CLMT 10-Q Quarterly Report June 30, 2010

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

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10-Q 1 h75020e10vq.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 June 30, 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		37-1516132
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification Number)

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Registration S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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


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

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

At August 4, 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 and Six Months Ended June 30, 2010

Table of Contents


	Page
Part I
Item 1. Financial Statements
Condensed Consolidated Balance Sheets		5
Unaudited Condensed Consolidated Statements of Operations		6
Unaudited Condensed Consolidated Statements of Partners’ Capital		7
Unaudited Condensed Consolidated Statements of Cash Flows		8
Notes to Unaudited Condensed Consolidated Financial Statements		9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3. Quantitative and Qualitative Disclosures About Market Risk		43
Item 4. Controls and Procedures		45
Part II
Item 1. Legal Proceedings		46
Item 1A. Risk Factors		46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 3. Defaults Upon Senior Securities		46
Item 4. Reserved		46
Item 5. Other Information		46
Item 6. Exhibits		46
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 in this Quarterly Report 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, our Quarterly Report filed with the Securities and Exchange Commission (the “SEC”) on May 7, 2010 (our “2010 First Quarterly Report”) and in our Annual Report on Form 10-K filed with 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, including legislation related to the Dodd-Frank Wall Street Reform and Consumer Protection Act;

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

	•		hurricane or other weather interference with business operations;

	•		fluctuations in the debt and equity markets;

	•		accidents or other unscheduled shutdowns; and

	•		general economic, market or business conditions.

Other factors described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Our forward looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward looking statement. Please 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.

PART I

Item 1. Financial Statements

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2010			December 31, 2009
	(Unaudited)
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	67		$	49
Accounts receivable:
Trade		148,456			116,914
Other		1,726			5,854

		150,182			122,768
Inventories		146,833			137,250
Derivative assets		932			30,904
Prepaid expenses and other current assets		3,135			1,811
Deposits		3,272			6,861

Total current assets		304,421			299,643
Property, plant and equipment, net		621,043			629,275
Goodwill		48,335			48,335
Other intangible assets, net		33,689			38,093
Other noncurrent assets, net		22,599			16,510

Total assets	$	1,030,087		$	1,031,856


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable	$	135,428		$	92,110
Accounts payable — related party		25,251			17,866
Accrued salaries, wages and benefits		5,897			6,500
Taxes payable		7,717			7,551
Other current liabilities		4,285			6,114
Current portion of long-term debt		4,836			5,009
Derivative liabilities		10,449			4,766

Total current liabilities		193,863			139,916
Pension and postretirement benefit obligations		8,955			9,433
Other long-term liabilities		1,097			1,111
Long-term debt, less current portion		404,006			396,049

Total liabilities		607,921			546,509
Commitments and contingencies
Partners’ capital:
Common unitholders (22,213,778 units and 22,166,000 units issued and outstanding at June 30, 2010 and December 31, 2009, respectively)		391,580			418,902
Subordinated unitholders (13,066,000 units issued and outstanding at June 30, 2010 and December 31, 2009)		17,752			34,714
General partner’s interest (719,995 units and 719,020 units issued and outstanding at June 30, 2010 and December 31, 2009, respectively)		18,171			19,087
Accumulated other comprehensive income (loss)		(5,337	)		12,644

Total partners’ capital		422,166			485,347

Total liabilities and partners’ capital	$	1,030,087		$	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						For the Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands, except per unit data)
Sales	$	514,652		$	444,039		$	999,269		$	858,303
Cost of sales		465,033			425,671			917,974			760,964

Gross profit		49,619			18,368			81,295			97,339

Operating costs and expenses:
Selling, general and administrative		8,321			6,939			15,491			16,261
Transportation		19,956			16,087			40,202			31,242
Taxes other than income taxes		1,098			865			2,123			1,989
Other		480			278			808			697

Operating income (loss)		19,764			(5,801	)		22,671			47,150

Other income (expense):
Interest expense		(7,277	)		(8,447	)		(14,711	)		(17,090	)
Realized gain (loss) on derivative instruments		(5,297	)		7,637			(5,858	)		(833	)
Unrealized gain (loss) on derivative instruments		(8,008	)		(17,582	)		(15,766	)		22,158
Other		9			(1,727	)		(50	)		(1,585	)

Total other income (expense)		(20,573	)		(20,119	)		(36,685	)		2,650

Net income (loss) before income taxes		(809	)		(25,920	)		(13,714	)		49,800
Income tax expense		98			67			260			149

Net income (loss)	$	(907	)	$	(25,987	)	$	(13,974	)	$	49,651

Allocation of net income (loss):
Net income (loss)	$	(907	)	$	(25,987	)	$	(13,974	)	$	49,651
Less:
General partner’s interest in net income (loss)		(18	)		(519	)		(279	)		991
Holders of incentive distribution rights		—			—			—			—

Net income (loss) available to limited partners	$	(889	)	$	(25,468	)	$	(13,695	)	$	48,660

Weighted average limited partner units outstanding — basic and diluted		35,359			32,232			35,355			32,232

Common and subordinated unitholders’ basic and diluted net income (loss) per unit	$	(0.03	)	$	(0.79	)	$	(0.39	)	$	1.51

Cash distributions declared per common and subordinated unit	$	0.455		$	0.45		$	0.91		$	0.90

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 (Loss)			Partner			Common			Subordinated			Total
	(In thousands)
Balance at December 31, 2009	$	12,644		$	19,087		$	418,902		$	34,714		$	485,347
Comprehensive loss:
Net loss					(279	)		(8,623	)		(5,072	)		(13,974	)
Cash flow hedge gain reclassified to net income (loss)		(7,521	)											(7,521	)
Change in fair value of cash flow hedges		(10,924	)											(10,924	)
Defined benefit pension and retiree health benefit plans		464												464

Comprehensive loss														(31,955	)
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								999						999
Distributions to partners					(655	)		(20,243	)		(11,890	)		(32,788	)

Balance at June 30, 2010	$	(5,337	)	$	18,171		$	391,580		$	17,752		$	422,166

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Six Months Ended
	June 30,
	2010			2009
	(In thousands)
Operating activities
Net income (loss)	$	(13,974	)	$	49,651
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		31,408			32,446
Amortization of turnaround costs		4,100			3,370
Provision for doubtful accounts		(91	)		(724	)
Unrealized (gain) loss on derivative instruments		15,766			(22,158	)
Other non-cash activity		1,114			2,098
Changes in assets and liabilities:
Accounts receivable		(27,323	)		(3,445	)
Inventories		(9,583	)		(27,590	)
Prepaid expenses and other current assets		(1,324	)		(1,480	)
Derivative activity		1,443			(201	)
Deposits		3,589			4,000
Other assets		(8,548	)		(4,286	)
Accounts payable		48,584			23,346
Accrued salaries, wages and benefits		(603	)		121
Taxes payable		166			1,355
Other liabilities		(2,143	)		304
Pension and postretirement benefit obligations		(14	)		631

Net cash provided by operating activities		42,567			57,438
Investing activities
Additions to property, plant and equipment		(17,017	)		(13,345	)
Proceeds from disposal of property and equipment		121			737

Net cash used in investing activities		(16,896	)		(12,608	)
Financing activities
Proceeds from (Repayments of) borrowings — revolving credit facility		9,240			(6,725	)
Repayments of borrowings — term loan credit facility		(1,925	)		(1,925	)
Payments on capital lease obligations		(743	)		(618	)
Proceeds from public equity offering, net		793			—
Contribution from Calumet GP, LLC		18			—
Change in bank overdraft		—			(5,746	)
Common units repurchased for vested phantom unit grants		(248	)		(164	)
Distributions to partners		(32,788	)		(29,636	)

Net cash used in financing activities		(25,653	)		(44,814	)

Net increase in cash and cash equivalents		18			16
Cash and cash equivalents at beginning of period		49			48

Cash and cash equivalents at end of period	$	67		$	64

Supplemental disclosure of cash flow information
Interest paid	$	13,074		$	15,701
Income taxes paid	$	89		$	41

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands)

1. Description of the Business

Calumet Specialty Products Partners, L.P. (the “Company”) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of June 30, 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 June 30, 2010 and for the three and six months ended June 30, 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 and six months ended June 30, 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. The Company issued these unaudited condensed consolidated financial statements by filing them with the SEC and has 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 ” (the “ASU”), which amends ASC No. 820, “Fair Value Measurements and Disclosures” to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The ASU also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. The ASU is effective for the first reporting period (including interim periods) beginning after December 15, 2009. The Company has adopted this ASU standard effective January 1, 2010; however, the Company’s adoption of the ASU 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:


	June 30,		December 31,
	2010		2009
Raw materials	$	9,267	$	1,323
Work in process		55,009		51,304
Finished goods		82,557		84,623

	$	146,833	$	137,250

The replacement cost of these inventories, based on current market values, would have been $38,720 and $30,420 higher as of June 30, 2010 and December 31, 2009, respectively. During both the three and six months ended June 30, 2010 and 2009, the Company recorded $883 and $0, respectively, of gains in cost of sales in the unaudited condensed consolidated statements of operations due to the liquidation of lower cost inventory layers.

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 $135,000. 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 taxation and regulatory authorities, such as the Louisiana Department of Environmental Quality (“LDEQ”), the U.S. Environmental Protection Agency (“EPA”), the Internal Revenue Service and the Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. 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

Effective April 1, 2010, the Company entered into a new Shreveport collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial, and Service Workers International Union that 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 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 operated under a variance from the LDEQ until the environmental operating unit was operational 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 capital expenditures during 2010 at its Cotton Valley refinery in connection with this matter.

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, contractors, state and local government authorities and customers. The Company maintains safety, training, and maintenance programs as part of its ongoing efforts to ensure compliance with applicable laws and

regulations. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. The Company has implemented an internal program of inspection designed to monitor and enforce compliance with worker safety requirements as well as a quality system that meets the requirements of the ISO-9001-2000 Standard. The integrity of the Company’s ISO-9001-2000 Standard certification is maintained through surveillance audits by its registrar at regular intervals designed to ensure adherence to the standards. In April 2010, the Company received its certification to the ISO-9001-2008 Standard.

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 its 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 June 30, 2010 and December 31, 2009, the Company had outstanding standby letters of credit of $66,875 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 June 30, 2010 and December 31, 2009, the Company had availability to issue letters of credit of $112,510 and $107,285, respectively, under its revolving credit facility. As discussed in Note 6, as of June 30, 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:


	June 30,			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% (4.44% and 4.27% at June 30, 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 4.77% and 6.00% for the periods ended June 30, 2010 and December 31, 2009, respectively	$	369,310		$	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 June 30, 2010 and December 31, 2009, respectively), interest payments monthly, borrowings due January 2013		49,140			39,900
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly through January 2012		2,278			2,938
Less unamortized discount on senior secured first lien term loan with third-party lenders		(11,886	)		(13,015	)

Total long-term debt		408,842			401,058
Less current portion of long-term debt		4,836			5,009

	$	404,006		$	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 June 30, 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 June 30, 2010 under the revolving credit facility was $228,525 with $112,510 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 June 30, 2010, the Company was in compliance with all financial covenants under its credit agreements.

As of June 30, 2010, maturities of the Company’s long-term debt are as follows:


Year	Maturity
2010	$	2,422
2011		4,844
2012		4,401
2013		53,226
2014		3,850
Thereafter		351,985

Total	$	420,728

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 recorded the following derivative assets and liabilities at their fair values as of June 30, 2010 and December 31, 2009:


	Derivative Assets						Derivative Liabilities
	June 30, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	6,057		$	134,587		$	25,406		$	—
Gasoline swaps		—			(6,147	)		(8,816	)		—
Diesel swaps		(5,125	)		(67,731	)		(13,093	)		—
Jet fuel swaps		—			(26,926	)		(9,138	)		—
Specialty products segment:
Crude oil collars		—			—			—			—
Crude oil swaps		—			—			—			—
Natural gas swaps		—			—			—			—
Interest rate swaps:		—			—			(2,854	)		(2,752	)

Total derivative instruments designated as hedges		932			33,783			(8,495	)		(2,752	)


	Derivative Assets					Derivative Liabilities
	June 30, 2010		December 31, 2009			June 30, 2010			December 31, 2009
Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps (1)		—		13,062			(5,047	)		—
Gasoline swaps (1)		—		(16,165	)		6,311			—
Diesel swaps		—		—			—			—
Jet fuel crack spread collars (2)		—		375			87			—
Specialty products segment:
Crude oil collars (3)		—		(151	)		(1,421	)		—
Crude oil swaps (3)		—		—			(246	)		—
Natural gas swaps (3)		—		—			(75	)		—
Interest rate swaps: (4)		—		—			(1,563	)		(2,014	)

Total derivative instruments not designated as hedges		—		(2,879	)		(1,954	)		(2,014	)

Total derivative instruments	$	932	$	30,904		$	(10,449	)	$	(4,766	)


(1)		The Company entered into derivative instruments, which do not qualify for hedge accounting, 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 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.

(3)		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.

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

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

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

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital as of, and for the three months ended, June 30, 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 (Loss)						Accumulated Other Comprehensive							Amount of Gain (Loss) Recognized in Net
	on Derivatives						Income (Loss) into Net Income (Loss)							Income (Loss) on Derivatives
	(Effective Portion)						(Effective Portion)							(Ineffective Portion)
								Three Months Ended							Three Months Ended
	June 30,						Location of (Gain)	June 30,						Location of Gain	June 30,
Type of Derivative	2010			2009			Loss	2010			2009			(Loss)	2010			2009
Fuel products segment:
Crude oil swaps	$	(95,836	)	$	194,531		Cost of sales	$	(18,178	)	$	22,903		Unrealized/ Realized	$	(3,500	)	$	1,146
Gasoline swaps		25,491			(90,944	)	Sales		5,874			(4,451	)	Unrealized/ Realized		(3,016	)		(618	)
Diesel swaps		41,122			(114,090	)	Sales		10,002			(18,769	)	Unrealized/ Realized		(43	)		(20,460	)
Jet fuel swaps		24,847			(11,836	)	Sales		—			—		Unrealized/ Realized		166			(446	)
Specialty products segment:
Crude oil collars		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Crude oil swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Natural gas swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Interest rate swaps:		(449	)		(606	)	Interest expense		511			772		Unrealized/ Realized		—			—

Total	$	(4,825	)	$	(22,945	)		$	(1,791	)	$	455			$	(6,393	)	$	(20,378	)

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended June 30, 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 Gain (Loss) on Derivatives						in Unrealized Gain (Loss) on Derivatives
	Three Months Ended						Three Months Ended
	June 30,						June 30,
Type of Derivative	2010			2009			2010			2009
Fuel products segment:
Crude oil swaps	$	(2,155	)	$	4,142		$	5,366		$	(28,224	)
Gasoline swaps		3,709			2,871			(7,161	)		29,101
Diesel swaps		(325	)		(1,663	)		325			1,663
Jet fuel swaps		—			—			—			—
Jet fuel collars		—			—			(162	)		(18	)
Specialty products segment:
Crude oil collars		(2,188	)		2,346			(2,245	)		359
Crude oil swaps		(1,686	)		—			(298	)		—
Natural gas swaps		—			—			(76	)		32
Interest rate swaps:		(205	)		(206	)		189			30

Total	$	(2,850	)	$	7,490		$	(4,062	)	$	2,943

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 six months ended, June 30, 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)
								Six Months Ended							Six Months Ended
	June 30,						Location of (Gain)	June 30,						Location of Gain	June 30,
Type of Derivative	2010			2009			Loss	2010			2009			(Loss)	2010			2009
Fuel products segment:
Crude oil swaps	$	(79,355	)	$	147,612		Cost of sales	$	(35,686	)	$	65,679		Unrealized/ Realized	$	(9,973	)	$	14,151
Gasoline swaps		19,650			(111,412	)	Sales		11,058			(23,828	)	Unrealized/ Realized		(4,551	)		2,026
Diesel swaps		32,556			(62,887	)	Sales		15,810			(47,507	)	Unrealized/ Realized		(1,224	)		(12,715	)
Jet fuel swaps		17,623			(11,836	)	Sales		—			—		Unrealized/ Realized		166			(446	)
Specialty products segment:
Crude oil collars		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Crude oil swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Natural gas swaps		—			(101	)	Cost of sales		—			307		Unrealized/ Realized		—			—
Interest rate swaps:		(1,398	)		(1,163	)	Interest expense		1,297			1,263		Unrealized/ Realized		—			—

Total	$	(10,924	)	$	39,787			$	(7,521	)	$	(4,086	)		$	(15,582	)	$	3,016

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the six months ended June 30, 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 Gain (Loss) on Derivatives						in Unrealized Gain (Loss) on Derivatives
	Six Months Ended						Six Months Ended
	June 30,						June 30,
Type of Derivative	2010			2009			2010			2009
Fuel products segment:
Crude oil swaps	$	(4,390	)	$	15,652		$	6,938		$	(37,213	)
Gasoline swaps		7,103			(2,865	)		(9,203	)		42,930
Diesel swaps		(650	)		(3,327	)		650			3,327
Jet fuel swaps		—			—			—			—
Jet fuel collars		—			—			(288	)		(177	)
Specialty products segment:
Crude oil collars		(2,959	)		(11,915	)		(1,268	)		12,531
Crude oil swaps		(1,662	)		—			(247	)		—
Natural gas swaps		(35	)		(1,507	)		(76	)		1,255
Interest rate swaps		(405	)		(410	)		450			28

Total	$	(2,998	)	$	(4,372	)	$	(3,044	)	$	22,681

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 received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits on the Company’s condensed consolidated balance sheets and not netted against derivative assets or liabilities. As of June 30, 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 June 30, 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 loss is $1,093 as of June 30, 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	$	13,951
2011		(5,520	)
2012		(9,524	)

Total	$	(1,093	)

Based on fair values as of June 30, 2010, the Company expects to reclassify $8,150 of net gains on derivative instruments from accumulated other comprehensive income (loss) to earnings during the next twelve months due to actual crude oil purchases, gasoline, diesel and jet fuel sales, and the payment of variable interest associated with floating rate debt. However, the amounts actually realized will be dependent on the fair values as of the date of settlements.

Crude Oil Swap and Collar Contracts — Specialty Products Segment

The Company is exposed to fluctuations in the price of crude oil, its principal raw material. The Company utilizes combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty products segment. These derivatives may be designated as cash flow hedges of the future purchase of crude oil if they meet the hedge criteria. The Company’s general policy is to enter into crude oil derivative contracts that mitigate the Company’s exposure to price risk associated with crude oil purchases related to specialty products production (for up to 70% of expected purchases). As of June 30, 2010, the Company has hedged at levels approximating 14.2% of its expected specialty products production for the three months ended September 30, 2010. 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 June 30, 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)
July 2010		155,000		5,000	$	70.43	$	84.46	$	94.46
August 2010		93,000		3,000		62.38		78.22		88.22

Totals		248,000
Average price					$	67.41	$	82.12	$	92.12


					Average
					Swap
Crude Oil Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
July 2010		62,000		2,000	$	75.33
August 2010		93,000		3,000		79.32

Totals		155,000
Average price					$	77.72

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 June 30, 2010, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as hedges.


					Average
	Barrels				Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Third Quarter 2010		1,871,000		20,337	$	67.41
Fourth Quarter 2010		1,840,000		20,000		67.29
Calendar Year 2011		5,796,000		15,879		76.71
Calendar Year 2012		3,557,000		9,719		85.99

Totals		13,064,000
Average price					$	76.58

At June 30, 2010, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges.


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

Totals		276,000
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				Average Swap
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.


					Average Swap
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, jet fuel and gasoline swap contracts for a period no longer than five years forward and for no more than 75% of forecasted fuel sales.

Diesel Swap Contracts

At June 30, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as hedges.


					Average Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
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
Calendar Year 2012		732,000		2,000		98.70

Totals		5,495,000
Average price					$	87.23

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.


					Average Swap
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 June 30, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as hedges.


					Average Swap
Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Calendar Year 2011		2,696,000		7,386	$	88.86
Calendar Year 2012		2,688,500		7,346		99.04

Totals		5,384,500
Average price					$	93.94

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.


					Average Swap
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 June 30, 2010, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as hedges.


					Average Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Third Quarter 2010		675,000		7,337	$	75.59
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		2,184,500
Average price					$	78.99

At June 30, 2010, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges.


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

Totals		276,000
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.


	Barrels				Average Swap
Gasoline Swap Contracts by Expiration Dates	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				Average Swap
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 June 30, 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 June 30, 2010, the Company had the following derivatives related to natural gas purchases, none of which are designated as hedges.


			Average Swap
Natural Gas Swap Contracts by Expiration Dates	MMBtus		($/MMBtu)
Third Quarter 2010		60,000	$	5.10
Fourth Quarter 2010		120,000		5.28

Totals		180,000
Average price			$	5.22

The Company did not have any derivatives related to natural gas purchases at December 31, 2009.

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 $334,226 and $328,543 at June 30, 2010 and December 31, 2009, respectively. The carrying values of borrowings under the Company’s senior secured revolving credit facility were $49,140 and $39,900 at June 30, 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 June 30, 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 June 30, 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, natural gas 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 June 30, 2010, the Company’s asset was reduced by approximately $5 and its liability was reduced by approximately $1,931. 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 June 30, 2010 were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Cash and cash equivalents	$	67	$	—	$	—		$	67
Crude oil swaps		—		—		26,170			26,170
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Natural gas swaps		—		—		—			—
Crude oil options		—		—		—			—
Jet fuel options		—		—		87			87
Pension Plan investments		13,063		—		—			13,063

Total assets at fair value	$	13,130	$	—	$	26,257		$	39,387

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(2,505	)		(2,505	)
Diesel swaps		—		—		(18,218	)		(18,218	)
Jet fuel swaps		—		—		(9,138	)		(9,138	)
Natural gas swaps		—		—		(75	)		(75	)
Crude oil options		—		—		(1,421	)		(1,421	)
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(4,417	)		(4,417	)

Total liabilities at fair value	$	—	$	—	$	(35,774	)	$	(35,774	)

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 six months ended June 30, 2010:


	Derivative
	Instruments, Net
Fair value at January 1, 2010	$	26,138
Realized losses		5,858
Unrealized losses		(15,766	)
Change in fair value of cash flow hedges		(10,924	)
Purchases, issuances and settlements		(14,823	)
Transfers in (out) of Level 3		—

Fair value at June 30, 2010	$	(9,517	)

Total gains (losses) included in net income (loss) attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of June 30, 2010	$	(15,766	)

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 and six months ended June 30, 2010 and 2009 was as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Net income (loss)	$	(907	)	$	(25,987	)	$	(13,974	)	$	49,651
Cash flow hedge gain reclassified to net income		(1,791	)		(2,775	)		(7,521	)		(4,086	)
Change in fair value of cash flow hedges		(4,825	)		(19,715	)		(10,924	)		(39,787	)
Defined benefit pension and retiree health benefit plans		59			95			464			189

Total comprehensive income (loss)	$	(7,464	)	$	(48,382	)	$	(31,955	)	$	5,967

11. Unit-Based Compensation and Distributions

A summary of the Company’s nonvested phantom units as of June 30, 2010 and the changes during the six months ended June 30, 2010 is presented below:


				Weighted Average
				Grant Date
Nonvested Phantom Units	Grant			Fair Value
Nonvested at December 31, 2009		57,493		$	12.42
Granted		59,992			18.94
Vested		(53,607	)		17.75
Forfeited		—			—

Nonvested at June 30, 2010		63,878		$	14.07

For the three months ended June 30, 2010 and 2009, compensation expense of $145 and $130, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. For the six months ended June 30, 2010 and 2009, compensation expense of $292 and $185, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. As of June 30, 2010 and 2009, there was a total of $899 and $473 of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately three years.

The Company’s distribution policy is as defined in its partnership agreement. For the six months ended June 30, 2010 and 2009, the Company made distributions of $32,788 and $29,636, 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 June 30, 2010 and 2009 were as follows:


	For the Three Months Ended June 30,
	2010						2009
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	21		$	—		$	62		$	3
Interest cost		334			6			332			11
Expected return on assets		(258	)		—			(187	)		—
Amortization of net (gain) loss		68			—			96			(1	)
Prior service cost		—			(9	)		—			—

Net periodic benefit cost	$	165		$	(3	)	$	303		$	13

The components of net periodic pension and other post retirement benefits cost for the six months ended June 30, 2010 and 2009 were as follows:


	For the Six Months Ended June 30,
	2010						2009
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	42		$	—		$	125		$	5
Interest cost		668			12			664			22
Expected return on assets		(517	)		—			(374	)		—
Amortization of net (gain) loss		137			(1	)		191			(2	)
Prior service cost		—			(18	)		—			—

Net periodic benefit cost	$	330		$	(7	)	$	606		$	25

During each of the three and six months ended June 30, 2010 and 2009, the Company made contributions of $337 to its non-contributory defined benefit plan (its “Pension Plan”) and expects to make total contributions to its Pension Plan in 2010 of $1,078. During each of the three and six months ended June 30, 2010 and 2009, the Company made no contributions to its other post retirement employee benefit plans.

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 June 30, 2010 and December 31, 2009 were as follows:


	Quoted Prices in
	Active Markets for
	Identical Assets
	(Level 1)
	June 30,		December 31,
	2010		2009
	Pension		Pension
	Benefits		Benefits
Cash	$	355	$	326
Equity		8,687		8,326
Foreign equities		1,571		2,736
Fixed income		2,450		2,342

	$	13,063	$	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 Annual Report for the year ended December 31, 2009 except that the Company evaluates segment performance based on operating income (loss). 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 June 30, 2010	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	329,423	$	185,229	$	514,652	$	—		$	514,652
Intersegment sales		188,654		16,427		205,081		(205,081	)		—

Total sales	$	518,077	$	201,656	$	719,733	$	(205,081	)	$	514,652

Depreciation and amortization		18,017		—		18,017		—			18,017
Operating income		19,472		292		19,764		—			19,764
Reconciling items to net income:
Interest expense											(7,277	)
Loss on derivative instruments											(13,305	)
Other											9
Income tax expense											(98	)

Net loss										$	(907	)

Capital expenditures	$	11,348	$	—	$	11,348	$	—		$	11,348


	Specialty			Fuel			Combined						Consolidated
Three Months Ended June 30, 2009	Products			Products			Segments			Eliminations			Total
Sales:
External customers	$	222,284		$	221,755		$	444,039		$	—		$	444,039
Intersegment sales		175,852			4,140			179,992			(179,992	)		—

Total sales	$	398,136		$	225,895		$	624,031		$	(179,992	)	$	444,039

Depreciation and amortization		18,084			—			18,084			—			18,084
Operating loss		(796	)		(5,005	)		(5,801	)		—			(5,801	)
Reconciling items to net loss:
Interest expense														(8,447	)
Loss on derivative instruments														(9,945	)
Other														(1,727	)
Income tax expense														(67	)

Net loss														(25,987	)

Capital expenditures	$	8,400		$	—		$	8,400		$	—		$	8,400


	Specialty		Fuel		Combined					Consolidated
Six Months Ended June 30, 2010	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	634,899	$	364,370	$	999,269	$	—		$	999,269
Intersegment sales		363,261		27,217		390,478		(390,478	)		—

Total sales	$	998,160	$	391,587	$	1,389,747	$	(390,478	)	$	999,269

Depreciation and amortization		35,508		—		35,508		—			35,508
Operating income		16,835		5,836		22,671		—			22,671
Reconciling items to net loss:
Interest expense											(14,711	)
Loss on derivative instruments											(21,624	)
Other											(50	)
Income tax expense											(260	)

Net loss										$	(13,974	)

Capital expenditures	$	17,017	$	—	$	17,017	$	—		$	17,017


	Specialty		Fuel		Combined					Consolidated
Six Months Ended June 30, 2009	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	439,255	$	419,048	$	858,303	$			$	858,303
Intersegment sales		295,517		8,413		303,930		(303,930	)		—

Total sales	$	734,772	$	427,461	$	1,162,233	$	(303,930	)	$	858,303

Depreciation and amortization		35,816		—		35,816		—			35,816
Operating income		36,338		10,812		47,150		—			47,150
Reconciling items to net income:
Interest expense											(17,090	)
Gain on derivative instruments											21,325
Other											(1,585	)
Income tax expense											(149	)

Net income											49,651

Capital expenditures	$	13,345	$	—	$	13,345	$	—		$	13,345


	June 30, 2010			December 31, 2009
Segment assets:
Specialty products	$	2,976,387		$	3,072,815
Fuel products		2,243,659			2,371,750

Combined segments		5,220,046			5,444,565
Eliminations		(4,189,959	)		(4,412,709	)

Total assets	$	1,030,087		$	1,031,856

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three and six months ended June 30, 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 June 30,
	2010		2009
Specialty products:
Lubricating oils	$	176,354	$	110,728
Solvents		95,777		61,140
Waxes		28,362		21,787
Fuels		2,232		2,245
Asphalt and other by-products		26,698		26,384

Total	$	329,423	$	222,284

Fuel products:
Gasoline		76,287		75,350
Diesel		77,396		102,010
Jet fuel		27,816		42,151
By-products		3,730		2,244

Total	$	185,229	$	221,755

Consolidated sales	$	514,652	$	444,039


	Six Months Ended June 30,
	2010		2009
Specialty products:
Lubricating oils	$	340,402	$	229,044
Solvents		183,631		115,627
Waxes		54,608		44,196
Fuels		3,971		4,904
Asphalt and other by-products		52,287		45,484

Total	$	634,899	$	439,255

Fuel products:
Gasoline		152,170		150,206
Diesel		141,626		183,667
Jet fuel		65,380		81,365
By-products		5,194		3,810

Total	$	364,370	$	419,048

Consolidated sales	$	999,269	$	858,303

d. Major Customers

During the three and six months ended June 30, 2010 and 2009, the Company had no customer that represented 10% or greater of consolidated sales.

14. Subsequent Events

On July 9, 2010, the Company declared a quarterly cash distribution of $0.455 per unit on all outstanding units, or $16,391, for the quarter ended June 30, 2010. The distribution will be paid on August 13, 2010 to unitholders of record as of the close of business on August 3, 2010. This quarterly distribution of $0.455 per unit equates to $1.82 per unit, or $65,564 on an annualized basis.

As of the date of this filing, the net fair value of the Company’s derivatives have increased by approximately $13,000 subsequent to June 30, 2010.


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

The historical consolidated financial statements included in this Quarterly Report reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet,” the “Company,” “we,” “our,” “us”). The following discussion analyzes the financial condition and results of operations of Calumet for the three and six months ended June 30, 2010 and 2009. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Calumet 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.

Second Quarter 2010 Update

For the three months ended June 30, 2010 and 2009, approximately 51.8% and 44.3%, respectively, of our sales volume and 93.5% and 112.9%, respectively, of our gross profit was generated from our specialty products segment while approximately 48.2% and 55.7%, respectively, of our sales volume and approximately 6.5% and (12.9)%, respectively, of our gross profit was generated from our fuel products segment. Despite continued economic challenges in the overall refining industry, we noted improvements in the specialty petroleum products markets during the second quarter of 2010. The trend of increased demand for our specialty products continued during the second quarter of 2010, with specialty products segment sales volume increasing 4.7% in the three months ended June 30, 2010 from the same period in 2009. In addition, our average crude oil costs were reasonably stable during the second quarter of 2010, as crude oil monthly average prices ranged between $74.12 and $84.51 per barrel, which helped allow our specialty products segment to generate a gross profit margin of 14.1% in the three months ended June 30, 2010 under these improved product demand conditions, as compared to gross profit margins of 9.3% in the same period in 2009 and 7.7% in the three months ended March 31, 2010.

Our production levels for the second quarter of 2010 were significantly lower than our production levels during the same period in 2009 due to an extended turnaround at our Shreveport refinery during the entire month of April 2010. These lower production levels did have an adverse impact on our financial results for the quarter; however, they were partially offset by the addition of volumes under the LyondellBasell Agreements. Upon the completion of the turnaround, we increased the Shreveport refinery’s throughput rates in order to meet increasing specialty products demand and historically higher demand for fuel products during the second quarter. We expect to operate at these increased rates during the third quarter of 2010 due to current market demand for our products.

Despite reduced refinery throughput rates during the first half of 2010 as a result of the decision to reduce crude oil run rates in the first quarter based on the poor economics of running additional barrels and the completion of an extended turnaround at our Shreveport refinery during the second quarter, we generated $42.6 million in net cash flow from operations and paid quarterly distributions of $32.8 million in aggregate to our unitholders in the six months ended June 30, 2010. In addition to paying our quarterly distributions, we expect cash flow from operations will be used to (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 and our sales by $45.1 million and $65.2 million for the three and six months ended June 30, 2010, respectively.

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 June 30, 2010, we have hedged approximately 13.1 million barrels of fuel products through December 2012 at an average refining margin of $12.02 per barrel. As of June 30, 2010, we have approximately 0.4 million barrels of crude oil swaps and options through August 2010 to hedge our purchases of crude oil for specialty products production. The strike prices 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 and Six Months Ended June 30, 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 June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(In bpd)				(In bpd)
Total sales volume (1)		52,626		58,802		52,166		56,624
Total feedstock runs (2)		57,169		60,076		52,774		61,639
Facility production: (3)
Specialty products:
Lubricating oils		13,783		9,659		12,538		10,649
Solvents		8,904		7,417		8,490		7,840
Waxes		1,152		870		1,081		985
Fuels		978		821		1,063		744
Asphalt and other by-products		6,075		7,680		5,921		7,708

Total		30,892		26,447		29,093		27,926

Fuel products:
Gasoline		8,710		9,322		8,743		10,195
Diesel		10,875		13,164		9,936		12,958
Jet fuel		5,326		6,878		5,290		7,111
By-products		722		748		511		512

Total		25,633		30,112		24,480		30,776

Total facility production		56,525		56,559		53,573		58,702


(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 June 30, 2010 compared to the same period in 2009 is due primarily to the extended turnaround at the Shreveport refinery during April 2010, partially offset by the addition of volumes under the LyondellBasell Agreements during the same period. Additionally, the decrease in feedstock runs for the six months ended June 30, 2010 compared to the same period in 2009 is also due to the Company’s 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. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of finished products and volume loss. The decrease in facility production for the six months ended June 30, 2010 compared to the same period in 2009 is a result of reduced feedstock runs during that period, as discussed in footnote 2 of this table. The increase in the production of specialty products for the three and six months ended June 30, 2010 compared to the same periods in 2009 is primarily the result of the addition of volumes under the LyondellBasell Agreements and was partially offset by reduced facility production levels as a result of reduced feedstock runs during those periods, as discussed above in footnote 2 of this table. The reduction in production of fuel products for the three and six months ended June 30, 2010 as compared to the same periods in 2009 is due to reduced feedstock runs at our Shreveport refinery during those periods, as discussed in footnote 2 of this table.

The following table reflects our consolidated results of operations and includes the non-GAAP financial measures EBITDA and Adjusted EBITDA. For a reconciliation 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 in accordance with GAAP, please read “—Non-GAAP Financial Measures.”


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)						(In thousands)
Sales	$	514,652		$	444,039		$	999,269		$	858,303
Cost of sales		465,033			425,671			917,974			760,964

Gross profit		49,619			18,368			81,295			97,339

Operating costs and expenses:
Selling, general and administrative		8,321			6,939			15,491			16,261
Transportation		19,956			16,087			40,202			31,242
Taxes other than income taxes		1,098			865			2,123			1,989
Other		480			278			808			697

Operating income (loss)		19,764			(5,801	)		22,671			47,150

Other income (expense):
Interest expense		(7,277	)		(8,447	)		(14,711	)		(17,090	)
Realized gain (loss) on derivative instruments		(5,297	)		7,637			(5,858	)		(833	)
Unrealized gain (loss) on derivative instruments		(8,008	)		(17,582	)		(15,766	)		22,158
Other		9			(1,727	)		(50	)		(1,585	)

Total other income (expense)		(20,573	)		(20,119	)		(36,685	)		2,650

Net income (loss) before income taxes		(809	)		(25,920	)		(13,714	)		49,800
Income tax expense		98			67			260			149

Net income (loss)	$	(907	)	$	(25,987	)	$	(13,974	)	$	49,651

EBITDA	$	21,710		$	(1,944	)	$	30,790		$	97,708

Adjusted EBITDA	$	27,829		$	26,632		$	48,620		$	76,733

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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)						(In thousands)
Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA:
Net income (loss)	$	(907	)	$	(25,987	)	$	(13,974	)	$	49,651
Add:
Interest expense		7,277			8,447			14,711			17,090
Depreciation and amortization		15,242			15,529			29,793			30,818
Income tax expense		98			67			260			149

EBITDA	$	21,710		$	(1,944	)	$	30,790		$	97,708

Add:
Unrealized (gain) loss from mark to market accounting for hedging activities	$	8,380		$	24,608		$	17,208		$	(21,797	)
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		(2,261	)		3,968			622			822

Adjusted EBITDA	$	27,829		$	26,632		$	48,620		$	76,733


	Six Months Ended
	June 30,
	2010			2009
	(In thousands)
Reconciliation of Adjusted EBITDA and EBITDA to net cash provided by operating activities:
Adjusted EBITDA	$	48,620		$	76,733
Add:
Unrealized gain (loss) from mark to market accounting for hedging activities		(17,208	)		21,797
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		(622	)		(822	)

EBITDA	$	30,790		$	97,708

Add:
Cash interest expense		(12,805	)		(15,277	)
Unrealized (gain) loss on derivative instruments		15,766			(22,158	)
Income taxes		(260	)		(149	)
Provision for doubtful accounts		(91	)		(724	)
Changes in assets and liabilities:
Accounts receivable		(27,323	)		(3,445	)
Inventory		(9,583	)		(27,590	)
Other current assets		2,265			2,520
Derivative activity		1,443			(201	)
Accounts payable		48,584			23,346
Other liabilities		(2,580	)		1,780
Other, including changes in noncurrent assets and liabilities		(3,639	)		1,628

Net cash provided by operating activities	$	42,567		$	57,438

Changes in Results of Operations for the Three Months Ended June 30, 2010 and 2009

Sales. Sales increased $70.6 million, or 15.9%, to $514.7 million in the three months ended June 30, 2010 from $444.0 million in the same period in 2009. Sales for each of our principal product categories in these periods were as follows:


	Three Months Ended June 30,
	2010		2009		% Change
	(Dollars in thousands)
Sales by segment:
Specialty products:
Lubricating oils	$	176,354	$	110,728		59.3	%
Solvents		95,777		61,140		56.7	%
Waxes		28,362		21,787		30.2	%
Fuels (1)		2,232		2,245		(0.6	)%
Asphalt and by-products (2)		26,698		26,384		1.2	%

Total specialty products	$	329,423	$	222,284		48.2	%

Total specialty products sales volume (in barrels)		2,481,000		2,369,000		4.7	%
Fuel products:
Gasoline	$	76,287	$	75,350		1.2	%
Diesel		77,396		102,010		(24.1	)%
Jet fuel		27,816		42,151		(34.0	)%
By-products (3)		3,730		2,244		66.2	%

Total fuel products	$	185,229	$	221,755		(16.5	)%

Total fuel products sales volume (in barrels)		2,308,000		2,982,000		(22.6	)%
Total sales	$	514,652	$	444,039		15.9	%

Total sales volume (in barrels)		4,789,000		5,351,000		(10.5	)%


(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 June 30, 2010 increased $107.1 million, or 48.2%, as a result of an increase in the average selling price per barrel, increasing our sales by 43.5%, and a 4.7% increase in sales volume as compared to the same period in 2009. Specialty products average selling prices per barrel increased in all product categories compared to a 32.3% increase in the average cost of crude oil per barrel from the three months ended June 30, 2010 as compared to the same period in 2009. The increased volume and selling prices are due to improving overall specialty products demand and the addition of the LyondellBasell Agreements in 2010.

Fuel products segment sales for the three months ended June 30, 2010 decreased $36.5 million, or 16.5%, due to a 22.6% decrease in sales volume as compared to the second quarter of 2009 as a result of the extended turnaround at the Shreveport refinery during the entire month of April 2010. This decrease was partially offset by an increase in the average selling price per barrel at a rate comparable to the 31.7% increase in the average cost of crude oil per barrel for the same period. The average selling price per barrel increased for all fuel products, with diesel and jet fuel selling prices experiencing the most significant increases driven by improved market pricing. In addition, there was a $39.1 million increase in derivative loss on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for discussion of the net impact of our crude oil and fuel products derivative instruments designated as hedges.

Gross Profit. Gross profit increased $31.3 million, or 170.1%, to $49.6 million in the three months ended June 30, 2010 from $18.4 million in the same period in 2009. Gross profit (loss) for our specialty products and fuel products segments was as follows:


	Three Months Ended June 30,
	2010			2009			% Change
	(Dollars in thousands)
Gross profit (loss) by segment:
Specialty products	$	46,400		$	20,735			123.8	%
Percentage of sales		14.1	%		9.3	%
Fuel products	$	3,219		$	(2,367	)		236.0	%
Percentage of sales		1.7	%		(1.1	)%
Total gross profit	$	49,619		$	18,368			170.1	%
Percentage of sales		9.6	%		4.1	%

The increase of $25.7 million in specialty products segment gross profit was primarily due to an increase in the average selling price per barrel, increasing our sales by 43.5%, while the average cost of crude oil per barrel increased by only 32.3%. Also, specialty products sales volumes increased 4.7%, due primarily to improvements to overall specialty products demand and the addition of the LyondellBasell Agreements in 2010.

Fuel products segment gross profit was positively impacted by improving crack spreads as the average selling price per barrel of our fuel products increased at a rate comparable to the average cost of crude oil per barrel, which increased by 31.7%, combined with a net $2.0 million increase in derivative gains on our fuel products crack spread cash flow hedges. Partially offsetting this increase in gross profit per barrel was a 22.6% decrease in fuel products sales volume, as discussed above.

Selling, general and administrative. Selling, general and administrative expenses increased $1.4 million, or 19.9%, to $8.3 million in the three months ended June 30, 2010 from $6.9 million in the same period in 2009. This increase is primarily due to lower bad debt expense in the second quarter of 2009 resulting from the recovery of $0.9 million from a fully reserved account receivable of that period and increased incentive compensation costs of $0.4 million in the second quarter of 2010 as compared to the same period in 2009.

Transportation. Transportation expenses increased $3.9 million, or 24.1%, to $20.0 million in the three months ended June 30, 2010 from $16.1 million in the same period in 2009. This increase is primarily due to increased lubricating oils, solvents and waxes sales volumes.

Interest expense. Interest expense decreased $1.2 million, or 13.9%, to $7.3 million in the three months ended June 30, 2010 from $8.5 million in the three months ended June 30, 2009 primarily due to lower interest rates and lower balances being carried on the revolver and term loan during the three months ended June 30, 2010 as compared to the same period in 2009.

Realized gain (loss) on derivative instruments. Realized gain (loss) on derivative instruments decreased $12.9 million to a loss of $5.3 million in the three months ended June 30, 2010 from a gain of $7.6 million for the three months ended June 30, 2009. This decrease was primarily due to increased losses of $5.5 million on derivatives used to economically hedge our specialty products segment crude oil purchases and decreased realized gains of $4.5 million in 2010 on our crack spread derivatives that were executed to economically lock in gains on a portion of our fuel products segment derivative hedging activity.

Unrealized loss on derivative instruments. Unrealized loss on derivative instruments decreased $9.6 million, to $8.0 million in the three months ended June 30, 2010 from a loss of $17.6 million in the three months ended June 30, 2009. This decreased loss is primarily due to decreased loss ineffectiveness during the quarter ended June 30, 2010 as compared to the same period in 2009. Partially offsetting this decrease were decreases in unrealized gains on derivatives used to economically hedge our specialty products segment crude oil purchases and decreases in unrealized gains on crack spread derivatives that were executed to economically lock in gains on a portion of our fuel products segment derivative hedging activity.

Changes in Results of Operations for the Six Months Ended June 30, 2010 and 2009

Sales. Sales increased $141.0 million, or 16.4%, to $998.3 million in the six months ended June 30, 2010 from $858.3 million in the six months ended June 30, 2009. Sales for each of our principal product categories in these periods were as follows:


	Six Months Ended June 30,
	2010		2009		% Change
	(Dollars in thousands)
Sales by segment:
Specialty products:
Lubricating oils	$	340,402	$	229,044		48.6	%
Solvents		183,631		115,627		58.8	%
Waxes		54,608		44,196		23.6	%
Fuels (1)		3,971		4,904		(19.0	)%
Asphalt and by-products (2)		52,287		45,484		15.0	%

Total specialty products	$	634,899	$	439,255		44.5	%

Total specialty products volume (in barrels)		4,936,000		4,582,000		7.7	%
Fuel products:
Gasoline	$	152,170	$	150,206		1.3	%
Diesel		141,626		183,667		(22.9	)%
Jet fuel		65,380		81,365		(19.6	)%
By-products (3)		5,194		3,810		3.6	%

Total fuel products	$	364,370	$	419,048		(13.0	)%

Total fuel products sales volumes (in barrels)		4,506,000		5,667,000		(20.5	)%
Total sales	$	999,269	$	858,303		16.4	%

Total sales volumes (in barrels)		9,442,000		10,249,000		(7.9	)%


(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 six months ended June 30, 2010 increased $195.6 million, or 44.5%, primarily due to an increase in the average selling price per barrel, increasing our sales by 36.8%, with average selling prices per barrel increasing across all specialty products categories compared to the 56.5% increase in the average cost of crude oil per barrel for the six months ended June 30, 2010 as compared to the same period in 2009. In addition, specialty products segment volumes sold increased by 7.7%. The increased volume and selling prices are due to improving overall specialty products demand and the addition of the LyondellBasell Agreements in 2010.

Fuel products segment sales for the six months ended June 30, 2010 decreased $54.7 million, or 13.0%, primarily due to a 20.5% decrease in sales volumes, from approximately 5.7 million barrels in the six months ended June 30, 2009 to 4.5 million barrels in the six months ended June 30, 2010, due to the extended turnaround at the Shreveport refinery during the entire month of April 2010. Partially offsetting this decrease in sales volumes was an increase in the average selling price per barrel, increasing our sales by 33.0%, as compared to a 56.2% increase in the average cost of crude oil per barrel. Also contributing to the overall decrease in sales was a $98.2 million decrease in derivative gains on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for the net impact of our crude oil and fuel products derivative instruments designated as hedges.

Gross Profit. Gross profit decreased $16.0 million, or 16.5%, to $81.3 million for the six months ended June 30, 2010 from $97.3 million for the same period in 2009. Gross profit for our specialty and fuel products segments was as follows:


	Six Months Ended June 30,
	2010			2009			% Change
	(Dollars in thousands)
Gross profit by segment:
Specialty products	$	69,826		$	80,558			(13.3	)%
Percentage of sales		11.0	%		18.3	%
Fuel products	$	11,469		$	16,781			(31.7	)%
Percentage of sales		3.1	%		4.0	%
Total gross profit	$	81,295		$	97,339			(16.5	)%
Percentage of sales		8.1	%		11.3	%

The decrease in specialty products segment gross profit was primarily due to the 56.5% increase in the cost of crude oil with an increase in average selling price per barrel increasing our sales by only 36.8%. This decrease is primarily due to the first quarter of 2009 having significantly higher gross profit per barrel than the first quarter of 2010 resulting from crude oil prices declining late in 2008 and remaining relatively stable during the first quarter of 2009 without a significant reduction in the average selling price per barrel. Partially offsetting this reduction in gross profit was a 7.7% increase in specialty products segment sales volumes due to increased demand for these products.

The decrease in fuel products segment gross profit was primarily due to reduced sales volume of 20.5%, as discussed above, as well as a 56.2% increase in the average crude oil cost per barrel while the increase in the average selling price per barrel only increased our sales by 33.0%. Partially offsetting the reduction in gross profit was increased derivative gains of $3.2 million on our fuel products crack spread cash flow hedges.

Transportation. Transportation expenses increased $9.0 million, or 28.7%, to $40.2 million in the six months ended June 30, 2010 from $31.2 million in the same period in 2009. This increase is primarily due to increased lubricating oils, solvents and waxes sales volumes.

Interest expense. Interest expense decreased $2.4 million, or 13.9%, to $14.7 million in the six months ended June 30, 2010 from $17.1 million in the six months ended June 30, 2009. This decrease is primarily due to lower interest rates and lower balances being carried on the Company’s revolver and term loan during the six months ended June 30, 2010, as compared to the same period in 2009.

Realized loss on derivative instruments. Realized loss on derivative instruments increased $5.0 million to a loss of $5.9 million in the six months ended June 30, 2010 from a loss of $0.8 million in the same period in 2009. The increase is primarily due to reduced derivative gains in the six months ended June 30, 2010 as compared to the same period in 2009 on settlements of our crack spread derivatives used to economically lock in gains on a portion of our fuel products segment derivative hedging activity. Offsetting this reduction in derivative gains, were less realized losses in the six months ended June 30, 2010 on crude oil derivatives in our specialty products segment due to the significant decline in crude oil prices late in 2008 whereas crude oil prices were relatively stable in the six months ended June 30, 2010 and significantly less volume of these derivatives in the same period in 2010. Also contributing to this increase in realized loss was increased loss ineffectiveness.

Unrealized gain (loss) on derivative instruments. Unrealized gain on derivative instruments decreased $37.9 million to a loss of $15.8 million in the six months ended June 30, 2010 from a gain of $22.2 million for the same period in 2009. This decreased gain was primarily due to gains in the six months ended June 30, 2009 on the derivatives used to economically hedge our specialty products crude oil purchases and gains in the six months ended June 30, 2009 on our crack spread derivatives used to economically lock in gains on a portion of our fuel products segment derivative hedging activity with minimal related activity in the same period in 2010. This decrease was also due to increased loss ineffectiveness in the six months ended June 30, 2010 as compared to the same period in 2009.

Liquidity and Capital Resources

The following should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” included under 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 distributions to our limited partners and general partner, debt service, replacement and environmental capital expenditures and capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. 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:


	Six Months Ended
	June 30,
	2010			2009
	(In thousands)
Net cash provided by operating activities	$	42,567		$	57,438
Net cash used in investing activities	$	(16,896	)	$	(12,608	)
Net cash used in financing activities	$	(25,653	)	$	(44,814	)

Operating Activities. Operating activities provided $42.6 million in cash during the six months ended June 30, 2010 compared to $57.4 million during the same period in 2009. The decrease in cash provided by operating activities was primarily due to decreased net income and offset by unrealized derivative losses of $15.8 million in the six months ended June 30, 2010 as compared to unrealized gains of $22.2 million during the same period in 2009, as well as an improvement in net working capital, as compared to the same period in 2009.

Investing Activities. Cash used in investing activities increased to $16.9 million during the six months ended June 30, 2010 compared to $12.6 million during the six months ended June 30, 2009. This is due to increased capital expenditures.

Financing Activities. Financing activities used cash of $25.7 million during the six months ended June 30, 2010 as compared to $44.8 million during the six months ended June 30, 2009. The decreased use of cash is primarily due to increased use of net proceeds from revolver borrowings in the six months ended June 30, 2010, as compared to repayments on the revolver in the same period in 2009.

On July 9, 2010, the Company declared a quarterly cash distribution of $0.455 per unit on all outstanding units, or $16.4 million, for the quarter ended June 30, 2010. The distribution will be paid on August 13, 2010 to unitholders of record as of the close of business on August 3, 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.


	Six Months Ended June 30,
	2010		2009
	(In thousands)
Capital improvement expenditures	$	675	$	5,601
Replacement capital expenditures		8,801		6,056
Environmental capital expenditures		7,541		1,688

Total	$	17,017	$	13,345

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 half 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 June 30, 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 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 discounts.

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 fluctuates 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 June 30, 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 June 30, 2010, we had availability under our revolving credit facility of $112.5 million, based on a $228.5 million borrowing base, $66.9 million in outstanding standby letters of credit, and outstanding borrowings of $49.1. The increase in our availability of $5.2 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 unit holders, debt service obligations, contingencies and anticipated capital expenditures.

Contractual Obligations and Commercial Commitments

A summary of our total contractual cash obligations as of June 30, 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	$	418,450	$	3,850	$	56,840	$	7,700	$	350,060
Interest on long-term debt at contractual rates		85,816		21,744		39,903		24,169		—
Capital lease obligations		2,278		986		1,173		119		—
Operating lease obligations (1)		34,359		11,590		15,249		6,527		993
Letters of credit (2)		116,875		66,875		—		50,000		—
Purchase commitments (3)		753,841		312,268		265,209		176,364		—

Total obligations	$	1,411,619	$	417,313	$	378,374	$	264,879	$	351,053


(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 and other feedstocks and finished products for resale from various suppliers based on current market prices at the time of delivery.

In connection with the closing of the 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 $50.4 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of June 30, 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 and Item 3 of our 2010 First Quarterly 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 June 30, 2010, we estimate we have executed derivative instruments to economically hedge approximately 15% to 20% of forecasted specialty products segment crude oil purchases through August 31, 2010. Also, as of June 30, 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	$	(5.5	)
Jet fuel swaps	$	(5.4	)
Gasoline swaps	$	(2.2	)
Crude oil collars	$	0.2
Jet fuel collars	$	0.8
Natural gas swaps	$	0.2

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 June 30, 2010, we had approximately $418.5 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 June 30, 2010 would be expected to have an impact on net income and cash flows of approximately $4.2 million.

We have a $375.0 million revolving credit facility as of June 30, 2010, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had borrowings of $49.1 million outstanding under this facility as of June 30, 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 June 30, 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)
Third Quarter 2010		1,871,000		20,337	$	11.26
Fourth Quarter 2010		1,840,000		20,000		11.32
Calendar Year 2011		5,796,000		15,879		12.14
Calendar Year 2012		3,557,000		9,719		12.60

Totals		13,064,000
Average price					$	12.02

The following table provides a summary of our derivative instruments and implied crack spreads for the crude oil and gasoline swaps as of June 30, 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)
Third Quarter 2010		138,000		1,500	$	0.17
Fourth Quarter 2010		138,000		1,500		0.17

Totals		276,000
Average price					$	0.17

At June 30, 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 June 30, 2010, the Company had 403,000 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 June 30, 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 June 30, 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 second 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, our 2010 First 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*

None.


Item 3.		*Defaults Upon Senior Securities*

None.


Item 4.		*Reserved*

None.


Item 5.		*Other Information*

None.


Item 6.		*Exhibits*

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


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

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

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


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

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

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

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

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

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


*		Filed herewith.

SIGNATURES

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


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



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

Date: August 5, 2010

Index to Exhibits


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

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

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

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

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

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

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

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

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


*		Filed herewith.

TABLE OF CONTENTS

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

Exhibits

EX-31.1 EX-31.2 EX-32.1

CLMT 10-Q Quarter ended June 30, 2010

Exhibits