	303		$	12

During each of the three months ended March 31, 2010 and 2009, the Company made no contributions to its non-contributory defined benefit plan (its “Pension Plan”) and other post retirement employee benefit plans and expects to make contributions to its Pension Plan in 2010 of $1,078.

The Company’s investments associated with its Pension Plan consist of mutual funds that are publicly traded and for which market prices are readily available and, as such, these investments are categorized as Level 1. The Company’s Pension Plan assets measured at fair value at March 31, 2010 and December 31, 2009 were as follows:


	Quoted Prices in
	Active Markets for
	Identical Assets
	(Level 1)
	March 31,		December 31,
	2010		2009
	Pension		Pension
	Benefits		Benefits

Cash	$	409	$	326
Equity		10,861		8,326
Foreign equities		549		2,736
Fixed income		2,315		2,342

	$	14,134	$	13,730

13. 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 their 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 in the notes to consolidated financial statements in the Company’s 2009 Annual Report for the year ended December 31, 2009 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, 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 income:
Interest expense												(7,434	)
Loss on derivative instruments												(8,319	)
Other expense												(59	)
Income tax expense												(162	)

Net loss											$	(13,067	)

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


	Specialty		Fuel		Combined					Consolidated
Three Months Ended March 31, 2009	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	216,972	$	197,292	$	414,264	$	—		$	414,264
Intersegment sales		119,665		4,272		123,937		(123,937	)		—

Total sales	$	336,637	$	201,564	$	538,201	$	(123,937	)	$	414,264

Depreciation and amortization		17,732		—		17,732		—			17,732
Operating income		37,134		15,817		52,951		—			52,951
Reconciling items to net loss:
Interest expense											(8,644	)
Debt extinguishment costs											—
Gain on derivative instruments											31,269
Other income											144
Income tax expense											(82	)

Net income										$	75,638

Capital expenditures	$	4,945	$	—	$	4,945	$	—		$	4,945


	March 31, 2010			December 31, 2009
Segment assets:
Specialty products	$	2,603,498		$	3,072,815
Fuel products		1,934,712			2,371,750

Combined segments		4,538,210			5,444,565
Eliminations		(3,551,853	)		(4,412,709	)

Total assets	$	986,357		$	1,031,856

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three months ended March 31, 2010 and 2009. 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 and jet fuel. The following table sets forth the major product category sales:


	Three Months Ended March 31,
	2010		2009
Specialty products:
Lubricating oils	$	164,048	$	118,316
Solvents		87,853		54,487
Waxes		26,246		22,409
Fuels		1,738		2,659
Asphalt and other by-products		25,591		19,101

Total	$	305,476	$	216,972

Fuel products:
Gasoline		75,883		74,855
Diesel		64,230		81,657
Jet fuel		37,564		39,214
By-products		1,463		1,566

Total	$	179,140	$	197,292

Consolidated sales	$	484,616	$	414,264

d. Major Customers

During the three months ended March 31, 2010 and 2009, the Company had no customer that represented 10% or greater of consolidated sales.

14. Subsequent Events

On April 12, 2010, the Company declared a quarterly cash distribution of $0.455 per unit on all outstanding units, or $16,391, for the quarter ended March 31, 2010. The distribution will be paid on May 14, 2010 to unitholders of record as of the close of business on May 4, 2010. This quarterly distribution of $0.455 per unit equates to $1.82 per unit, or $65,564 on an annualized basis.

The fair value of the Company’s derivatives have decreased by approximately $10,000 subsequent to March 31, 2010.

In April 2010, the Company purchased naphthenic lubricating oil inventory from LyondellBasell pursuant to the LyondellBasell Agreements for approximately $10,670. Please refer to Note 4 for additional information related to the LyondellBasell Agreements.


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. (the “Company,” “we,” “our,” “us”). The following discussion analyzes the financial condition and results of operations of the Company for the three months ended March 31, 2010 and 2009. Unitholders should read the following discussion and analysis of the financial condition and results of operations for the Company in conjunction with our 2009 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 (“Princeton”), Cotton Valley, Louisiana (“Cotton Valley”), Shreveport, Louisiana (“Shreveport”), Karns City, Pennsylvania (“Karns City”), and Dickinson, Texas (“Dickinson”), 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. The asphalt and other by-products produced in connection with the production of specialty products at our Princeton, Cotton Valley and Shreveport refineries are included in our specialty products segment. The by-products produced in connection with the production of fuel products at our Shreveport refinery are included in our fuel products segment. The fuels produced in connection with the production of specialty products at Princeton, Cotton Valley and Karns City are included in our specialty products segment.

First Quarter 2010 Update

For the three months ended March 31, 2010 and 2009, approximately 52.8% and 45.2%, respectively, of our sales volume and 74.0% and 75.8%, respectively, of our gross profit was generated from our specialty products segment while approximately 47.2% and 54.8%, respectively, of our sales volume and approximately 26.0% and 24.2%, respectively, of our gross profit was generated from our fuel products segment. The specialty petroleum products refining market and, in general, the overall refining industry has continued to experience economic challenges. As fuel products crack spreads declined during 2009, numerous refiners announced reductions in refinery throughput rates, the idling of refinery assets and refinery closures. While specialty products segment sales volumes declined by 8.9% for the full year 2009 as compared to 2008, we noted an improving demand environment during the third and fourth quarters of 2009. This improvement continued into the first quarter of 2010 as specialty products sales volumes increased 10.9% over the first quarter of 2009. In addition, our average crude oil costs were relatively stable during the third and fourth quarters of 2009. This allowed our specialty products segment to generate gross profit margins of 12.8% and 10.2%, respectively, in those periods. Crude oil costs continued to remain relatively stable in the first quarter of 2010 resulting in a gross profit margin of 7.7%, which is lower than the prior quarters due to decreased production resulting in higher operating costs per barrel sold.

Our production levels for the three months ended March 31, 2010 were significantly lower than those of the same quarter in 2009 due primarily to the decision to reduce crude oil run rates at our facilities during the entire first quarter of 2010 because of the poor economics of running additional barrels. In early May 2010, we expect to increase the refinery’s second quarter throughput rates significantly compared to those of the first quarter in order to meet increasing specialty products demand and historically higher demand for fuel products during the second quarter.

Despite reduced refinery throughput rates, we generated $57.3 million in cash flow from operations and paid our quarterly distribution of $16.4 million to our unitholders in the first quarter of 2010. In addition to paying our quarterly distribution, we expect cash flow from operations will be used to help us (i) maintain compliance with the financial covenants of our credit agreements, (ii) improve our liquidity position and (iii) provide funding for general operational purposes.

LyondellBasell Agreements

Effective November 4, 2009, we entered into the LyondellBasell Agreements with Houston Refining, a wholly-owned subsidiary of LyondellBasell, to form a long-term exclusive specialty products affiliation. The initial term of the LyondellBasell Agreements lasts until October 31, 2014. After October 31, 2014 the agreements are automatically extended for additional one-year terms unless either party provides 24 months’ notice of a desire to terminate either the initial term or any renewal term. Under the terms of the LyondellBasell Agreements, (i) we are the exclusive purchaser of Houston Refining’s naphthenic lubricating oil production at its Houston, Texas refinery and are required to purchase a minimum of approximately 3,000 bpd, and (ii) Houston Refining will process a minimum of approximately 800 bpd of white mineral oil for us at its Houston, Texas refinery, which will supplement the existing white mineral oil production at our Karns City and Dickinson facilities. We also have exclusive rights to use certain LyondellBasell registered trademarks and tradenames including Tufflo, Duoprime, Duotreat, Crystex, Ideal and Aquamarine.

While no fixed assets were purchased under the LyondellBasell Agreements, these agreements have increased our working capital requirements by approximately $30 million at current market prices as of April 30, 2010.

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 which do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Item 3 “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” As of March 31, 2010, we have hedged approximately 12.8 million barrels of fuel products through December 2012 at an average refining margin of $11.72 per barrel with average refining margins ranging from a low of $11.32 in 2010 to a high of $12.16 in 2011. As of March 31, 2010, we have approximately 0.4 million barrels of crude oil swaps and options through June 2010 to hedge our purchases of crude oil for specialty products production. The strike prices and types of these crude oil swaps and options vary. Please refer to Note 7 under Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for a detailed listing of 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 fuels products sold as an important measure of our ability to effectively utilize our refining assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our 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 include 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.

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, Calumet GP, LLC.

Results of Operations for the Three Months Ended March 31, 2010 and 2009

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,
	2010		2009
	(In bpd)
Total sales volume (1)		51,700		54,422
Total feedstock runs (2)		48,331		63,219
Facility production: (3) Specialty products:
Lubricating oils		11,279		11,650
Solvents		8,070		8,267
Waxes		1,009		1,101
Fuels		1,150		666
Asphalt and other by-products		5,766		7,735

Total		27,274		29,419

Fuel products:
Gasoline		8,777		11,078
Diesel		8,986		12,750
Jet fuel		5,254		7,346
By-products		297		275

Total		23,314		31,449

Total facility production		50,588		60,868


(1)		Total sales volume includes sales from the production of 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 certain third-party facilities pursuant to supply and/or processing agreements. The decrease in feedstock runs for the three months ended March 31, 2010 compared to the same period in 2009 is primarily due to the decision to reduce crude oil run rates at our facilities during the entire first quarter of 2010 because of the poor economics of running additional barrels.

(3)		Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, including the LyondellBasell Agreements in 2010. The difference between total 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 decrease in production is a result of reduced feedstock runs as discussed above.

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


	Three Months Ended March 31,
	2010			2009
	(In millions)
Sales	$	484.6		$	414.3
Cost of sales		452.9			335.3

Gross profit		31.7			79.0

Operating costs and expenses:
Selling, general and administrative		7.2			9.3
Transportation		20.2			15.2
Taxes other than income taxes		1.0			1.1
Other		0.4			0.4

Operating income		2.9			53.0

Other income (expense):
Interest expense		(7.4	)		(8.6	)
Realized loss on derivative instruments		(0.6	)		(8.5	)
Unrealized gain (loss) on derivative instruments		(7.8	)		39.7
Other		—			0.1

Total other income (expense)		(15.8	)		22.7

Net income (loss) before income taxes		(12.9	)		75.7
Income tax expense		0.2			0.1

Net income (loss)	$	(13.1	)	$	75.6

EBITDA	$	9.1		$	99.6

Adjusted EBITDA	$	20.8		$	50.1

Non-GAAP Financial Measures

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

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

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

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

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

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

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

We define EBITDA as net income plus interest expense (including debt issuance and extinguishment costs), taxes and depreciation and amortization. We define Adjusted EBITDA to be Consolidated EBITDA as defined in our credit facilities. Consistent with that definition, Adjusted EBITDA means, for any period: (1) net income plus (2)(a) interest expense; (b) taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) unrealized items decreasing net income (including the non-cash impact of restructuring, decommissioning and asset impairments in the periods presented); and (f) other non-recurring expenses reducing net income which do not represent a cash item for such period; minus (3)(a) tax credits; (b) unrealized items increasing net income (including the non-cash impact of restructuring, decommissioning and asset impairments in the periods presented); (c) unrealized gains from mark to market accounting for hedging activities; and (d) other non-recurring expenses and unrealized items that reduced net income for a prior period, but represent a cash item in the current period.

We are required to report Adjusted EBITDA to our lenders under our credit facilities and it is used to determine our compliance with the consolidated leverage and consolidated interest coverage tests thereunder. Please refer to “Liquidity and Capital Resources — Debt and Credit Facilities” within this item for additional details regarding our credit agreements.

EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss), 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 and Adjusted EBITDA, management recognizes and considers the limitations of this measurement. EBITDA and Adjusted EBITDA do not reflect our obligations for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EDITDA and Adjusted EBITDA are only two of the measurements that management utilizes. Moreover, our EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA and Adjusted EBITDA in the same manner. The following tables present a reconciliation of both net income (loss) to EBITDA and Adjusted EBITDA and Adjusted EBITDA and EBITDA to net cash provided by operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.


	Three Months Ended
	March 31,
	2010			2009
	(In millions)
Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA:
Net income (loss)	$	(13.1	)	$	75.6
Add:
Interest expense		7.4			8.6
Depreciation and amortization		14.6			15.3
Income tax expense		0.2			0.1

EBITDA	$	9.1		$	99.6

Add:
Unrealized (gain) loss from mark to market accounting for hedging activities	$	8.8		$	(46.4	)
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		2.9			(3.1	)

Adjusted EBITDA	$	20.8		$	50.1


	Three Months Ended
	March 31,
	2010			2009
	(In millions)
Reconciliation of Adjusted EBITDA and EBITDA to net cash provided by operating activities:
Adjusted EBITDA	$	20.8		$	50.1
Add:
Unrealized gain (loss) from mark to market accounting for hedging activities		(8.8	)		46.4
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		(2.9	)		3.1

EBITDA	$	9.1		$	99.6

Add:
Cash interest expense		(6.5	)		(7.7	)
Unrealized (gain) loss on derivative instruments		7.8			(39.7	)
Income taxes		(0.2	)		(0.1	)
Provision for doubtful accounts		(0.1	)		0.2
Changes in assets and liabilities:
Accounts receivable		(17.4	)		7.0
Inventory		26.3			(30.5	)
Other current assets		5.6			4.7
Derivative activity		1.0			(7.2	)
Accounts payable		28.5			2.8
Accrued liabilities		1.1			1.6
Other, including changes in noncurrent assets and liabilities		2.1			1.9

Net cash provided by operating activities	$	57.3		$	32.6

Changes in Results of Operations for the Three Months Ended March 31, 2010 and 2009

Sales. Sales increased $70.4 million, or 17.0%, to $484.6 million in the three months ended March 31, 2010 from $414.3 million in the three months ended March 31, 2009. Sales for each of our principal product categories in these periods were as follows:


	Three Months Ended March 31,
	2010		2009		% Change
	(Dollars in millions)
Sales by segment:
Specialty products:
Lubricating oils	$	164.0	$	118.3		38.7	%
Solvents		87.9		54.5		61.2	%
Waxes		26.2		22.4		17.1	%
Fuels (1)		1.7		2.7		(34.6	)%
Asphalt and by-products (2)		25.7		19.1		34.0	%

Total specialty products	$	305.5	$	217.0		40.8	%

Total specialty products sales volume (in barrels)		2,455,000		2,213,000		10.9	%
Fuel products:
Gasoline	$	75.9	$	74.9		1.4	%
Diesel		64.2		81.7		(21.3	)%
Jet fuel		37.6		39.2		(4.2	)%
By-products (3)		1.4		1.5		(6.6	)%

Total fuel products	$	179.1	$	197.3		(9.2	)%

Total fuel products sales volume (in barrels)		2,198,000		2,685,000		(18.1	)%
Total sales	$	484.6	$	414.3		17.0	%

Total sales volume (in barrels)		4,653,000		4,898,000		(5.0	)%


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

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

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

Specialty products segment sales for the three months ended March 31, 2010 increased $88.5 million, or 40.8%, primarily as a result of an increase in the average selling price per barrel, increasing our sales by 29.9%, and a 10.9% increase in sales volume as compared to the same period in 2009. Specialty products pricing increased in all categories compared to a 91.5% increase in the average cost of crude oil per barrel for the three months ended March 31, 2010 as compared to the same period in 2009. Sales volume increased from approximately 2.2 million barrels in the first quarter of 2009 to approximately 2.5 million barrels in the first quarter of 2010 primarily as a result of increased demand for lubricating oils, solvents and waxes with improved overall economic conditions as well as specialty products sales from the LyondellBasell Agreements beginning in the fourth quarter of 2009.

Fuel products segment sales for the three months ended March 31, 2010 decreased $18.2 million, or 9.2%, due to an 18.1% decrease in sales volume as compared to the first quarter of 2009. The decrease in sales volume was primarily due to the decision to reduce crude oil run rates at our Shreveport refinery during the entire first quarter of 2010 because of the poor economics of running additional barrels. In addition, losses on our fuel products cash flow hedges recorded in sales increased $50.1 million compared to the prior period in 2009. These decreases were offset by a 55.6% increase in the average selling price per barrel as compared to the 93.7% increase in the average cost of crude oil per barrel for the same period in 2009. Please see “Gross Profit” below for a discussion of the net impact of our crude oil and fuel products derivative instruments designated as hedges.

Gross Profit. Gross profit decreased $47.3 million, or 59.9%, to $31.7 million for the three months ended March 31, 2010 from $79.0 million for the three months ended March 31, 2009. Gross profit for our specialty products and fuel products segments was as follows:


	Three Months Ended March 31,
	2010			2009			% Change
	(Dollars in millions)
Gross profit by segment:
Specialty products	$	23.4		$	59.8			(60.8	)%
Percentage of sales		7.7	%		27.6	%
Fuel products	$	8.3		$	19.2			(56.9	)%
Percentage of sales		4.6	%		9.7	%
Total gross profit	$	31.7		$	79.0			(59.9	)%
Percentage of sales		6.5	%		19.1	%

The decrease of $36.4 million in specialty products segment gross profit was primarily due to an increase of 91.5% in the average cost of crude oil per barrel and a decline in production primarily due to the decision to reduce crude oil run rates at our facilities as a result of the poor economics of running additional barrels. The reductions in gross profit were partially offset by an increase in the average selling price per barrel, increasing our sales by 29.9%, and an increase in sales volume of 10.9%, as discussed above.

Fuel products segment gross profit was negatively impacted by the sales volume of our fuel products falling by 18.1%, as discussed above. In addition, the average cost of crude oil per barrel increased by 93.7% as compared to an increased average selling price per barrel of 55.6%. The increase in sales prices lagged the increase in the cost of crude oil due primarily to lower crack spreads for all fuel products in the first quarter of 2010 as compared to the same period in 2009. Partially offsetting these decreases was a $3.8 million net increase in derivative gains on our fuel products cash flow hedges recorded in sales and cost of sales.

Selling, general and administrative. Selling, general and administrative expenses decreased $2.2 million, or 23.1%, to $7.2 million in the three months ended March 31, 2010 from $9.3 million in the three months ended March 31, 2009. This decrease was primarily due to reduced incentive compensation costs of $0.9 million in 2010 as compared to 2009 due to the lower profitability in the first quarter of 2010 compared to the prior period in 2009 as well as reduced bad debt expense of $0.3 million.

Transportation. Transportation expenses increased $5.1 million, or 33.6%, to $20.2 million in the three months ended March 31, 2010 from $15.2 million in the three months ended March 31, 2009 primarily as a result of increased lubricating oils, solvents and waxes sales volumes.

Interest Expense. Interest expense decreased $1.2 million, or 14.0%, to $7.4 million in the three months ended March 31, 2010 from $8.6 million in the three months ended March 31, 2009 primarily due to both lower interest rates and lower balances being carried on the revolver and term loan during the quarter ended March 31, 2010 as compared to the same period in 2009.

Realized loss on derivative instruments. Realized loss on derivative instruments decreased $7.9 million to $0.6 million in the three months ended March 31, 2010 from $8.5 million in realized loss for the three months ended March 31, 2009. This decreased loss was primarily due to realized losses of approximately $14.3 million in 2009 on

crude oil derivatives in our specialty products segment not designated as hedges due to the significant decline in crude oil prices in 2009 and significantly less settlement activity related to smaller volumes of crude oil derivatives which were not designated as hedges. Partially offsetting these reduced losses were realized crack spread derivative gains in our fuel products segment of $4.6 million during the first three months of 2009, with minimal comparable activity during the same period in 2010.

Unrealized gain (loss) on derivative instruments. Unrealized gain (loss) on derivative instruments decreased $47.5 million, to a $7.8 million loss in the three months ended March 31, 2010 from a gain of $39.7 million in the three months ended March 31, 2009. This change was primarily due to increased unrealized gains in the first quarter of 2009 on our gasoline crack spread derivatives that were executed to economically lock in gains on a portion of our fuel products segment derivatives and lower volumes of these derivatives outstanding in the first quarter of 2010 as well as less market volatility.

Liquidity and Capital Resources

The following should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation ¾ Liquidity and Capital Resources” included under Item 7 in our 2009 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 6 under 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 and debt service. We expect that our principal uses of cash in the future will be for working capital as we plan to increase our throughput rate at the Shreveport refinery and increased working capital requirements from the LyondellBasell Agreements, distributions to our limited partners and general partner, debt service, and capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and cause us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs. Given the current credit environment and our continued efforts to reduce leverage to ensure continued covenant compliance under our credit facilities, we do not anticipate completing any significant acquisitions, internal growth projects or replacement and environmental capital expenditures which would cause total spending to exceed $30.0 million during 2010. We anticipate future capital expenditures will be funded with current cash flow from operations and borrowings under our existing revolving credit facility.

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,
	2010			2009
	(In millions)
Net cash provided by operating activities	$	57.3		$	32.6
Net cash used in investing activities	$	(5.6	)	$	(4.9	)
Net cash used in financing activities	$	(51.8	)	$	(27.7	)

Operating Activities. Operating activities provided $57.3 million in cash during the three months ended March 31, 2010 compared to $32.6 million during the three months ended March 31, 2009. The increase in cash provided by operating activities was primarily due to a reduction in inventory levels at our Shreveport and Princeton refineries as well as increased accounts payable resulting from improved payment terms and utilization of letters of credit with certain crude oil suppliers. Partially offsetting these improvements were higher accounts receivable as sales prices for both specialty products and fuel products as well as specialty products sales volume increased quarter over quarter.

Investing Activities. Cash used in investing activities increased to $5.6 million during the three months ended March 31, 2010 compared to $4.9 million during the three months ended March 31, 2009 as our capital expenditures remained relatively consistent with the prior year.

Financing Activities. Financing activities used cash of $51.8 million during the three months ended March 31, 2010 as compared to $27.7 million during the three months ended March 31, 2009. The increased use of cash was primarily due to cash provided by operating activities being used to reduce borrowings under our revolving credit facility.

On April 12, 2010, we declared a quarterly cash distribution of $0.455 per unit on all outstanding units, or $16.4 million, for the quarter ended March 31, 2010. The distribution will be paid on May 14, 2010 to unitholders of record as of the close of business on May 4, 2010. This quarterly distribution of $0.455 per unit equates to $1.82 per unit, or $65.6 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 and to expand existing facilities, such as projects that increase operating capacity. 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,
	2010		2009
	(In millions)
Capital improvement expenditures	$	0.2	$	1.9
Replacement capital expenditures		2.1		2.4
Environmental capital expenditures		3.4		0.6

Total	$	5.7	$	4.9

We anticipate that future capital expenditure requirements will be provided primarily through cash from operations and available borrowings under our revolving credit facility. During the first quarter of 2010 and for the remainder of 2010, we are limiting our overall capital expenditures to required environmental expenditures, necessary replacement capital expenditures to maintain our facilities and minor capital improvement projects to reduce energy costs, improve finished product quality and finished product yields. We estimate our replacement and environmental capital expenditures will be approximately $4.0 million per quarter for the remainder of 2010 with total capital expenditures remaining generally consistent with 2009.

Debt and Credit Facilities

As of March 31, 2010, our credit facilities consist 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 facility and a $50.0 million prefunded letter of credit facility 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 discount.

Borrowings under the amended revolving credit facility are limited by advance rates of percentages of eligible accounts receivable and inventory (the borrowing base) as defined by the revolving credit agreement. As such, the borrowing base can fluctuate based on changes in selling prices of our products and our current material costs, primarily the cost of crude oil. 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, 2010, this margin was 25 basis points for prime and 175 basis points for LIBOR; however, it fluctuates based on quarterly measurement of our Consolidated Leverage Ratio as discussed below. The lenders under our revolving credit facility have a first priority lien on our cash, accounts receivable and inventory and a second priority lien on our fixed assets. The revolving credit facility matures in January 2013. On March 31, 2010, we had availability on our revolving credit facility of $141.2 million, based upon a $209.4 million borrowing base, $61.2 million in outstanding standby letters of credit, and outstanding borrowings of $7.0 million under the revolving credit facility. The continued improvement in our availability of $34.0 million from December 31, 2009 is due to cash generated from operations offset by capital expenditures, distributions to unitholders, and debt service costs. We believe that we have sufficient cash flow from operations and borrowing capacity to meet our financial commitments, minimum quarterly distributions to unitholders, debt service obligations, contingencies and anticipated capital expenditures.

Contractual Obligations and Commercial Commitments

The amounts presented in the table below include our best estimate as of March 31, 2010 of the amount and timing of the net obligations associated with those contractual obligations that varied significantly since December 31, 2009. A summary of our total contractual cash obligations as of March 31, 2010 is as follows:


			Payments Due by Period
			Less Than		1-3		3-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Long-term debt obligations, excluding capital lease obligations	$	377,229	$	3,850	$	14,656	$	7,700	$	351,023
Interest on long-term debt at contractual rates		84,091		19,572		37,509		27,010		—
Capital lease obligations		2,613		1,074		1,361		178		—
Operating lease obligations (1)		32,697		11,109		14,174		6,926		488
Letters of credit (2)		111,215		61,215		50,000		—		—
Purchase commitments (3)		724,731		302,693		235,775		186,263		—

Total obligations	$	1,332,576	$	399,513	$	353,475	$	228,077	$	351,511


(1)		We have various operating leases for the use of land, storage tanks, pressure stations, railcars, equipment, precious metals and office facilities that extend through August 2015.

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


(3)		Purchase commitments consist of obligations to purchase fixed volumes of crude oil, 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 Penreco acquisition on January 3, 2008, we entered into a feedstock purchase agreement with ConocoPhillips Company (“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 $53.5 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of March 31, 2010. 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 Item 7 of our 2009 Annual Report.

Recent Accounting Pronouncements

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

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 Item 7A in our 2009 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 7 under Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for additional discussion related to derivative instruments and hedging activities.

Commodity Price Risk

As of March 31, 2010, we estimate we have executed derivative instruments to hedge approximately 15% to 20% of forecasted specialty products segment crude oil purchases through June 30, 2010. Also, as of March 31, 2010 we estimate we are over 60% and 50% hedged for the forward twelve and twenty-four months, respectively, for our fuel products segment crack spread exposure. We enter into derivative instruments to purchase crude oil and sell gasoline, diesel or jet fuel in an equal quantity to hedge an implied fuel products crack spread. The change in fair value expected from a $1 per unit increase in commodity prices are shown in the table below:


	In millions
Crude oil swaps	$	13.2
Diesel swaps	$	(5.9	)
Jet fuel swaps	$	(4.1	)
Gasoline swaps	$	(3.2	)
Crude oil collars	$	0.4
Jet fuel collars	$	0.8

Interest Rate Risk

We are exposed to market risk from fluctuations in interest rates. Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates. As of March 31, 2010, we had approximately $377.2 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, 2010 would be expected to have an impact on net income and cash flows of approximately $3.8 million.

We have a $375.0 million revolving credit facility as of March 31, 2010, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had borrowings of $7.0 million outstanding under this facility as of March 31, 2010, bearing interest at the prime rate plus the applicable margin of 25 basis points.

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, 2010 disclosed in Note 7 under 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 Contracts by Expiration Dates	Barrels		BPD		Spread ($/Bbl)
Second Quarter 2010		1,820,000		20,000	$	11.32
Third Quarter 2010		1,840,000		20,000		11.32
Fourth Quarter 2010		1,840,000		20,000		11.32
Calendar Year 2011		5,614,000		15,381		12.16
Calendar Year 2012		1,685,500		4,605		11.60

Totals		12,799,500
Average price					$	11.72

The following table provides a summary of our derivative instruments and implied crack spreads for the crude oil and gasoline swaps as of March 31, 2010 disclosed in Note 7 under Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements,” none of which are designated as hedges. These trades were used to economically lock a portion of the mark-to-market valuation gain for the above crack spread trades.


					Implied Crack
Crude Oil and Fuel Products Contracts by Expiration Dates	Barrels		BPD		Spread ($/Bbl)
Second Quarter 2010		136,500		1,500	$	0.17
Third Quarter 2010		138,000		1,500		0.17
Fourth Quarter 2010		138,000		1,500		0.17

Totals		412,500
Average price					$	0.17

At March 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)
Calendar Year 2011		814,000		2,230	$	4.17	$	6.23

Totals		814,000
Average price					$	4.17	$	6.23

Specialty Products Segment

At March 31, 2010, the Company had 410,000 barrels of crude oil derivative positions related to crude oil purchases in its specialty products segment, none of which are designated as hedges. Please refer to Note 7 under Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for detailed information on these derivatives. At March 31, 2010, we have provided no cash collateral in credit support to our hedging counterparties.

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, 2010 at the reasonable assurance level.

(b) Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting during the first fiscal quarter of 2010 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 set forth above under Note 5 “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

There have been no material changes in the risk factors previously disclosed in our 2009 Annual Report under the section “Risk Factors.”

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 2009 Annual Report, which could materially affect our business, financial condition or future results. The risks described in this Quarterly Report and in our 2009 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

The following table summarizes the purchases of equity securities by Calumet GP, LLC, the general partner of the Company.


					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, 2010 – January 31, 2010		—	$	—		—		—
February 1, 2010 – February 28, 2010 (1)		12,718		19.4133		—		—
March 1, 2010 – March 31, 2010		—		—		—		—

Total		12,718	$	19.4133		—		—


(1)		A total of 12,718 common units were purchased by Calumet GP, LLC, our general partner, related to the Calumet GP, LLC Long-Term Incentive Plan (the “Plan”). The Plan 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 Plan, refer to Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation — Long-Term, Unit-Based Awards” in the Company’s 2009 Annual Report for the year ended December 31, 2009.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Reserved

None.

Item 5. Other Information

Entry into a Material Definitive Agreement

On May 4, 2010, Calumet Shreveport Fuels, LLC (“Calumet Shreveport Fuels”), a wholly-owned subsidiary of the Company, entered into Amendment No. 3 to Crude Oil Supply Agreement (the “Shreveport Amendment”) with Legacy Resources Co., L.P. (“Legacy”), a related party. The Shreveport Amendment, effective as of April 1, 2010, modifies the market-based pricing mechanism established in the Crude Oil Supply Agreement, effective as of September 1, 2009, 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.

On May 4, 2010, Calumet Lubricants Co., L.P. (“Calumet Lubricants”), a wholly-owned subsidiary of the Company, entered into Amendment No. 3 to Crude Oil Supply Agreement (the “Princeton Amendment”) with Legacy. The Princeton Amendment, effective as of April 1, 2010, modifies the market-based pricing mechanism established in the Crude Oil Supply Agreement, effective as of April 30, 2008, by and between Calumet Lubricants and 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.

Because Legacy is owned in part by The Heritage Group, an affiliate of the Company’s general partner, the Company’s chief executive officer and president, F. William Grube and the Company’s executive vice president and chief operating officer, Jennifer G. Straumins, the terms of the Shreveport Amendment and the Princeton Amendment were reviewed by the Company’s conflicts committee, which consists entirely of independent directors. The conflicts committee approved the Shreveport Amendment and the Princeton Amendment after determining that their terms are fair and reasonable to the Company.

The foregoing description is qualified in its entirety by reference to the Shreveport Amendment and the Princeton Amendment, copies of which are attached hereto as Exhibit 10.22 and Exhibit 10.23, respectively, and incorporated into this Quarterly Report by reference.

Item 6. Exhibits

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


Exhibit
Number		Description
10.22		Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier.

10.23		Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier.

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.

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 7, 2010

Index to Exhibits


Exhibit
Number		Description
10.22		Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Shreveport Fuels, LLC., customer, and Legacy Resources Co., L.P., supplier.

10.23		Amendment No. 3 to Crude Oil Supply Agreement, dated as of May 4, 2010 and effective April 1, 2010, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier.

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.

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. Reserved Item 5. Other Information Item 6. Exhibits

Exhibits

EX-10.22 EX-10.23 EX-31.1 EX-31.2 EX-32.1

CLMT 10-Q Quarter ended March 31, 2010

Exhibits