CLMT 10-Q Quarterly Report Sept. 30, 2010

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

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10-Q 1 h77340e10vq.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 September 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 (State or Other Jurisdiction of Incorporation or Organization)		37-1516132 (I.R.S. Employer Identification Number)

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

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

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

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

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

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

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 November 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 Nine Months Ended September 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		28
Item 3. Quantitative and Qualitative Disclosures About Market Risk		43
Item 4. Controls and Procedures		44
Part II
Item 1. Legal Proceedings		45
Item 1A. Risk Factors		45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		47
Item 3. Defaults Upon Senior Securities		47
Item 4. Reserved		47
Item 5. Other Information		47
Item 6. Exhibits		48
EX-3.7
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 crude oil throughput 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 Reports filed with the Securities and Exchange Commission (the “SEC”) on August 5, 2010 (our “2010 Second Quarterly Report”) and 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


	September 30, 2010			December 31, 2009
	(Unaudited)
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	88		$	49
Accounts receivable:
Trade		163,651			116,914
Other		1,047			5,854

		164,698			122,768
Inventories		150,214			137,250
Derivative assets		—			30,904
Prepaid expenses and other current assets		2,914			1,811
Deposits		2,094			6,861

Total current assets		320,008			299,643
Property, plant and equipment, net		618,408			629,275
Goodwill		48,335			48,335
Other intangible assets, net		31,487			38,093
Other noncurrent assets, net		20,381			16,510

Total assets	$	1,038,619		$	1,031,856

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	147,855		$	92,110
Accounts payable — related party		33,786			17,866
Accrued salaries, wages and benefits		6,081			6,500
Taxes payable		8,320			7,551
Other current liabilities		7,627			6,114
Current portion of long-term debt		4,840			5,009
Derivative liabilities		20,099			4,766

Total current liabilities		228,608			139,916
Pension and postretirement benefit obligations		8,720			9,433
Other long-term liabilities		1,090			1,111
Long-term debt, less current portion		386,103			396,049

Total liabilities		624,521			546,509
Commitments and contingencies
Partners’ capital:
Common unitholders (22,213,778 units and 22,166,000 units issued and outstanding at September 30, 2010 and December 31, 2009, respectively)		394,708			418,902
Subordinated unitholders (13,066,000 units issued and outstanding at September 30, 2010 and December 31, 2009)		19,509			34,714
General partner’s interest (719,995 units and 719,020 units issued and outstanding at September 30, 2010 and December 31, 2009, respectively)		18,267			19,087
Accumulated other comprehensive income (loss)		(18,386	)		12,644

Total partners’ capital		414,098			485,347

Total liabilities and partners’ capital	$	1,038,619		$	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 Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands, except per unit data)
Sales	$	595,273		$	492,431		$	1,594,542		$	1,350,735
Cost of sales		533,167			451,275			1,451,141			1,212,241

Gross profit		62,106			41,156			143,401			138,494

Operating costs and expenses:
Selling, general and administrative		7,403			7,437			22,894			23,697
Transportation		23,258			18,519			63,460			49,761
Taxes other than income taxes		1,308			1,167			3,431			3,156
Other		565			191			1,373			888

Operating income		29,572			13,842			52,243			60,992

Other income (expense):
Interest expense		(7,794	)		(8,243	)		(22,505	)		(25,333	)
Realized gain (loss) on derivative instruments		(2,288	)		4,045			(8,147	)		3,213
Unrealized gain (loss) on derivative instruments		1,931			(4,485	)		(13,835	)		17,672
Other		(121	)		(1,271	)		(170	)		(2,856	)

Total other expense		(8,272	)		(9,954	)		(44,657	)		(7,304	)

Net income before income taxes		21,300			3,888			7,586			53,688
Income tax expense (benefit)		79			(79	)		339			70

Net income	$	21,221		$	3,967		$	7,247		$	53,618

Allocation of net income:
Net income	$	21,221		$	3,967		$	7,247		$	53,618
Less:
General partner’s interest in net income		424			79			145			1,070
Holders of incentive distribution rights		—			—			—			—

Net income available to limited partners	$	20,797		$	3,888		$	7,102		$	52,548

Weighted average limited partner units outstanding — basic		35,337			32,232			35,332			32,232

Weighted average limited partner units outstanding — diluted		35,352			32,232			35,351			32,232

Common and subordinated unitholders’ basic and diluted net income per unit	$	0.59		$	0.12		$	0.20		$	1.63

Cash distributions declared per common and subordinated unit	$	0.46		$	0.45		$	1.37		$	1.35

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 income					145			4,472			2,630			7,247
Cash flow hedge gain reclassified to net income		(11,473	)											(11,473	)
Change in fair value of cash flow hedges		(20,080	)											(20,080	)
Defined benefit pension and retiree health benefit plans		523												523

Comprehensive loss														(23,783	)
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								1,150						1,150
Distributions to partners					(983	)		(30,361	)		(17,835	)		(49,179	)

Balance at September 30, 2010	$	(18,386	)	$	18,267		$	394,708		$	19,509		$	414,098

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Nine Months Ended
	September 30,
	2010			2009
	(In thousands)
Operating activities
Net income	$	7,247		$	53,618
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		47,289			48,890
Amortization of turnaround costs		6,639			5,692
Provision for doubtful accounts		74			(766	)
Unrealized (gain) loss on derivative instruments		13,835			(17,672	)
Other non-cash activity		1,467			3,561
Changes in assets and liabilities:
Accounts receivable		(42,004	)		(17,937	)
Inventories		(12,964	)		(13,184	)
Prepaid expenses and other current assets		(1,103	)		(953	)
Derivative activity		849			6,680
Deposits		4,767			4,000
Other assets		(10,311	)		(4,539	)
Accounts payable		70,265			38,298
Accrued salaries, wages and benefits		(419	)		1,002
Taxes payable		769			741
Other liabilities		1,492			2,202
Pension and postretirement benefit obligations		(190	)		945

Net cash provided by operating activities		87,702			110,578
Investing activities
Additions to property, plant and equipment		(27,310	)		(20,718	)
Proceeds from disposal of property and equipment		201			793

Net cash used in investing activities		(27,109	)		(19,925	)
Financing activities
Repayments of borrowings — revolving credit facility		(8,027	)		(33,435	)
Repayments of borrowings — term loan credit facility		(2,888	)		(2,888	)
Payments on capital lease obligations		(1,023	)		(875	)
Proceeds from public equity offering, net		793			—
Contribution from Calumet GP, LLC		18			—
Change in bank overdraft		—			(6,325	)
Common units repurchased for vested phantom unit grants		(248	)		(164	)
Distributions to partners		(49,179	)		(44,447	)

Net cash used in financing activities		(60,554	)		(88,134	)

Net increase in cash and cash equivalents		39			2,519
Cash and cash equivalents at beginning of period		49			48

Cash and cash equivalents at end of period	$	88		$	2,567

Supplemental disclosure of cash flow information
Interest paid	$	19,635		$	23,124
Income taxes paid	$	138		$	91

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 September 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 September 30, 2010 and for the three and nine months ended September 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 nine months ended September 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:


	September 30,		December 31,
	2010		2009
Raw materials	$	8,165	$	1,323
Work in process		62,192		51,304
Finished goods		79,857		84,623

	$	150,214	$	137,250

The replacement cost of these inventories, based on current market values, would have been $45,125 and $30,420 higher as of September 30, 2010 and December 31, 2009, respectively. During the three months ended September 30, 2010 and 2009, the Company recorded $3,488 and $9,475, respectively, of gains in cost of sales in the unaudited condensed consolidated statements of operations due to the liquidation of lower cost inventory layers. During the nine months ended September 30, 2010 and 2009, the Company recorded $4,371 and $9,475, 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 $145,000. 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.

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 proposed penalties in prior years 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.

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 has proposed to pay penalties totaling $400 and to make emissions reductions requiring capital investments between approximately $1,000 and $3,000 above the Company’s planned levels between 2011 and 2015 at its three Louisiana refineries.

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 and 2011 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 during 2011, 2012 and 2013 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.

Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program which is targeting all U.S. refineries for review. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the “Citation”) to the Company as a result of this inspection which included a proposed civil penalty amount of $173. The Company has contested the Citation and penalty amount in a timely manner in an attempt to receive both a reduction in the amount of the civil penalty and an extension of time to complete ongoing capital expenditures designed to strengthen or relocate an existing control room at the Shreveport refinery. With the exception of the foregoing matter which we are contesting, 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 September 30, 2010 and December 31, 2009, the Company had outstanding standby letters of credit of $75,375 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 September 30, 2010 and December 31, 2009, the Company had availability to issue letters of credit of $143,812 and $107,285, respectively, under its revolving credit facility. As discussed in Note 6, as of September 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 its crack spread hedging activities, which bears interest at 4.0%.

6. Long-Term Debt

Long-term debt consisted of the following:


	September 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% (4.38% and 4.27% at September 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 5.44% and 6.00% for the periods ended September 30, 2010 and December 31, 2009, respectively	$	368,348		$	371,235
Borrowings under senior secured revolving credit agreement with third-party lenders, interest at prime plus 0.50% (3.75% at September 30, 2010 and December 31, 2009), interest payments monthly, borrowings due January 2013		31,873			39,900
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly through January 2012		2,031			2,938
Less unamortized discount on senior secured first lien term loan with third-party lenders		(11,309	)		(13,015	)

Total long-term debt		390,943			401,058
Less current portion of long-term debt		4,840			5,009

	$	386,103		$	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 September 30, 2010, the margin is 50 basis points for prime and 200 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 September 30, 2010 under the revolving credit facility was $251,060 with $143,812 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 September 30, 2010, the Company was in compliance with all financial covenants under its credit agreements.

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


Year	Maturity
2010	$	1,213
2011		4,844
2012		4,401
2013		35,959
2014		3,850
Thereafter		351,985

Total	$	402,252

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 September 30, 2010 and December 31, 2009:


	Derivative Assets					Derivative Liabilities
	September 30, 2010		December 31, 2009			September 30, 2010			December 31, 2009
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	—	$	134,587		$	74,454		$	—
Gasoline swaps		—		(6,147	)		(11,105	)		—
Diesel swaps		—		(67,731	)		(38,724	)		—
Jet fuel swaps		—		(26,926	)		(40,632	)		—
Specialty products segment:
Crude oil collars		—		—			—			—
Crude oil swaps		—		—			—			—
Natural gas swaps		—		—			—			—
Interest rate swaps:		—		—			(3,339	)		(2,752	)

Total derivative instruments designated as hedges		—		33,783			(19,346	)		(2,752	)

Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps (1)		—		13,062			(3,151	)		—
Gasoline swaps (1)		—		(16,165	)		3,702			—
Diesel swaps		—		—			—			—
Jet fuel crack spread collars (2)		—		375			54			—
Specialty products segment:
Crude oil collars (3)		—		(151	)		339			—
Crude oil swaps (3)		—		—			29			—
Natural gas swaps (3)		—		—			(263	)		—
Interest rate swaps: (4)		—		—			(1,463	)		(2,014	)

Total derivative instruments not designated as hedges		—		(2,879	)		(753	)		(2,014	)

Total derivative instruments	$	—	$	30,904		$	(20,099	)	$	(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, September 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
	September 30,						Location of (Gain)	September 30,						Location of Gain	September 30,
Type of Derivative	2010			2009			Loss	2010			2009			(Loss)	2010			2009
Fuel products segment:
Crude oil swaps	$	59,678		$	(19,056	)	Cost of sales	$	(16,163	)	$	5,120		Unrealized/ Realized	$	(221	)	$	(9	)
Gasoline swaps		(7,342	)		5,697		Sales		3,836			242		Unrealized/ Realized		(9	)		556
Diesel swaps		(28,924	)		22,660		Sales		7,736			(7,447	)	Unrealized/ Realized		(404	)		(1,682	)
Jet fuel swaps		(31,444	)		3,274		Sales		—			—		Unrealized/ Realized		(50	)		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:		(1,124	)		(673	)	Interest expense		639			928		Unrealized/ Realized		—			—

Total	$	(9,156	)	$	11,902			$	(3,952	)	$	(1,157	)		$	(684	)	$	(689	)

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended September 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
	September 30,						September 30,
Type of Derivative	2010			2009			2010			2009
Fuel products segment:
Crude oil swaps	$	(1,939	)	$	169		$	1,357		$	2,129
Gasoline swaps		3,071			5,598			(2,284	)		(7,384	)
Diesel swaps		(326	)		(1,664	)		326			1,664
Jet fuel swaps		—			—			—			—
Jet fuel collars		—			—			(33	)		(85	)
Specialty products segment:
Crude oil collars		(1,396	)		176			1,759			(159	)
Crude oil swaps		(56	)		—			275			—
Natural gas swaps		(136	)		(56	)		(187	)		(48	)
Interest rate swaps:		(205	)		(207	)		101			116

Total	$	(987	)	$	4,016		$	1,314		$	(3,767	)

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 nine months ended, September 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)
								Nine Months Ended							Nine Months Ended
	September 30,						Location of (Gain)	September 30,						Location of Gain	September 30,
Type of Derivative	2010			2009			Loss	2010			2009			(Loss)	2010			2009
Fuel products segment:
Crude oil swaps	$	(19,677	)	$	128,556		Cost of sales	$	(51,849	)	$	70,799		Unrealized/ Realized	$	(10,194	)	$	14,142
Gasoline swaps		12,307			(105,715	)	Sales		14,894			(23,586	)	Unrealized/ Realized		(4,560	)		2,582
Diesel swaps		3,633			(40,227	)	Sales		23,546			(54,954	)	Unrealized/ Realized		(1,628	)		(14,397	)
Jet fuel swaps		(13,821	)		(8,562	)	Sales		—			—		Unrealized/ Realized		116			—
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:		(2,522	)		(1,836	)	Interest expense		1,936			2,191		Unrealized/ Realized		—			—

Total	$	(20,080	)	$	(27,885	)		$	(11,473	)	$	(5,243	)		$	(16,266	)	$	2,327

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the nine months ended September 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
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
Type of Derivative	2010			2009			2010			2009
Fuel products segment:
Crude oil swaps	$	(6,329	)	$	15,821		$	8,295		$	(35,084	)
Gasoline swaps		10,174			2,733			(11,487	)		35,546
Diesel swaps		(976	)		(4,991	)		976			4,991
Jet fuel swaps		—			—			—			—
Jet fuel collars		—			—			(321	)		(262	)
Specialty products segment:
Crude oil collars		(4,355	)		(11,739	)		491			12,372
Crude oil swaps		(1,718	)		—			28			—
Natural gas swaps		(171	)		(1,563	)		(263	)		1,207
Interest rate swaps		(611	)		(617	)		551			144

Total	$	(3,986	)	$	(356	)	$	(1,730	)	$	18,914

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 September 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 September 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 $14,201 as of September 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	$	4,732
2011		(7,411	)
2012		(11,522	)

Total	$	(14,201	)

Based on fair values as of September 30, 2010, the Company expects to reclassify $3,546 of net losses on derivative instruments from accumulated other comprehensive income (loss) to earnings during the next twelve months due to actual crude oil purchases, gasoline, diesel and jet fuel sales, and the payment of variable interest associated with floating rate debt. However, the amounts actually realized will be dependent on the fair values as of the date of settlements.

Crude Oil Swap and Collar Contracts — Specialty Products Segment

The Company is exposed to fluctuations in the price of crude oil, its principal raw material. The Company utilizes combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty products segment. These derivatives may be designated as cash flow hedges of the future purchase of crude oil if they meet the hedge criteria. The Company’s general policy is to enter into crude oil derivative contracts that mitigate the Company’s exposure to price risk associated with crude oil purchases related to specialty products production (for up to 70% of expected purchases). As of September 30, 2010, the Company has hedged at levels approximating 8.5% of its expected specialty products production for the three months ended December 31, 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 September 30, 2010, the Company had the following crude oil derivatives related to crude oil purchases and forecasted changes in crude oil inventory levels 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)
October 2010		186,000		6,000	$	62.48	$	78.44	$	88.44

Totals		186,000
Average price					$	62.48	$	78.44	$	88.44


	Barrels						Average
	Purchased						Swap
Crude Oil Swap Contracts by Expiration Dates	(Sold)			BPD			($/Bbl)
October 2010		155,000			5,000		$	79.77
December 2010		(62,000	)		(2,000	)		(77.70	)
January 2011		62,000			2,000			79.25

Totals		155,000
Average price							$	80.39

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 September 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)
Fourth Quarter 2010		1,840,000		20,000	$	67.29
Calendar Year 2011		5,888,000		16,132		76.81
Calendar Year 2012		4,661,000		12,735		85.56

Totals		12,389,000
Average price					$	78.69

At September 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)
Fourth Quarter 2010		138,000		1,500	$	58.25

Totals		138,000
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 were 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 September 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)
Fourth Quarter 2010		1,196,000		13,000	$	80.41
Calendar Year 2011		2,371,000		6,496		90.58
Calendar Year 2012		1,238,000		3,383		97.62

Totals		4,805,000
Average price					$	89.86

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 September 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		2,788,000		7,638	$	89.08
Calendar Year 2012		3,286,500		8,980		98.92

Totals		6,074,500
Average price					$	94.40

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
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 September 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)
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		1,509,500
Average price					$	80.51

At September 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)
Fourth Quarter 2010		138,000		1,500	$	58.42

Totals		138,000
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 September 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 up to 50% of its upcoming fall and winter months’ anticipated natural gas requirement for a period no greater than three years forward. At September 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)
Fourth Quarter 2010		220,000	$	5.06

Totals		220,000
Average price			$	5.06

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 expiring December 2012 which is not designated as a cash flow hedge.

8. Fair Value of Financial Instruments

The Company’s financial instruments which require fair value disclosure consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and indebtedness. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The fair value of the Company’s term loan was $346,247 and $328,543 at September 30, 2010 and December 31, 2009, respectively. The carrying values of borrowings under the Company’s senior secured revolving credit facility were $31,873 and $39,900 at September 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 September 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 September 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 September 30, 2010, the Company’s asset was not adjusted and its liability was reduced by approximately $808. 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 financial assets and liabilities measured at fair value at September 30, 2010 were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Cash and cash equivalents	$	88	$	—	$	—		$	88
Crude oil swaps		—		—		71,332			71,332
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Natural gas swaps		—		—		—			—
Crude oil options		—		—		339			339
Jet fuel options		—		—		54			54
Pension Plan investments		14,549		—		—			14,549

Total assets at fair value	$	14,637	$	—	$	71,725		$	86,362

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(7,403	)		(7,403	)
Diesel swaps		—		—		(38,724	)		(38,724	)
Jet fuel swaps		—		—		(40,632	)		(40,632	)
Natural gas swaps		—		—		(263	)		(263	)
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(4,802	)		(4,802	)

Total liabilities at fair value	$	—	$	—	$	(91,824	)	$	(91,824	)

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 nine months ended September 30, 2010:


	Derivative
	Instruments, Net
Fair value at January 1, 2010	$	26,138
Realized losses		8,147
Unrealized losses		(13,835	)
Change in fair value of cash flow hedges		(20,080	)
Purchases, issuances and settlements		(20,469	)
Transfers in (out) of Level 3		—

Fair value at September 30, 2010	$	(20,099	)

Total gains (losses) included in net income attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of September 30, 2010	$	(13,835	)

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. Comprehensive income (loss) for the three and nine months ended September 30, 2010 and 2009 was as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net income	$	21,221		$	3,967		$	7,247		$	53,618
Cash flow hedge gain reclassified to net income		(3,952	)		(1,157	)		(11,473	)		(5,243	)
Change in fair value of cash flow hedges		(9,156	)		11,902			(20,080	)		(27,885	)
Defined benefit pension and retiree health benefit plans		59			94			523			283

Total comprehensive income (loss)	$	8,172		$	14,806		$	(23,783	)	$	20,773

11. Unit-Based Compensation and Distributions

A summary of the Company’s nonvested phantom units as of September 30, 2010 and the changes during the nine months ended September 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		65,271			18.86
Vested		(57,223	)		17.77
Forfeited		—			—

Nonvested at September 30, 2010		65,541		$	14.16

For the three months ended September 30, 2010 and 2009, compensation expense of $151 and $57, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. For the nine months ended September 30, 2010 and 2009, compensation expense of $443 and $242, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. As of September 30, 2010 and 2009, there was a total of $928 and $429, respectively, of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately three years.

The Company’s distribution policy is as defined in its partnership agreement. For the three months ended September 30, 2010 and 2009, the Company made distributions of $16,391 and $14,811, respectively, to its partners. For the nine months ended September 30, 2010 and 2009, the Company made distributions of $49,179 and $44,447, 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 September 30, 2010 and 2009 were as follows:


	For the Three Months Ended September 30,
	2010						2009
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	21		$	—		$	63		$	2
Interest cost		334			6			331			11
Expected return on assets		(259	)		—			(187	)		—
Amortization of net (gain) loss		69			(1	)		95			(1	)
Prior service cost		—			(9	)		—			—

Net periodic benefit cost	$	165		$	(4	)	$	302		$	12

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


	For the Nine Months Ended September 30,
	2010						2009
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	63		$	—		$	188		$	7
Interest cost		1,002			18			995			33
Expected return on assets		(776	)		—			(561	)		—
Amortization of net (gain) loss		206			(2	)		286			(3	)
Prior service cost		—			(27	)		—			—

Net periodic benefit cost	$	495		$	(11	)	$	908		$	37

During the three months and nine months ended September 30, 2010, the Company made contributions of $337 and $674 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 nine months ended September 30, 2010 and 2009, the Company made no contributions to its Pension Plan or 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 September 30, 2010 and December 31, 2009 were as follows:


	Quoted Prices in
	Active Markets for
	Identical Assets
	(Level 1)
	September 30,		December 31,
	2010		2009
	Pension		Pension
	Benefits		Benefits
Cash	$	268	$	326
Equity		10,096		8,326
Foreign equities		1,810		2,736
Fixed income		2,375		2,342

	$	14,549	$	13,730

13. Segments and Related Information

a. Segment Reporting

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

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in the notes to consolidated financial statements in the Company’s 2009 Annual Report 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 September 30, 2010	Products		Products			Segments		Eliminations			Total
Sales:
External customers	$	386,051	$	209,222		$	595,273	$	—		$	595,273
Intersegment sales		200,728		7,286			208,014		(208,014	)		—

Total sales	$	586,779	$	216,508		$	803,287	$	(208,014	)	$	595,273

Depreciation and amortization		18,420		—			18,420		—			18,420
Operating income (loss)		31,126		(1,554	)		29,572		—			29,572
Reconciling items to net income:
Interest expense												(7,794	)
Loss on derivative instruments												(357	)
Other												(121	)
Income tax expense												(79	)

Net income											$	21,221

Capital expenditures	$	10,293	$	—		$	10,293	$	—		$	10,293


	Specialty		Fuel		Combined					Consolidated
Three Months Ended September 30, 2009	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	261,966	$	230,465	$	492,431	$	—		$	492,431
Intersegment sales		203,965		5,143		209,108		(209,108	)		—

Total sales	$	465,931	$	235,608	$	701,539	$	(209,108	)	$	492,431

Depreciation and amortization		18,766		—		18,766		—			18,766
Operating income		9,253		4,589		13,842		—			13,842
Reconciling items to net income:
Interest expense											(8,243	)
Loss on derivative instruments											(440	)
Other											(1,271	)
Income tax benefit											79

Net income										$	3,967

Capital expenditures	$	7,373	$	—	$	7,373	$	—		$	7,373


	Specialty		Fuel		Combined					Consolidated
Nine Months Ended September 30, 2010	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	1,020,950	$	573,592	$	1,594,542	$	—		$	1,594,542
Intersegment sales		563,989		34,503		598,492		(598,492	)		—

Total sales	$	1,584,939	$	608,095	$	2,193,034	$	(598,492	)	$	1,594,542

Depreciation and amortization		53,928		—		53,928		—			53,928
Operating income		47,961		4,282		52,243		—			52,243
Reconciling items to net loss:
Interest expense											(22,505	)
Loss on derivative instruments											(21,982	)
Other											(170	)
Income tax expense											(339	)

Net income										$	7,247

Capital expenditures	$	27,310	$	—	$	27,310	$	—		$	27,310


	Specialty		Fuel		Combined					Consolidated
Nine Months Ended September 30, 2009	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	701,222	$	649,513	$	1,350,735	$			$	1,350,735
Intersegment sales		499,482		13,555		513,037		(513,037	)		—

Total sales	$	1,200,704	$	663,068	$	1,863,772	$	(513,037	)	$	1,350,735

Depreciation and amortization		54,582		—		54,582		—			54,582
Operating income		45,591		15,401		60,992		—			60,992
Reconciling items to net income:
Interest expense											(25,333	)
Gain on derivative instruments											20,885
Other											(2,856	)
Income tax expense											(70	)

Net income										$	53,618

Capital expenditures	$	20,718	$	—	$	20,718	$	—		$	20,718


	September 30, 2010			December 31, 2009
Segment assets:
Specialty products	$	3,313,992		$	3,072,815
Fuel products		2,576,179			2,371,750

Combined segments		5,890,171			5,444,565
Eliminations		(4,851,552	)		(4,412,709	)

Total assets	$	1,038,619		$	1,031,856

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three and nine months ended September 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 September 30,
	2010		2009
Specialty products:
Lubricating oils	$	214,926	$	133,388
Solvents		102,276		70,591
Waxes		34,089		27,186
Fuels		298		1,558
Asphalt and other by-products		34,462		29,243

Total	$	386,051	$	261,966

Fuel products:
Gasoline		73,550		79,193
Diesel		97,405		91,056
Jet fuel		34,998		47,502
By-products		3,269		12,714

Total	$	209,222	$	230,465

Consolidated sales	$	595,273	$	492,431


	Nine Months Ended September 30,
	2010		2009
Specialty products:
Lubricating oils	$	555,328	$	362,432
Solvents		285,907		186,218
Waxes		88,698		71,383
Fuels		4,268		6,462
Asphalt and other by-products		86,749		74,727

Total	$	1,020,950	$	701,222

Fuel products:
Gasoline		225,720		229,398
Diesel		239,031		274,724
Jet fuel		100,378		128,867
By-products		8,463		16,524

Total	$	573,592	$	649,513

Consolidated sales	$	1,594,542	$	1,350,735

d. Major Customers

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

14. Subsequent Events

On October 13, 2010, the Company declared a quarterly cash distribution of $0.46 per unit on all outstanding units, or $16,571, for the quarter ended September 30, 2010. The distribution will be paid on November 12, 2010 to unitholders of record as of the close of business on November 2, 2010. This quarterly distribution of $0.46 per unit equates to $1.84 per unit, or $66,284 on an annualized basis.

As of the date of this filing, the net fair value of the Company’s derivatives has increased by approximately $11,000 subsequent to September 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 nine months ended September 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.

Third Quarter 2010 Update

For the three months ended September 30, 2010 and 2009, 53.4% and 44.5%, respectively, of our sales volume and 98.0% and 81.5%, respectively, of our gross profit was generated from our specialty products segment while, for the same period, 46.6% and 55.5%, respectively, of our sales volume and approximately 2.0% and 18.5%, respectively, of our gross profit was generated from our fuel products segment. Despite the continuing challenging economic environment, we noted continued improvements in the specialty petroleum products markets during the third quarter of 2010. The trend of increased demand for our specialty products continued during the third quarter of 2010, with specialty products segment sales volume increasing 23.1% in the three months ended September 30, 2010 from the same period in 2009. Specialty products segment generated a gross profit margin of 15.8% in the three months ended September 30, 2010 under these improved product demand conditions, as compared to a gross profit margin of 12.8% in the same period in 2009.

Our production levels for the third quarter of 2010 were the highest for any quarter to date in 2010 by approximately 5,700 bpd in total primarily due to improved run rates at our Shreveport refinery. Our third quarter 2010 production also increased by 3.7% over our production levels for the third quarter of 2009, primarily due to the addition of volumes under the LyondellBasell Agreements and increases in production rates at our Cotton Valley and Princeton refineries, partially offset by lower production rates at our Shreveport refinery. Production levels at our Shreveport refinery for the current quarter were lower than the same period in 2009 to facilitate the balancing of inventory levels subsequent to the completion of our April 2010 turnaround. These higher net production levels during the third quarter of 2010 had a positive impact on our financial results as they provided additional specialty products volumes to meet the higher demand from our customers.

We also continued to improve our cash flow from operations by generating $87.7 million for the nine months ended September 30, 2010 and paid distributions of $49.2 million in the aggregate to our unitholders during that period. We continue to focus our efforts on generating positive cash flow from operations which we expect will be used to i) maintain compliance with the financial covenants of our credit agreements, ii) improve our liquidity position, iii) pay our quarterly distributions to our unitholders and iv) 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 by approximately $24.6 million and our sales by $45.8 million and $111.1 million for the three and nine months ended September 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 September 30, 2010, we have hedged approximately 12.4 million barrels of fuel products through December 2012 at an average refining margin of $12.26 per barrel. As of September 30, 2010, we have approximately 0.3 million barrels of crude oil swaps and options through January 2011 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 Nine Months Ended September 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 September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(In bpd)				(In bpd)
Total sales volume (1)		60,163		58,630		54,861		57,297
Total feedstock runs (2)		61,678		59,949		55,774		61,069
Facility production: (3)
Specialty products:
Lubricating oils		14,707		13,118		13,268		11,481
Solvents		10,715		7,923		9,240		7,868
Waxes		1,307		1,274		1,157		1,082
Fuels		942		941		1,023		811
Asphalt and other by-products		8,079		7,667		6,649		7,694

Total		35,750		30,923		31,337		28,936

Fuel products:
Gasoline		8,538		9,144		8,674		9,841
Diesel		11,883		12,079		10,592		12,662
Jet fuel		5,336		7,328		5,306		7,184
By-products		735		562		586		529

Total		26,492		29,113		25,158		30,216

Total facility production		62,242		60,036		56,495		59,152


(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 increase in feedstock runs for the three months ended September 30, 2010 compared to the same period in 2009 is due primarily to higher throughput rates at our Princeton and Cotton Valley refineries and the addition of volumes under the LyondellBasell Agreements. These improvements were partially offset by lower overall throughput rates at our Shreveport refinery to facilitate the balancing of inventory levels subsequent to the completion of our April 2010 turnaround discussed below.

		The decrease in feedstock runs for the nine months ended September 30, 2010 compared to the same period in 2009 is primarily due to our decision to reduce crude oil run rates at our facilities during the entire first quarter of 2010 because of the poor economics of running additional barrels, the extended turnaround and reduced throughput rates at our Shreveport refinery during April 2010, and the lower subsequent throughput rates at our Shreveport refinery during the third quarter of 2010 as discussed above. These decreases were partially offset by higher throughput rates at our Cotton Valley refinery and the addition of volumes under the LyondellBasell Agreements.

(3)		Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and 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 increase in the production of specialty products for the three months ended September 30, 2010 compared to the same period in 2009 is primarily the result of the addition of volumes


		under the LyondellBasell Agreements and increased feedstock runs during those periods at our Princeton and Cotton Valley refineries. This increase was partially offset by reduced facility production levels as a result of reduced feedstock runs at our Shreveport refinery during the period as discussed above in footnote 2 of this table. The reduction in production of fuel products for the three months ended September 30, 2010 as compared to the same period in 2009 was also due to reduced feedstock runs at our Shreveport refinery during the current period as discussed in footnote 2 of this table.

		The increase in the production of specialty products for the nine months ended September 30, 2010 compared to the same period in 2009 is primarily the result of the addition of volumes under the LyondellBasell Agreements and improved throughput rates at our Cotton Valley refinery as discussed in footnote 2 of this table. The reduction in production of fuel products for the nine months ended September 30, 2010 as compared to the same period in 2009 is due to reduced feedstock runs at our Shreveport refinery during the current period as discussed in footnote 2 of this table.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(In thousands)						(In thousands)

Sales	$	595,273		$	492,431		$	1,594,542		$	1,350,735
Cost of sales		533,167			451,275			1,451,141			1,212,241

Gross profit		62,106			41,156			143,401			138,494

Operating costs and expenses:
Selling, general and administrative		7,403			7,437			22,894			23,697
Transportation		23,258			18,519			63,460			49,761
Taxes other than income taxes		1,308			1,167			3,431			3,156
Other		565			191			1,373			888

Operating income		29,572			13,842			52,243			60,992

Other income (expense):
Interest expense		(7,794	)		(8,243	)		(22,505	)		(25,333	)
Realized gain (loss) on derivative instruments		(2,288	)		4,045			(8,147	)		3,213
Unrealized gain (loss) on derivative instruments		1,931			(4,485	)		(13,835	)		17,672
Other		(121	)		(1,271	)		(170	)		(2,856	)

Total other expense		(8,272	)		(9,954	)		(44,657	)		(7,304	)

Net income before income taxes		21,300			3,888			7,586			53,688
Income tax expense (benefit)		79			(79	)		339			70

Net income	$	21,221		$	3,967		$	7,247		$	53,618

EBITDA	$	44,125		$	27,709		$	74,915		$	125,417

Adjusted EBITDA	$	40,945		$	42,523		$	89,565		$	119,258

Distributable Cash Flow	$	28,554		$	30,184		$	47,501		$	83,325

Non-GAAP Financial Measures

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

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

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

	•		the ability of our assets to generate cash sufficient to pay interest costs, 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 and provide metrics to analyze our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully trend and analyze the performance of our core cash operations.

We define EBITDA 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.

We define Distributable Cash Flow as Adjusted EBITDA less replacement capital expenditures, cash interest paid (excluding capitalized interest) and income tax expense. Distributable Cash Flow is used by us and our investors to analyze our ability to pay distributions.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)						(In thousands)
Reconciliation of Net Income to EBITDA and Adjusted EBITDA and Distributable Cash Flow:
Net income	$	21,221		$	3,967		$	7,247		$	53,618
Add:
Interest expense		7,794			8,243			22,505			25,333
Depreciation and amortization		15,031			15,578			44,824			46,396
Income tax expense (benefit)		79			(79	)		339			70

EBITDA	$	44,125		$	27,709		$	74,915		$	125,417

Add:
Unrealized (gain) loss from mark to market accounting for hedging activities	$	(2,525	)	$	11,365		$	14,683		$	(10,430	)
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		(655	)		3,449			(33	)		4,271

Adjusted EBITDA	$	40,945		$	42,523		$	89,565		$	119,258

Less:
Replacement capital expenditures (1)		(5,751	)		(4,995	)		(22,090	)		(12,739	)
Cash interest expense (2)		(6,561	)		(7,423	)		(19,635	)		(23,124	)
Income tax (expense) benefit		(79	)		79			(339	)		(70	)

Distributable Cash Flow	$	28,554		$	30,184		$	47,501		$	83,325


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

(2)		Represents cash interest paid by the Partnership, excluding capitalized interest.


	Nine Months Ended
	September 30,
	2010			2009
	(In thousands)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by operating activities:

Distributable Cash Flow	$	47,501		$	83,325
Less:
Replacement capital expenditures (1)		22,090			12,739
Cash interest expense (2)		19,635			23,124
Income tax expense		339			70

Adjusted EBITDA	$	89,565		$	119,258

Add:
Unrealized gain (loss) from mark to market accounting for hedging activities		(14,683	)		10,430
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		33			(4,271	)

EBITDA	$	74,915		$	125,417

Add:
Interest expense, net of amortization		(19,626	)		(22,597	)
Unrealized (gain) loss on derivative instruments		13,835			(17,672	)
Income taxes		(339	)		(70	)
Provision for doubtful accounts		74			(766	)
Changes in assets and liabilities:
Accounts receivable		(42,004	)		(17,937	)
Inventory		(12,964	)		(13,184	)
Other current assets		3,664			3,047
Derivative activity		849			6,680
Accounts payable		70,265			38,298
Other liabilities		1,863			2,829
Other, including changes in noncurrent assets and liabilities		(2,830	)		6,533

Net cash provided by operating activities	$	87,702		$	110,578


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

(2)		Represents cash interest paid by the Partnership, excluding capitalized interest.

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

Sales. Sales increased $102.8 million, or 20.9%, to $595.3 million in the three months ended September 30, 2010 from $492.4 million in the same period in 2009. Sales for each of our principal product categories in these periods were as follows:


	Three Months Ended September 30,
	2010		2009		% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	214,926	$	133,388		61.1	%
Solvents		102,276		70,591		44.9	%
Waxes		34,089		27,186		25.4	%
Fuels (1)		298		1,558		(80.9	)%
Asphalt and by-products (2)		34,462		29,243		17.8	%

Total specialty products	$	386,051	$	261,966		47.4	%

Total specialty products sales volume (in barrels)		2,958,000		2,402,000		23.1	%
Average specialty products sales price per barrel	$	130.51	$	109.06		19.7	%
Fuel products:
Gasoline	$	73,550	$	79,193		(7.1	)%
Diesel		97,405		91,056		7.0	%
Jet fuel		34,998		47,502		(26.3	)%
By-products (3)		3,269		12,714		(74.3	)%

Total fuel products	$	209,222	$	230,465		(9.2	)%

Total fuel products sales volume (in barrels)		2,577,000		2,992,000		(13.9	)%
Average fuel products sales price per barrel	$	85.68	$	74.62		14.8	%
Total sales	$	595,273	$	492,431		20.9	%

Total sales volume (in barrels)		5,535,000		5,394,000		2.6	%


(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 September 30, 2010 increased $124.1 million, or 47.4%, as a result of an increase in the average selling price per barrel of $21.45 or 19.7%, and a 23.1% increase in sales volume as compared to the same period in 2009. Specialty products average selling prices per barrel increased in all product categories driven by improving overall demand and a 12.6% increase in the average cost of crude oil per barrel for the 2010 period as compared to the same period in 2009. The increased volume is primarily due to improving overall specialty products demand as a result of improved economic conditions and the addition of volumes under the LyondellBasell Agreements in 2010.

Fuel products segment sales for the three months ended September 30, 2010 decreased $21.2 million, or 9.2%, primarily due to a 13.9% decrease in sales volume as compared to the third quarter of 2009 as a result of lower overall throughput rates at our Shreveport refinery to facilitate the balancing of inventory levels subsequent to the extended turnaround completed in April 2010. This decrease was partially offset by an increase in the average selling price per barrel of $11.06 or 14.8% driven by market conditions including a 12.5% increase in the average cost of crude oil per barrel. The average selling price per barrel increased for all fuel products, with diesel selling prices experiencing the most significant increases driven by improved market pricing. Also contributing to lower sales was an $18.8 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 $21.0 million, or 50.9%, to $62.1 million in the three months ended September 30, 2010 from $41.2 million in the same period in 2009. Gross profit for our specialty products and fuel products segments was as follows:


	Three Months Ended September 30,
	2010			2009			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products	$	60,880		$	33,523			81.6	%
Percentage of sales		15.8	%		12.8	%
Specialty products gross profit per barrel	$	20.58		$	13.96			47.4	%
Fuel products	$	1,226		$	7,633			(83.9	)%
Percentage of sales		0.6	%		3.3	%
Fuel products gross profit per barrel	$	0.48		$	2.55			(81.2	)%
Total gross profit	$	62,106		$	41,156			50.9	%
Percentage of sales		10.4	%		8.4	%

The increase of $27.4 million in specialty products segment gross profit was primarily due to a 19.7% increase in the average selling price per barrel as further discussed above, while the average cost of crude oil per barrel increased by only 12.6%. Also, specialty products sales volumes increased 23.1%, due primarily to improvements in overall specialty products demand as a result of improved economic conditions and the addition of volumes under the LyondellBasell Agreements in 2010.

Fuel products segment gross profit was negatively impacted by a 13.9% decrease in fuel products sales volume as a result of lower overall throughput rates at our Shreveport refinery to facilitate the balancing of inventory levels subsequent to the extended turnaround completed in April 2010. Partially offsetting this decrease in gross profit per barrel was a slight improvement in crack spreads as the average selling price per barrel of our fuel products increased by 14.8%, as further discussed above, while the average cost of crude oil per barrel increased by 12.5%, combined with a $2.5 million net increase in derivative gains on our fuel products crack spread cash flow hedges.

Transportation. Transportation expenses increased $4.7 million, or 25.6%, to $23.3 million in the three months ended September 30, 2010 from $18.5 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 $0.4 million, or 5.4%, to $7.8 million in the three months ended September 30, 2010 from $8.2 million in the three months ended September 30, 2009 primarily due to lower interest rates and lower balances being carried on the revolver and term loan during the three months ended September 30, 2010 as compared to the same period in 2009.

Realized gain (loss) on derivative instruments. Realized gain (loss) on derivative instruments decreased $6.3 million to a loss of $2.3 million in the three months ended September 30, 2010 from a gain of $4.0 million for the three months ended September 30, 2009. This decrease was primarily due to decreased gains of $3.6 million on our crack spread derivatives that were executed to economically lock in gains on a portion of our fuel products segment derivative hedging activity and increased realized losses of $1.6 million in 2010 on derivatives used to economically hedge our specialty products segment crude oil purchases. In addition, this increased loss was due to increased loss ineffectiveness of $1.3 million on settled fuel products derivatives designated as hedges during the quarter ended September 30, 2010 as compared to the same period in 2009.

Unrealized gain (loss) on derivative instruments. Unrealized gain (loss) on derivative instruments increased $6.4 million, to a gain of $1.9 million in the three months ended September 30, 2010 from a loss of $4.5 million in the three months ended September 30, 2009. This was primarily due to decreases in unrealized losses on crack spread derivatives that were executed to economically lock in gains on a portion of our fuel products segment derivative hedging activity and decreases in unrealized losses on derivatives used to economically hedge our specialty products segment crude oil purchases.

Changes in Results of Operations for the Nine Months Ended September 30, 2010 and 2009

Sales. Sales increased $243.8 million, or 18.0%, to $1,594.5 million in the nine months ended September 30, 2010 from $1,350.7 million in the nine months ended September 30, 2009. Sales for each of our principal product categories in these periods were as follows:


	Nine Months Ended September 30,
	2010		2009		% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	555,328	$	362,432		53.2	%
Solvents		285,907		186,218		53.5	%
Waxes		88,698		71,383		24.3	%
Fuels (1)		4,268		6,462		(34.0	)%
Asphalt and by-products (2)		86,749		74,727		16.1	%

Total specialty products	$	1,020,950	$	701,222		45.6	%

Total specialty products volume (in barrels)		7,894,000		6,983,000		13.0	%
Average specialty products sales price per barrel	$	129.33	$	100.42		28.8	%
Fuel products:
Gasoline		225,720	$	229,398		(1.6	)%
Diesel		239,031		274,724		(13.0	)%
Jet fuel		100,378		128,867		(22.1	)%
By-products (3)		8,463		16,524		(48.8	)%

Total fuel products	$	573,592	$	649,513		(11.7	)%

Total fuel products sales volumes (in barrels)		7,083,000		8,659,000		(18.2	)%
Average fuel products sales price per barrel	$	86.41	$	65.94		31.0	%
Total sales	$	1,594,542	$	1,350,735		18.0	%

Total sales volumes (in barrels)		14,977,000		15,642,000		(4.3	)%


(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 nine months ended September 30, 2010 increased $319.7 million, or 45.6%, primarily due to an increase in the average selling price per barrel of $28.91, or 28.8%driven by improving overall specialty products demand and a 39.2% increase in the average cost of crude oil per barrel. In addition, specialty products segment volumes sold increased by 13.0%, with increases in all product categories with the exception of asphalt and other by-products. The increased volume is due to improving overall specialty products demand as a result of improved economic conditions and the addition of volumes under the LyondellBasell Agreements in 2010.

Fuel products segment sales for the nine months ended September 30, 2010 decreased $75.9 million, or 11.7%, primarily due to a 18.2% decrease in sales volumes, from approximately 8.7 million barrels in the nine months ended September 30, 2009 to 7.1 million barrels in the nine months ended September 30, 2010, primarily due to the lower overall throughput rates at our Shreveport refinery to facilitate the balancing of inventory levels subsequent to the extended turnaround completed in April 2010. Partially offsetting this decrease in sales volumes was an increase in the average selling price per barrel of $20.47 or 31.0%, as compared to a 39.5% increase in the average cost of crude oil per barrel. Sales prices lagged crude cost due to local market conditions. Also contributing to the overall decrease in sales was a $117.0 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 increased $4.9 million, or 3.5%, to $143.4 million for the nine months ended September 30, 2010 from $138.5 million for the same period in 2009. Gross profit for our specialty products and fuel products segments was as follows:


	Nine Months Ended September 30,
	2010			2009			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products	$	130,706		$	114,080			14.6	%
Percentage of sales		12.8	%		16.3	%
Specialty products gross profit per barrel	$	16.56		$	16.34			1.3	%
Fuel products	$	12,695		$	24,414			(48.0	)%
Percentage of sales		2.2	%		3.8	%
Fuel products gross profit per barrel	$	1.79		$	2.82			(36.5	)%
Total gross profit	$	143,401		$	138,494			3.5	%
Percentage of sales		9.0	%		10.3	%

The increase in specialty products segment gross profit was primarily due to a 13.0% increase in specialty products segment sales volumes. Further, the increase in the average selling price per barrel of $28.91 or 28.8%, exceeded the increase in the average cost of crude oil per barrel. These increases were partially offset by higher operating costs per barrel at our Shreveport refinery.

The decrease in fuel products segment gross profit was primarily due to reduced sales volume of 18.2%, higher operating costs per barrel at our Shreveport refinery and increasing crude oil costs per barrel. Partially offsetting this reduction in gross profit was an increase of 31.0% in the average selling price per barrel and increased net derivative gains of $5.7 million on our fuel products crack spread cash flow hedges.

Transportation. Transportation expenses increased $13.7 million, or 27.5%, to $63.5 million in the nine months ended September 30, 2010 from $49.8 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 $2.8 million, or 11.2%, to $22.5 million in the nine months ended September 30, 2010 from $25.3 million in the nine months ended September 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 nine months ended September 30, 2010, as compared to the same period in 2009.

Realized gain (loss) on derivative instruments. Realized gain (loss) on derivative instruments decreased $11.4 million to a loss of $8.1 million in the nine months ended September 30, 2010 from a gain of $3.2 million in the same period in 2009. This decrease is primarily due to reduced derivative gains of $11.7 million in the nine months ended September 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. Also contributing to this decrease in realized gain was increased loss ineffectiveness on settled fuel products derivatives designated as hedges of $7.7 million, which was partially offset by less realized losses in the nine months ended September 30, 2010 on crude oil derivatives in our specialty products segment due to the significant decline in crude oil prices late in 2008 (which resulted in larger realized losses early in 2009), whereas crude oil prices were relatively stable in the nine months ended September 30, 2010 as well as significantly less volume of these derivatives settled in the same period in 2010.

Unrealized gain (loss) on derivative instruments. Unrealized gain (loss) on derivative instruments decreased $31.5 million to a loss of $13.8 million in the nine months ended September 30, 2010 from a gain of $17.7 million for the same period in 2009. This decreased gain was primarily due to increased gains of $11.6 million in the nine months ended September 30, 2009 on the derivatives used to economically hedge our specialty products crude oil purchases and increased gains of $8.1 million in the nine months ended September 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 decreased gain ineffectiveness in the nine months ended September 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 approximately $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:


	Nine Months Ended
	September 30,
	2010			2009
	(In thousands)
Net cash provided by operating activities	$	87,702		$	110,578
Net cash used in investing activities	$	(27,109	)	$	(19,925	)
Net cash used in financing activities	$	(60,554	)	$	(88,134	)

Operating Activities. Operating activities provided $87.7 million in cash during the nine months ended September 30, 2010 compared to $110.6 million during the same period in 2009. The decrease in cash provided by operating activities was primarily due to decreased net income of $46.4 million and a slight increase in net working capital in the nine months ended September 30, 2010 as compared to the same period in 2009, partially offset by increased unrealized derivative losses of $31.5 million in the nine months ended September 30, 2010 as compared to the same period in 2009.

Investing Activities. Cash used in investing activities increased to $27.1 million during the nine months ended September 30, 2010 compared to $19.9 million during the nine months ended September 30, 2009. This is due to increased capital expenditures primarily for replacement and environmental purposes.

Financing Activities. Financing activities used cash of $60.6 million during the nine months ended September 30, 2010 as compared to $88.1 million during the nine months ended September 30, 2009. The decreased use of cash is primarily due to decreased repayments of revolver borrowings in the nine months ended September 30, 2010 as compared to the same period in 2009.

On October 13, 2010, the Company declared a quarterly cash distribution of $0.46 per unit on all outstanding units, or $16.6 million, for the quarter ended September 30, 2010. The distribution will be paid on November 12, 2010 to unitholders of record as of the close of business on November 2, 2010. This quarterly distribution of $0.46 per unit equates to $1.84 per unit, or $66.3 million, on an annualized basis.

Capital Expenditures

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

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


	Nine Months Ended September 30,
	2010		2009
	(In thousands)
Capital improvement expenditures	$	5,217	$	7,979
Replacement capital expenditures		13,546		10,246
Environmental capital expenditures		8,547		2,493

Total	$	27,310	$	20,718

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 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 for the fourth quarter of 2010, with total 2010 capital expenditures exceeding total 2009 capital expenditures by approximately $5 million to $10 million.

Debt and Credit Facilities

As of September 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 September 30, 2010, this margin was 50 basis points for prime and 200 basis points for LIBOR; however, it fluctuates based on quarterly measurement of our Consolidated Leverage Ratio as presented above. 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 September 30, 2010, we had availability under our revolving credit facility of $143.8 million, based on a $251.1 million borrowing base, $75.4 million in outstanding standby letters of credit, and outstanding borrowings of $31.9 million.

Amounts outstanding on our revolving credit facility do materially fluctuate each quarter due to normal changes in working capital, payments of quarterly distributions to unitholders and debt service costs. Specifically, our amount borrowed under our revolving credit facility is typically at its highest levels after we pay for the majority of our crude oil supplies on the 20th day of every month per standard industry terms. The maximum revolving credit facility borrowings during the third quarter were $103.9 million. Nonetheless, our availability on our revolving credit facility during the peak borrowing days of a quarter has been ample to support our operations and service upcoming requirements. During the quarter ended September 30, 2010, availability for additional borrowings under our revolving credit facility was approximately $70.0 million at its lowest point. We believe that we will continue to have sufficient cash flow from operations and borrowing availability under our revolving credit facility to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, credit agreement covenants, contingencies and anticipated capital expenditures.

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


	Requirement	Level at September 30, 2010
Consolidated Leverage Ratio	< 3.75 to 1	3.44 to 1
Consolidated Interest Coverage Ratio	> 2.75 to 1	3.75 to 1

Our credit facilities permit us to make distributions to our unitholders as long as we are not in default and would not be in default following the distribution. Under the credit facilities, we are obligated to comply with certain financial covenants requiring us to maintain a Consolidated Leverage Ratio of no more than 3.75 to 1 and a Consolidated Interest Coverage Ratio of no less than 2.75 to 1 (as of the end of each fiscal quarter and after giving effect to a proposed distribution or other restricted payments as defined in the credit agreements) and Availability (as such term is defined in our credit agreements) of at least $35.0 million (after giving effect to a proposed distribution or other restricted payments as defined in the credit agreements). The Consolidated Leverage Ratio is defined under our credit agreements to mean the ratio of our Consolidated Debt (as defined in the credit agreements) as of the last day of any fiscal quarter to our Adjusted EBITDA (as defined below) for the last four fiscal quarter periods ending on such date. The Consolidated Interest Coverage Ratio is defined as the ratio of Consolidated EBITDA for the last four fiscal quarters to Consolidated Interest Charges for the same period. Adjusted EBITDA means Consolidated EBITDA as defined in our credit facilities to mean, 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); (f) other non-recurring expenses reducing net income which do not represent a cash item for such period; and (g) all non-recurring restructuring charges associated with the Penreco acquisition 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.

In addition, if at any time that our borrowing capacity under our revolving credit facility falls below $35.0 million, meaning we have Availability of less than $35.0 million, we will be required to immediately measure and maintain a Fixed Charge Coverage Ratio of at least 1 to 1 (as of the end of each fiscal quarter). The Fixed Charge Coverage Ratio is defined under our credit agreements to mean the ratio of (a) Adjusted EBITDA minus Consolidated Capital Expenditures minus Consolidated Cash Taxes, to (b) Fixed Charges (as each such term is defined in our credit agreements).

Compliance with the financial covenants pursuant to our credit agreements is measured quarterly based upon performance over the most recent four fiscal quarters, and as of September 30, 2010, we believe we were in compliance with all financial covenants under our credit agreements and have adequate liquidity to conduct our business.

On July 12, 2010, we announced that we and Calumet Finance Corp., our wholly owned subsidiary, intended to offer for sale in a private placement under Rule 144A to eligible purchasers $450 million in aggregate principal amount of senior unsecured notes. We viewed the offering as an opportunity, but not a necessity, to refinance our existing term loan facility with longer-term unsecured notes. However, on July 22, 2010, we announced that, due to market conditions, we opted to not move forward with the contemplated senior notes offering at that time. We intend to continue monitoring the debt markets for the opportunity to complete a debt refinancing transaction under appropriate market conditions.

Contractual Obligations and Commercial Commitments

The following table summarizes our total contractual cash obligations as of September 30, 2010:


			Payments Due by Period
			Less Than		1-3		3-5		More Than
	Total		1 Year		Years		Years		5 Years
					(In thousands)
Operating Activities:
Interest on long-term debt at contractual rates	$	78,374	$	21,006	$	37,525	$	19,843	$	—
Operating lease obligations (1)		36,364		12,456		16,388		6,704		816
Letters of credit (2)		125,375		75,375		—		50,000		—
Purchase commitments (3)		765,081		317,182		290,844		157,055		—
Financing Activities:
Capital lease obligations		2,031		990		982		59		—
Long-term debt obligations, excluding capital lease obligations		400,221		3,850		39,573		7,700		349,098

Total obligations	$	1,407,446	$	430,859	$	385,312	$	241,361	$	349,914


(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 $57.1 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of September 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, Item 3 of our 2010 First Quarterly Report and Item 3 of our 2010 Second 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 September 30, 2010, we estimate we have executed derivative instruments to economically hedge approximately 20% to 30% of forecasted specialty products segment crude oil purchases through October 31, 2010, with minimal additional derivative instruments through January 2011. Also, as of September 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	$	12.4
Diesel swaps	$	(4.8	)
Jet fuel swaps	$	(6.1	)
Gasoline swaps	$	(1.4	)
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 September 30, 2010, we had approximately $400.2 million of variable rate debt. Holding other variables constant (such as debt levels), a one hundred basis point change in interest rates on our variable rate debt as of September 30, 2010 would be expected to have an impact on net income and cash flows of approximately $4.0 million.

We have a $375.0 million revolving credit facility as of September 30, 2010, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had borrowings of $31.9 million outstanding under this facility as of September 30, 2010, bearing interest at the prime rate plus the applicable margin of 50 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 September 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)
Fourth Quarter 2010		1,840,000		20,000	$	11.32
Calendar Year 2011		5,888,000		16,132		12.19
Calendar Year 2012		4,661,000		12,735		12.71

Totals		12,389,000
Average price					$	12.26

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

Totals		138,000
Average price					$	0.17

At September 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 September 30, 2010, the Company had a net 341,000 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 September 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 September 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 third 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*

The risk factors included in our 2009 Annual Report have not materially changed other than as set forth below.

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

Our crude oil and specialty hydrocarbon refining and terminal operations are subject to stringent and complex federal, state and local environmental, health and safety laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection and worker health and safety. These laws and regulations impose numerous obligations that are applicable to our operations, including the requirement to obtain permits to conduct regulated activities, the incurrence of significant capital expenditures to limit or prevent releases of materials from our refineries, terminal, and related facilities, and the incurrence of substantial costs and liabilities for pollution resulting from our operations or from those of prior owners. Numerous governmental authorities, such as the EPA, OSHA, and state agencies, such as the LDEQ, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with laws, regulations, permits and orders may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. On occasion, we receive notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations.

We are in discussions with the LDEQ regarding our participation in the Small Refinery and Single Site Refinery Initiative and anticipate that we will be entering into a settlement agreement with the LDEQ pursuant to which we have proposed to pay penalties totaling $400 and make emissions reductions requiring capital investments between approximately $1.0 million and $3.0 million above our planned levels between 2011 and 2015 at our three Louisiana refineries.

The workplaces associated with the facilities we operate are subject to the requirements of federal OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local government authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances could reduce our ability to make distributions to our unitholders if we are subjected to fines or significant compliance costs.

We have completed studies to assess the adequacy of our process safety management practices at our Shreveport refinery with respect to certain consensus codes and standards. We expect to incur between $5 million and $8 million of capital expenditures in total during 2011, 2012 and 2013 to address OSHA compliance issues identified in these studies. We expect these capital expenditures will enhance our equipment to maintain compliance with applicable requirements at the Shreveport refinery. Beginning in February 2010, OSHA conducted an inspection of our Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program, which is targeting all U.S. refineries for review. On August 19, 2010, OSHA issued us a Citation and Notification of Penalty (the “Citation”) to the Company as a result of this inspection which included a proposed civil penalty amount of $173. We have contested the Citation and penalty amount in a timely manner in an attempt to receive both a reduction in the amount of the civil penalty and an extension of time to complete ongoing capital expenditures designed to strengthen or relocate an existing control room at our Shreveport refinery.

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

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. Also, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur increased operating costs and could adversely affect demand for the refined petroleum products we produce.

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

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including businesses like ours, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the Act. The Act may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities, although the application of those provisions to us is uncertain at this time. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivatives contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on our business, our financial condition, and our results of operations.

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 Second 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 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

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

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

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

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

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

3.7*		Specimen Unit Certificate representing common units.

10.24		Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.24 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000-51734)).

10.25		Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Lubricants Co., Limited Partnership., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.25 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000-51734)).

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: November 4, 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 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

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

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

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

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

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

3.7*		Specimen Unit Certificate representing common units.

10.24		Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.24 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000-51734)).

10.25		Amendment No. 4 to Crude Oil Supply Agreement, dated as of August 30, 2010 and effective September 1, 2010, between Calumet Lubricants Co., Limited Partnership., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.25 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2010 (File No 000-51734)).

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-3.7 EX-31.1 EX-31.2 EX-32.1

CLMT 10-Q Quarter ended Sept. 30, 2010

Exhibits