Calumet Specialty Products Partners 10Q 2009 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended March 31, 2009


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

FOR THE TRANSITION PERIOD FROM TO

Commission File number 000-51734

Calumet Specialty Products Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)


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

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

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

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

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

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


Large accelerated filero		Accelerated filerþ		Non-accelerated filero (Do not check if a smaller reporting company)		Smaller reporting companyo

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

At May 6, 2009, there were 19,166,000 common units and 13,066,000 subordinated units outstanding.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-Q — March 31, 2009 QUARTERLY REPORT

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		29
Item 3. Quantitative and Qualitative Disclosures About Market Risk		43
Item 4. Controls and Procedures		46
Part II
Item 1. Legal Proceedings		46
Item 1A. Risk Factors		47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		47
Item 3. Defaults Upon Senior Securities		47
Item 4. Submission of Matters to a Vote of Security Holders		47
Item 5. Other Information		47
Item 6. Exhibits		48
EX-31.1
EX-31.2
EX-32.1

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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 on Form 10-Q may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. The statements regarding (i) expected settlements with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental and regulatory liabilities, (ii) our anticipated levels of use of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes, (iii) future compliance with our debt covenants, (iv) improvements in our liquidity, and (v) future increases in Shreveport refinery throughput rates as well as other matters discussed in this Quarterly Report on Form 10-Q 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 on Form 10-Q and in our Annual Report on Form 10-K filed on March 4, 2009. The risk factors and other factors noted throughout this Quarterly Report on Form 10-Q 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 or businesses;

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

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

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

	•		fluctuations in refinery capacity;

	•		the effects of competition;

	•		continued creditworthiness of, and performance by, counterparties;

	•		the impact of current and future laws, rulings and governmental regulations;

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

	•		hurricane or other weather interference with business operations;

	•		fluctuations in the debt and equity markets;

	•		accidents or other unscheduled shutdowns; and

	•		general economic, market or business conditions.

Other factors described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Our forward looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward looking statement. Please read Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk.” We will not update these statements unless securities laws require us to do so.

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

References in this Quarterly Report on Form 10-Q to “Calumet,” “the Partnership,” “the Company,” “we,” “our,” “us” or like terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References in this Quarterly Report on Form 10-Q to “our general partner” refer to Calumet GP, LLC.

PART I

Item 1.Financial Statements

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2009		December 31, 2008
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	28	$	48
Accounts receivable:
Trade		97,992		103,962
Other		4,326		5,594

		102,318		109,556

Inventories		148,976		118,524
Derivative assets		86,793		71,199
Prepaid expenses and other current assets		1,119		1,803
Deposits		21		4,021

Total current assets		339,255		305,151
Property, plant and equipment, net		652,247		659,684
Goodwill		48,335		48,335
Other intangible assets, net		46,649		49,502
Other noncurrent assets, net		16,496		18,390

Total assets	$	1,102,982	$	1,081,062


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable	$	68,674	$	87,460
Accounts payable — related party		27,966		6,395
Accrued salaries, wages and benefits		6,773		6,865
Taxes payable		8,842		6,833
Other current liabilities		7,431		9,662
Current portion of long-term debt		4,778		4,811
Derivative liabilities		5,837		15,827

Total current liabilities		130,301		137,853
Pension and postretirement benefit obligations		9,938		9,717
Long-term debt, less current portion		450,050		460,280

Total liabilities		590,289		607,850

Commitments and contingencies
Partners’ capital:
Common unitholders (19,166,000 units authorized, issued and outstanding)		399,369		363,935
Subordinated unitholders (13,066,000 units authorized, issued and outstanding)		59,900		35,778
General partner’s interest		19,147		17,933
Accumulated other comprehensive income		34,277		55,566

Total partners’ capital		512,693		473,212

Total liabilities and partners’ capital	$	1,102,982	$	1,081,062

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months Ended
	March 31,
	2009			2008
	(In thousands, except per unit data)
Sales	$	414,264		$	594,723
Cost of sales		335,293			559,889

Gross profit		78,971			34,834

Operating costs and expenses:
Selling, general and administrative		9,322			8,252
Transportation		15,155			23,860
Taxes other than income taxes		1,125			1,054
Other		418			224

Operating income		52,951			1,444

Other income (expense):
Interest expense		(8,644	)		(5,166	)
Debt extinguishment costs		—			(526	)
Realized loss on derivative instruments		(8,470	)		(2,877	)
Unrealized gain on derivative instruments		39,739			3,570
Other		144			171

Total other income (expense)		22,769			(4,828	)

Net income (loss) before income taxes		75,720			(3,384	)
Income tax expense		82			8

Net income (loss)	$	75,638		$	(3,392	)


Calculation of common unitholders’ interest in net income (loss):
Net income (loss)	$	75,638		$	(3,392	)
Less:
General partner’s interest in net income (loss)		1,510			(68	)
Subordinated unitholders’ interest in net income (loss)		30,002			(1,347	)

Net income (loss) available to common unitholders	$	44,126		$	(1,977	)


Weighted average number of common units outstanding – basic and diluted		19,166			19,166

Weighted average number of subordinated units outstanding – basic and diluted		13,066			13,066


Common and subordinated unitholders’ basic and diluted net income (loss) per unit		2.30			(0.10	)

Cash distributions declared per common and subordinated unit	$	0.45		$	0.63

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Accumulated Other			Partners’ Capital
	Comprehensive			General			Limited Partners
	Income			Partner			Common			Subordinated			Total
							(In thousands)
Balance at December 31, 2008	$	55,566		$	17,933		$	363,935		$	35,778		$	473,212
Comprehensive income:
Net income					1,510			44,126			30,002			75,638
Cash flow hedge gain reclassified to net income upon settlement		(1,311	)											(1,311	)
Change in fair value of cash flow hedges		(20,072	)											(20,072	)
Minimum pension liability adjustment		94												94

Comprehensive income														54,349
Common units repurchased for vested phantom unit grants								(105	)					(105	)
Amortization of vested phantom units								55						55
Distributions to partners					(296	)		(8,642	)		(5,880	)		(14,818	)

Balance at March 31, 2009	$	34,277		$	19,147		$	399,369		$	59,900		$	512,693

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Operating activities
Net income (loss)	$	75,638		$	(3,392	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		16,135			11,350
Amortization of turnaround costs		1,597			330
Provision for doubtful accounts		240			400
Non-cash debt extinguishment costs		—			526
Unrealized gain on derivative instruments		(39,739	)		(3,570	)
Other non-cash activity		106			114
Changes in assets and liabilities:
Accounts receivable		6,998			(16,745	)
Inventories		(30,452	)		24,494
Prepaid expenses and other current assets		684			6,237
Derivative activity		(7,228	)		5,961
Deposits		4,000			—
Other assets		(76	)		1,372
Accounts payable		2,785			32,910
Accrued salaries, wages and benefits		(92	)		349
Taxes payable		2,009			1,235
Other current liabilities		(287	)		475
Pension and postretirement benefit obligations		315			383

Net cash provided by operating activities		32,633			62,429
Investing activities
Additions to property, plant and equipment		(4,945	)		(90,274	)
Acquisition of Penreco, net of cash acquired		—			(268,969	)

Net cash used in investing activities		(4,945	)		(359,243	)
Financing activities
Repayments of borrowings, net — revolving credit facility		(9,569	)		(6,958	)
Repayments of borrowings — prior term loan credit facility		—			(30,099	)
Proceeds from (Repayments of) borrowings, net — existing term loan credit facility		(963	)		366,637
Debt issuance costs		—			(10,996	)
Payments on capital lease obligation		(309	)		—
Change in bank overdraft		(1,944	)		98
Common units repurchased for vested phantom unit grants		(105	)		(115	)
Distributions to partners		(14,818	)		(21,738	)

Net cash provided by (used in) financing activities		(27,708	)		296,829

Net increase (decrease) in cash and cash equivalents		(20	)		15
Cash and cash equivalents at beginning of period		48			35

Cash and cash equivalents at end of period	$	28		$	50

Supplemental disclosure of cash flow information
Interest paid	$	7,917		$	5,666
Income taxes paid	$	—		$	7

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands, except operating, unit, per unit and per barrel data)

1. Description of the Business

Calumet Specialty Products Partners, L.P. (Calumet, Partnership, or the Company) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. On January 31, 2006, the Partnership completed the initial public offering of its common units. At that time, substantially all of the assets and liabilities of Calumet Lubricants Co., Limited Partnership and its subsidiaries were contributed to Calumet. As of March 31, 2009, Calumet had 19,166,000 common units, 13,066,000 subordinated units, and 657,796 general partner equivalent units outstanding. The general partner owns 2% of Calumet while the remaining 98% is owned by limited partners. On January 3, 2008 the Company acquired Penreco, a Texas general partnership, for approximately $269,118. Calumet is engaged in the production and marketing of crude oil-based specialty lubricating oils, white mineral oils, solvents, petrolatums, waxes and fuels. Calumet owns facilities located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport, Louisiana, Karns City, Pennsylvania, and Dickinson, Texas, and a terminal located in Burnham, Illinois.

The unaudited condensed consolidated financial statements of the Company as of March 31, 2009 and for the three months ended March 31, 2009 and 2008 included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three months ended March 31, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 4, 2009.

2. New Accounting Pronouncements

In December 2007, the FASB issued FASB Statement No. 141(R),Business Combinations(the “Statement”). The Statement applies to the financial accounting and reporting of business combinations. The Statement is effective for business combination transactions for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company will apply the provisions of the Statement for all future acquisitions.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133(“SFAS 161”). SFAS 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS 133 have been applied, and the impact that hedges have on an entity’s financial position, results of operations, and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Company has adopted SFAS 161 as of January 1, 2009. Because SFAS 161 applies only to financial statement disclosures, it did not have any impact on the Company’s financial position, results of operations, or cash flows.

In March 2008, the FASB issued EITF Issue No. 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships(“EITF 07-4”). EITF 07-4 requires master limited partnerships to treat incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to pay IDRs. EITF 07-4 requires that undistributed earnings be allocated to the partnership interests based on the allocation of earnings to capital accounts as specified in the respective partnership agreement. When distributions exceed earnings, EITF 07-4 requires that net income be reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the respective partnership agreement. EITF 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Company has adopted EITF 07-4 as of January 1, 2009 and applied it retrospectively. The impact of EITF 07-4 on our calculation of earnings per unit as reported for the three months ended March 31, 2008 is as follows:


	Three Months Ended March 31, 2008, as Adjusted
	for EITF 07-4
Net income (loss)	$	(3,392	)
Less:
General partner’s interest in net income (loss)		(68	)
Subordinated unitholders interest in net income (loss)		(1,347	)

Net income (loss) available to common unitholders	$	(1,977	)


Weighted average number of common units outstanding – basic and diluted		19,166

Weighted average number of subordinated units outstanding – basic and diluted		13,066


Common and subordinated unitholders’ basic and diluted net income (loss) per unit		(0.10	)

Cash distributions declared per common and subordinated unit	$	0.63


	Three Months Ended March 31, 2008, as Previously
	Reported
Net income (loss)	$	(3,392	)
Minimum quarterly distribution to common unitholders		(8,625	)
General partner’s incentive distribution rights		—
General partner’s interest in net (income) loss		68
Common unitholders’ share of income in excess of minimum quarterly distribution		—

Subordinated unitholders’ interest in net income (loss)	$	(11,949	)

Basic and diluted net income (loss) per limited partner unit:
Common	$	0.45
Subordinated	$	(0.91	)

Weighted average limited partner common units outstanding – basic and diluted		19,166
Weighted average limited partner subordinated units outstanding – basic and diluted		13,066

Cash distributions declared per common and subordinated unit	$	0.63

In April 2008, the FASB issued FASB Staff Position No. 142-3,Determination of the Useful Life of Intangible Assets, (“FSP No. 142-3”) that amends the factors considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142,Goodwill and Other Intangible Assets(“SFAS No. 142”). FSP No. 142-3 requires a consistent approach between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of an asset under SFAS No. 141(R),Business Combinations. FSP No. 142-3 also requires enhanced disclosures when an intangible asset’s expected future cash flows are affected by an entity’s intent and/or ability to renew or extend the arrangement. FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and is applied prospectively. The Company has adopted FSP No. 142-3 and applied its various provisions as required as of January 1, 2009. The adoption of FSP No. 142-3 did not have a material affect on the Company’s financial position, results of operations, or cash flows.

In December 2008, the FASB issued FASB Staff Position No. FAS 132R-1,Employers’ Disclosures about Postretirement Benefit Plan Assets(the “FSP FAS 132R-1”). FSP FAS 132R-1 replaces the requirement to disclose the percentage of the fair value of total plan assets with a requirement to disclose the fair value of each major asset category. FSP FAS 132R-1 also requires additional disclosure regarding the level of the plan assets within the fair value hierarchy according to FASB Statement No. 157 and a reconciliation of activity for any plan assets being measured using unobservable inputs as defined in FASB Statement No. 157. FSP FAS 132R-1 is effective for fiscal years ending after December 15, 2009. The Company expects that the adoption of FSP FAS 132R-1 will not have a material impact on the Company’s financial position, results of operations, or cash flows.

3. Inventories

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

Inventories consist of the following:


	March 31,		December 31,
	2009		2008
Raw materials	$	21,899	$	24,955
Work in process		49,925		43,735
Finished goods		77,152		49,834

	$	148,976	$	118,524

The replacement cost of these inventories, based on current market values, would have been $7,067 and $27,517 higher as of March 31, 2009 and December 31, 2008, respectively. During the three months ended March 31, 2008, the Company recorded $9,120 of gains in cost of sales in the unaudited condensed consolidated statements of operations due to the liquidation of lower cost inventory layers. No gains were recorded in 2009.

4. Acquisition of Penreco

On January 3, 2008 the Company acquired Penreco, a Texas general partnership, for $269,118, net of the cash acquired. Penreco was owned by ConocoPhillips Company and M.E. Zukerman Specialty Oil Corporation. Penreco manufactures and markets highly-refined products and specialty solvents, including white mineral oils, petrolatums, natural petroleum sulfonates, cable-filling compounds, refrigeration oils, food-grade compressor lubricants and gelled products. The acquisition included facilities in Karns City, Pennsylvania and Dickinson, Texas, as well as several long-term supply agreements with ConocoPhillips Company.

The Company believes that this acquisition has provided several key strategic benefits, including market synergies within its solvents and lubricating oil product lines, additional operational and logistics flexibility and overhead cost reductions resulting from the acquisition. The acquisition has broadened the Company’s customer base and given the Company access to new markets.

As a result of the acquisition, the assets and liabilities previously held by Penreco and results of the operations of these assets have been included in the Company’s unaudited condensed consolidated balance sheets and unaudited condensed consolidated statements of operations since the date of acquisition.

5. Commitments and Contingencies

From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxing and regulatory authorities, such as the Louisiana Department of Environmental Quality (“LDEQ”), Environmental Protection Agency (“EPA”), IRS and Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position, results of operations or cash flows.

Environmental

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

Failure to comply with environmental laws and regulations may result in the triggering of administrative, civil and criminal measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of the Company’s operations. On occasion, the Company receives notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. In particular, the LDEQ has proposed penalties totaling approximately $400 and supplemental environmental capital projects for the following alleged violations: (i) a May 2001 notification received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations, as identified in the course of the Company’s Leak Detection and Repair program, and also for failure to submit various reports related to the facility’s air emissions; (ii) a December 2002 notification received by the Company’s Cotton Valley refinery from the LDEQ regarding alleged violations for excess emissions, as identified in the LDEQ’s file review of the Cotton Valley refinery; (iii) a December 2004 notification received by the Cotton Valley refinery from the LDEQ regarding alleged violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency; and (iv) an August 2005 notification received by the Princeton refinery from the

LDEQ regarding alleged violations of air emissions regulations, as identified by the LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emissions levels. The Company anticipates that any penalties that may be assessed due to the alleged violations will be consolidated in a settlement agreement that the Company anticipates executing with the LDEQ in connection with the agency’s “Small Refinery and Single Site Refinery Initiative” described below. The Company has recorded a liability for the proposed penalty within other current liabilities on the unaudited condensed consolidated balance sheets. Environmental expenses are recorded within other expenses in the unaudited condensed consolidated statements of operations.

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

Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state 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. During 2008, the Company determined that it would incur approximately $700 of costs during 2009 at its Cotton Valley refinery in connection with continued remediation of groundwater impacts at that site.

The Company and the EPA have resolved alleged deficiencies in risk management planning in connection with a fire-related incident arising out of tank cleaning and vacuum truck operations at the Company’s Shreveport refinery on October 30, 2008. The incident involved a third-party contractor and resulted in damage to an on-site aboveground storage tank. Following an investigation of the matter, EPA issued five violations against the Company alleging, among other things, inadequate contractor training and oversight, and proposed a penalty of $230, which the Company has agreed to and paid subsequent to March 31, 2009.

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.

The Company is indemnified on a limited basis by ConocoPhillips Company and M.E. Zuckerman Specialty Oil Corporation, former owners of Penreco, for pending, threatened, contemplated or contingent environmental claims against Penreco, if any, that were not known and identified as of the Penreco acquisition date. A significant portion of these indemnifications will expire on January 1, 2010 if there are no claims asserted by the Company and are generally subject to a $2,000 limit.

Health and Safety

The Company is subject to various laws and regulations relating to occupational health and safety including OSHA, and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens. 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 commissioned studies to assess the adequacy of its process safety management practices at its Shreveport refinery with respect to certain consensus codes and standards, some of which have been recently reviewed. Depending on the findings made in these studies, the Company may incur capital expenditures over the next several years to enhance its programs and equipment so that it may

maintain its compliance with applicable requirements at the Shreveport refinery. While the Company does not expect these expenditures to be material at this time, it has not yet received the reports from the engineering firms conducting the studies to reach final determination. 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 March 31, 2009 and December 31, 2008, the Company had outstanding standby letters of credit of $20,055 and $21,355, respectively, under its senior secured revolving credit facility. The maximum amount of letters of credit the Company can issue is limited to its availability under its revolving credit facility or $300,000, whichever is lower. As of March 31, 2009 and December 31, 2008, the Company had availability to issue letters of credit of $69,151 and $51,865, respectively, under its revolving credit facility. As discussed in Note 6, as of March 31, 2009 the Company also had a $50,000 letter of credit outstanding under its senior secured first lien letter of credit facility for its fuels hedging program, which bears interest at 4.0%.

6. Long-Term Debt

Long-term debt consisted of the following:


	March 31,			December 31,
	2009			2008

Borrowings under senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 4.00% (5.23% and 6.15% at March 31, 2009 and December 31, 2008, respectively), interest and principal payments quarterly with borrowings due January 2015, effective interest rate of 7.47% at March 31, 2009	$	374,123		$	375,085
Borrowings under senior secured revolving credit agreement with third-party lenders, interest at prime plus 0.50% (3.75% and 3.75% at March 31, 2009 and December 31, 2008, respectively), interest payments monthly, borrowings due January 2013		92,970			102,539
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly with borrowings due January 2012		2,381			2,640
Less unamortized discount on senior secured first lien term loan with third-party lenders		(14,646	)		(15,173	)

Total long-term debt		454,828			465,091
Less current portion of long-term debt		4,778			4,811

	$	450,050		$	460,280

The Partnership’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. The term loan bears interest at a rate equal (i) with respect to a LIBOR Loan, the LIBOR Rate plus 400 basis points and (ii) with respect to a Base Rate Loan, the Base Rate plus 300 basis points (as defined in the term loan credit agreement). The letter of credit facility to support crack spread hedging bears interest at 4.0%.

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.

On January 3, 2008, the Partnership amended its existing senior secured revolving credit facility dated as of December 9, 2005, Pursuant to this amendment, the revolving credit facility lenders agreed to, among other things, (i) increase the total availability under the revolving credit facility up to $375,000, subject to borrowing base limitations, and (ii) conformed certain of the financial covenants and other terms in the revolving credit facility to those contained in the term loan credit agreement. 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 prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. This margin is currently at 50 basis points for prime and 200 basis points for LIBOR; however, it fluctuates based on quarterly measurement of the Company’s Consolidated Leverage Ratio. The existing senior secured revolving credit facility matures on January 3, 2013.

The borrowing capacity at March 31, 2009 under the revolving credit facility was $182,176 with $69,151 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.

While assurances cannot be made regarding the Company’s future compliance with the financial covenants in its credit agreements, and being cognizant of the general uncertain economic environment, the Company anticipates that it will be able to maintain compliance with such financial covenants and to continue to improve its liquidity and distributable cash flow.

Failure to achieve the Company’s anticipated results may result in a breach of certain of the financial covenants contained in its credit agreements. If this occurs, the Company will enter into discussions with its lenders to either modify the terms of the existing credit facilities or obtain waivers of non-compliance with such covenants. There can be no assurances of the timing of the receipt of any such modification or waiver, the term or costs associated therewith or the Company’s ultimate ability to obtain the relief sought. The Company’s failure to obtain a waiver of non-compliance with certain of the financial covenants or otherwise amend the credit facilities would constitute an event of default under its credit facilities and would permit the lenders to pursue remedies. These remedies could include acceleration of maturity under the credit facilities and limitations or the elimination of the Company’s ability to make distributions to its unitholders. If the Company’s lenders accelerate maturity under its credit facilities, a significant portion of its indebtedness may become due and payable immediately. The Company might not have, or be able to obtain, sufficient funds to make these accelerated payments. If the Company is unable to make these accelerated payments, its lenders could seek to foreclose on its assets.

As of March 31, 2009, maturities of the Company’s long-term debt are as follows:


Year	Maturity
2009	$	3,590
2010		4,594
2011		4,460
2012		4,175
2013		96,820
Thereafter		355,835

Total	$	469,474

7. Derivatives

The Company is exposed to significant fluctuations in the price of crude oil, its principal raw material, as well as the sales prices of gasoline, diesel and jet fuel. Given the historical volatility of crude oil, gasoline, diesel and jet fuel prices, this exposure can significantly impact sales and gross profit. Therefore, 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.

In accordance with Statement of Financial Accounting Standards (SFAS) No. 133,Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138 and in May 2003 by SFAS No. 149 (collectively referred to as “SFAS 133”), the Company recognizes all derivative instruments at their fair values in accordance with SFAS 157 (see Note 9) as either assets or liabilities on the unaudited 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 or payable from or to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The Company had recorded the following derivative assets and liabilities at fair values as of March 31, 2009 and December 31, 2008:


	Derivative Assets						Derivative Liabilities
	March 31, 2009			December 31, 2008			March 31, 2009			December 31, 2008
Derivative instruments designated as cash flow hedges:
Fuel products segment:
Crude oil swaps	$	(119,299	)	$	(93,197	)	$	—		$	(40,283	)
Gasoline swaps		79,647			115,172			—			4,459
Diesel swaps		120,322			50,652			—			39,685
Specialty products segment:
Crude oil collars		—			—			—			—
Natural gas swaps		—			—			—			(206	)
Interest rate swap		—			—			(3,647	)		(3,582	)

Total derivative instruments designated as cash flow hedges		80,670			72,627			(3,647	)		73

Derivative instruments not designated as cash flow hedges:
Fuel products segment:
Crude oil swaps (1)		8,047			12,929			—			1,349
Gasoline swaps (1)		(2,154	)		(14,357	)		—			(1,494	)
Diesel swaps		—			—			—			—
Jet fuel crack spread collars (4)		403			—			—			—
Specialty products segment:
Crude oil collars (2)		(173	)		—			—			(12,345	)
Natural gas swaps (2)		—			—			—			(1,223	)
Interest rate swaps (3)		—			—			(2,190	)		(2,187	)

Total derivative instruments not designated as cash flow hedges		6,123			(1,428	)		(2,190	)		(15,900	)

Total derivative instruments	$	86,793		$	71,199		$	(5,837	)	$	(15,827	)


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

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

(3)		The Company refinanced its long-term debt in January 2008 and as a result the interest rate swap designated as a hedge of the interest payments related to the previous debt agreement no longer qualified for hedge accounting. The Company entered into an offsetting interest rate swap to fix the value of this derivative instrument and is settling this position over the original term of the derivative instrument. No additional interest rate risk on these derivative instruments exists.

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

To the extent a derivative instrument is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income, a component of partners’ capital in the unaudited 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, the sale 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 on-going 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 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 loss on derivative instruments in the unaudited condensed consolidated statements of operations.

The Company recorded the following amounts in its unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital for the three months ended March 31, 2009 and 2008 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)
	For the Three Months Ended March 31,						Location of (Gain)	For the Three Months Ended March 31,						Location of Gain	For the Three Months Ended March 31,
Type of Derivative	2009			2008			Loss	2009			2008			(Loss)	2009		2008
Fuel products segment:
Crude oil swaps	$	(142,869	)	$	666,184		Cost of sales	$	36,410		$	(53,167	)	Unrealized/ Realized	$	13,005	$	(10	)
Gasoline swaps		85,542			(239,112	)	Sales		(20,667	)		20,973		Unrealized/ Realized		2,644		(3	)
Diesel swaps		101,381			(524,685	)	Sales		(18,482	)		34,062		Unrealized/ Realized		7,745		2,905
Specialty products segment:
Crude oil collars		—			4,614		Cost of sales		—			(2,758	)	Unrealized/ Realized		—		(617	)
Natural gas swaps		—			570		Cost of sales		1,428			1,568		Unrealized/ Realized		—		311
Interest rate swaps		(3,647	)		(2,116	)	Interest expense		—			—		Unrealized/ Realized		—		—

Total	$	40,407		$	(94,545	)		$	(1,311	)	$	678			$	23,394	$	2,586

The Company recorded the following gains (losses) in its unaudited condensed consolidated statement of operations for the three months ended March 31, 2009 and 2008 related to its derivative instruments not designated as cash flow hedges:


	Amount of Gain (Loss) Recognized in						Amount of Gain (Loss) Recognized
	Realized Loss on Derivatives Three Months Ended March 31,						in Unrealized Gain on Derivatives Three Months Ended March 31,
Type of Derivative	2009			2008			2009			2008
Fuel products segment:
Crude oil swaps	$	11,510		$	3,323		$	(8,989	)	$	(3,323	)
Gasoline swaps		(5,736	)		(1,931	)		13,829			(1,317	)
Diesel swaps		(1,664	)		(4,018	)		1,664			6,408
Jet fuel collars		—			—			(159	)		—
Specialty products segment:
Crude oil collars		(14,261	)		—			12,172			210
Natural gas swaps		(1,507	)		—			1,223			—
Interest rate swaps		(204	)		(251	)		(3	)		(994	)

Total	$	(11,862	)	$	(2,877	)	$	19,737		$	984

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 a small number of counterparties, the majority of which are large financial institutions and all 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 or held by counterparties is netted against the derivative asset or liability. The Company provides the counterparties with collateral when the fair value of its obligation exceeds specified amounts for each counterparty. As of March 31, 2009, the Company had provided the counterparties with no cash collateral. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.

Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating was lowered below its current level by either Moody’s or S&P, such counterparties would have the right to reduce the applicable threshold to zero and demand full collateralization of the Company’s net liability position on outstanding derivative instruments. As of March 31, 2009, there is no net liability associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.

The effective portion of the hedges classified in accumulated other comprehensive income is $40,407 as of March 31, 2009 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)
2009	$	12,842
2010		21,728
2011		6,810
2012		(973	)

Total	$	40,407

Based on fair values as of March 31, 2009, the Company expects to reclassify $18,560 of net gains on derivative instruments from accumulated other comprehensive income (loss) to earnings during the next twelve months due to actual crude oil purchases, gasoline, diesel and jet fuel sales, and the payment of variable interest associated with floating rate debt. However, the amounts actually realized will be dependent on the fair values as of the date of settlements.

Crude Oil Collar Contracts — Specialty Products Segment

The Company is exposed to significant 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 of SFAS 133. The Company’s policy is generally to enter into crude oil derivative contracts for up to 70% of expected purchases that mitigate its exposure to price risk associated with crude oil purchases related to specialty products production. Generally, the Company’s policy is that these positions will be short term in nature and expire within three to nine months from execution; however, the Company may execute derivative contracts for up to two years forward if a change in the risks support lengthening the Company’s position. As of March 31, 2009, the Company had the following crude oil derivative instruments for the second quarter 2009 in its specialty products segment, none of which are designated as hedges.


					Average		Average		Average		Average
					Bought Put		Sold Put		Bought Call		Sold Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)		($/Bbl)
April 2009		105,000		3,500	$	33.49	$	43.49	$	53.49	$	63.49
May 2009		93,000		3,000		34.55		44.55		54.55		64.55
June 2009		30,000		1,000		34.50		44.50		54.50		64.50

Totals		228,000
Average price					$	34.06	$	44.06	$	54.06	$	64.06


					Average		Average		Average
					Bought Put		Bought Swap		Sold Call
Crude Oil Put/Swap/Call Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)
April 2009		60,000		2,000	$	41.33	$	53.55	$	63.55
May 2009		62,000		2,000		45.53		55.30		64.50
June 2009		90,000		3,000		43.47		53.42		62.83

Totals		212,000
Average price					$	43.46	$	54.01	$	63.52

At December 31, 2008, 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		Average
					Bought Put		Sold Put		Bought Call		Sold Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)		($/Bbl)
January 2009		217,000		7,000	$	50.32	$	60.32	$	70.32	$	80.32
February 2009		84,000		3,000		38.33		48.33		58.33		68.33

Totals		301,000
Average price					$	46.98	$	56.98	$	66.98	$	76.98


					Average		Average
					Sold Put		Bought Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
January 2009		186,000		6,000	$	68.57	$	90.83
February 2009		112,000		4,000		74.85		96.25
March 2009		93,000		3,000		79.37		101.67

Totals		391,000
Average price					$	72.94	$	94.96

Crude Oil Swap Contracts — Fuel Products Segment

The Company is exposed to significant fluctuations in the price of crude oil, its principal raw material. The Company utilizes swap contracts to manage crude oil price risk and volatility of cash flows in its fuel products segment. The Company’s policy is generally to enter into crude oil swap contracts for a period no greater than five years forward and for no more than 75% of crude oil purchases used in fuels production. At March 31, 2009, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as hedges.


Crude Oil Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Second Quarter 2009		2,047,500		22,500	$	66.26
Third Quarter 2009		2,070,000		22,500		66.26
Fourth Quarter 2009		2,070,000		22,500		66.26
Calendar Year 2010		7,300,000		20,000		67.29
Calendar Year 2011		3,009,000		8,244		76.98

Totals		16,496,500
Average price					$	68.67

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


	Barrels
Crude Oil Swap Contracts by Expiration Dates	Sold		BPD		($/Bbl)
Second Quarter 2009		455,000		5,000	$	62.66
Third Quarter 2009		460,000		5,000		62.66
Fourth Quarter 2009		460,000		5,000		62.66
Calendar Year 2010		547,500		1,500		58.25

Totals		1,922,500
Average price					$	61.40

At December 31, 2008, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which were designated as hedges.


	Barrels
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 2009		2,025,000		22,500	$	66.26
Second Quarter 2009		2,047,500		22,500		66.26
Third Quarter 2009		2,070,000		22,500		66.26
Fourth Quarter 2009		2,070,000		22,500		66.26
Calendar Year 2010		7,300,000		20,000		67.29
Calendar Year 2011		3,009,000		8,244		76.98

Totals		18,521,500
Average price					$	68.41

At December 31, 2008, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges.


Crude Oil Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2009		450,000		5,000	$	62.66
Second Quarter 2009		455,000		5,000		62.66
Third Quarter 2009		460,000		5,000		62.66
Fourth Quarter 2009		460,000		5,000		62.66

Totals		1,825,000
Average price					$	62.66

Fuel Products Swap Contracts

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

Diesel Swap Contracts

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


Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2009		1,183,000		13,000	$	80.51
Third Quarter 2009		1,196,000		13,000		80.51
Fourth Quarter 2009		1,196,000		13,000		80.51
Calendar Year 2010		4,745,000		13,000		80.41
Calendar Year 2011		2,371,000		6,496		90.58

Totals		10,691,000
Average price					$	82.70

At December 31, 2008, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which were designated as hedges.


Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2009		1,170,000		13,000	$	80.51
Second Quarter 2009		1,183,000		13,000		80.51
Third Quarter 2009		1,196,000		13,000		80.51
Fourth Quarter 2009		1,196,000		13,000		80.51
Calendar Year 2010		4,745,000		13,000		80.41
Calendar Year 2011		2,371,000		6,496		90.58

Totals		11,861,000
Average price					$	82.48

Gasoline Swap Contracts

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


Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2009		864,500		9,500	$	73.83
Third Quarter 2009		874,000		9,500		73.83
Fourth Quarter 2009		874,000		9,500		73.83
Calendar Year 2010		2,555,000		7,000		75.28
Calendar Year 2011		638,000		1,748		83.42

Totals		5,805,500
Average price					$	75.52

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


	Barrels
Gasoline Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Second Quarter 2009		455,000		5,000	$	60.53
Third Quarter 2009		460,000		5,000		60.53
Fourth Quarter 2009		460,000		5,000		60.53
Calendar Year 2010		547,500		1,500		58.42

Totals		1,922,500
Average price					$	59.93

At December 31, 2008, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which were designated as hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2009		855,000		9,500	$	73.83
Second Quarter 2009		864,500		9,500		73.83
Third Quarter 2009		874,000		9,500		73.83
Fourth Quarter 2009		874,000		9,500		73.83
Calendar Year 2010		2,555,000		7,000		75.28
Calendar Year 2011		638,000		1,748		83.42

Totals		6,660,500
Average price					$	75.30

At December 31, 2008, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which were designated as hedges.


	Barrels
Gasoline Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 2009		450,000		5,000	$	60.53
Second Quarter 2009		455,000		5,000		60.53
Third Quarter 2009		460,000		5,000		60.53
Fourth Quarter 2009		460,000		5,000		60.53

Totals		1,825,000
Average price					$	60.53

Jet Fuel Put Spread Contracts

At March 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)
January 2011		216,500		6,984	$	4.00	$	6.00
February 2011		197,000		7,036		4.00		6.00
March 2011		216,500		6,984		4.00		6.00

Totals		630,000
Average price					$	4.00	$	6.00

Natural Gas Swap Contracts

Natural gas purchases comprise a significant component of the Company’s cost of sales, therefore, changes in the price of natural gas also significantly affect its profitability and cash flows. The Company utilizes swap contracts to manage natural gas price risk and volatility of cash flows. Certain of these swap contracts are designated as cash flow hedges of the future purchase of natural gas. The Company’s policy is generally to enter into natural gas derivative contracts to hedge approximately 50% or more of its upcoming fall and winter months’ anticipated natural gas requirement for a period no greater than three years forward. At March 31, 2009, the Company had no natural gas swaps outstanding as the current hedging period just ended. The Company anticipates adding natural gas derivatives throughout the summer months to reach its desired hedge levels.

At December 31, 2008, the Company had the following derivatives related to natural gas purchases, of which 90,000 MMBtus were designated as hedges.


Natural Gas Swap Contracts by Expiration Dates	MMBtus		$/MMBtu
First Quarter 2009		330,000	$	10.38

Totals		330,000
Average price			$	10.38

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. 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 has 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 on derivative instruments in the unaudited condensed consolidated statements of operations. In the first quarter of 2008, the Company fixed its unrealized loss on this interest rate swap derivative instrument by entering into an offsetting interest rate swap which is not designated as a cash flow hedge.

8. Fair Value of Financial Instruments

The Company’s financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and indebtedness. The carrying value 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 in accordance with SFAS No. 157,Fair Value Measurements. The fair value of the Company’s senior secured first lien term loan was $285,643 and $305,084 at March 31, 2009 and December 31, 2008, respectively. The carrying value of the Company’s senior secured first lien term loan was $374,123 and $375,085 at March 31, 2009 and December 31, 2008, respectively. In addition, based upon fees charged for similar agreements, the face values of outstanding standby letters of credit approximated their fair value at March 31, 2009 and December 31, 2008.

9. Fair Value Measurements

In September 2006, the FASB issued Statement No. 157,Fair Value Measurements(“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. The Company adopted the provisions of SFAS 157 as of January 1, 2008 for financial instruments and as of January 1, 2009 for nonfinancial assets and liabilities as required by SFAS 157.

SFAS 157 establishes 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, as required by SFAS 157, prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded, and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants, and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.

As of March 31, 2009, 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, 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. The fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, natural gas and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the company obtains this data through surveying its counterparties and performing various analytical tests to validate the data. The Company determines the fair value of its crude oil option contracts utilizing a standard option pricing model based on inputs that can be derived from information available in publicly quoted markets, or are quoted by counterparties to these contracts. In situations where the Company obtains inputs via quotes from its counterparties, it verifies the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. The Company also includes an adjustment for non-performance risk in the recognized measure of fair value of all of the Company’s derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When the Company is in a net asset position, it uses its counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. The Company uses its own peer group’s estimated CDS when it is in a net liability position. As a result of applying the applicable CDS, at March 31, 2009, the Company’s asset was reduced by approximately $7,054 and its liability was reduced by $822. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for gasoline and diesel, the Company has categorized these derivative instruments as Level 3. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds.

The Company’s investments associated with its Pension Plan consist of mutual funds that are publicly traded and for which market prices are readily available, thus these investments are categorized as Level 1.

The Company’s assets measured at fair value on a recurring basis subject to the disclosure requirements of SFAS 157 at March 31, 2009 were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		77,493			77,493
Diesel swaps		—		—		120,322			120,322
Natural gas swaps		—		—		—			—
Crude oil options		—		—		255			255
Jet fuel options		—		—		403			403
Pension plan investments		12,018		—		—			12,018

Total assets at fair value	$	12,018	$	—	$	198,473		$	210,491

Liabilities:
Crude oil swaps	$	—	$	—	$	(111,680	)	$	(111,680	)
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Natural gas swaps		—		—		—			—
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(5,837	)		(5,837	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(117,517	)	$	(117,517	)

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the three months ended March 31, 2009:


	Derivative
	Instruments, Net
Fair value at January 1, 2009	$	55,372
Realized losses		8,470
Unrealized gains		26,496
Comprehensive income (loss)		(4,959	)
Purchases, issuances and settlements		(4,423	)
Transfers in (out) of Level 3		—

Fair value at March 31, 2009	$	80,956

Total gains or losses included in net income (loss) attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of March 31, 2009	$	39,739

All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges as defined in SFAS 133, are included in sales for gasoline and diesel 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, as defined in SFAS 133, are recorded in earnings immediately in unrealized gain 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 loss on derivative instruments. See Note 7 for further information on SFAS 133 and hedging.

10. Partners’ Capital

Calumet’s distribution policy is as defined in its partnership agreement. For the three months ended March 31, 2009 and 2008, Calumet made distributions of $14,818 and $21,738, respectively, to its partners.

11. Comprehensive Income (Loss)

Comprehensive income (loss) for the Company includes the change in fair value of cash flow hedges that has not been reclassified to net income (loss). Comprehensive income (loss) for the three months ended March 31, 2009 and 2008 was as follows:


	Three Months Ended March 31,
	2009			2008
Net income (loss)	$	75,638		$	(3,392	)
Cash flow hedge (gain) loss reclassified to net income (loss) upon settlement		(1,311	)		678
Gain in fair value of cash flow hedges		(20,072	)		(55,582	)
Minimum pension liability adjustment		94			—

Total comprehensive income (loss)	$	54,349		$	(58,296	)

12. Unit-Based Compensation

The Company’s general partner adopted a Long-Term Incentive Plan (the “Plan”) on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Plan provides for the grant of restricted units, phantom units, unit options, substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards under the Plan. The Plan is administered by the compensation committee of the Company’s general partner’s board of directors.

On December 28, 2007 and December 30, 2008, non-employee directors of our general partner were granted phantom units under the terms of the Plan as part of their director compensation package related to fiscal years 2007 and 2008, respectively. These phantom units have a four year service period, beginning on January 1, with one quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant. The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and selling, general and administrative expenses in the unaudited condensed consolidated statements of operations using the straight-line method over the four year vesting period, as it expects these units to fully vest.

On January 22, 2009, the board of directors of the Company’s general partner approved discretionary contributions to participant accounts for certain directors and employees in the form of phantom units under the Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan. The phantom unit awards vest in one-quarter increments over a four year service period, subject to early vesting on a change in control or upon termination without cause or due to death. These phantom units also carry DERs from the date of grant.

A summary of the Company’s nonvested phantom units as of March 31, 2009 and the changes during the three months ended March 31, 2009 is presented below:


			Weighted Average
			Grant Date
Nonvested Phantom Units	Grant		Fair Value
Nonvested at December 31, 2008		27,708	$	12.91
Granted		30,051		11.54
Vested		—		—
Forfeited		—		—

Nonvested at March 31, 2009		57,759	$	12.20

For the three months ended March 31, 2009 and 2008, compensation expense of $55 and $30, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. As of March 31, 2009 and 2008, there was a total of $638 and $313 of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately two years.

13. Employee Benefit Plans

The components of net periodic pension and other post retirement benefits cost for the three months ended March 31, 2009 and 2008 were as follows:


	Three Months Ended March 31,
Pension Benefits	2009			2008
Service cost	$	63		$	354
Interest cost		332			348
Expected return on assets		(187	)		(336	)
Gain (Loss)		95			—

Net periodic benefit cost	$	303		$	366


	Three Months Ended March 31,
Other Post Retirement Employee Benefits	2009			2008
Service cost	$	2		$	3
Interest cost		11			13
Expected return on assets		—			—
Gain (Loss)		(1	)		—

Net periodic benefit cost	$	12		$	16

During each of the three months ended March 31, 2009 and 2008, the Company made no contributions to its Pension Plan and other post retirement employee benefit plans, respectively, and expects to make no contributions in 2009.

14. Transactions with Related Parties

In addition to our Legacy Resources Co., L.P. agreement covering crude oil purchases for its Princeton refinery, in January 2009, the Company entered into a Master Crude Oil Purchase and Sale Agreement (the “Agreement”) with Legacy Resources Co., L.P. (“Legacy”) to begin purchasing certain of its crude oil requirements for its Shreveport refinery utilizing a market-based pricing mechanism from Legacy. Legacy is owned in part by one of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and president, F. William Grube, and Jennifer G. Straumins, the Company’s senior vice president. The volume of crude purchased under this Agreement fluctuates based on the volume of crude needed by the Shreveport refinery and can range from zero to 15,000 barrels per day. During the three months ended March 31, 2009, the Company had crude oil purchases of $58,787 from Legacy. Accounts payable to Legacy at March 31, 2009 were $27,966.

15. Segments and Related Information

a. Segment Reporting

Under the provisions of SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information, the Company has two reportable segments: Specialty Products and Fuel Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes and asphalt and other by-products. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The Fuel Products segment produces a variety of fuel and fuel-related products including gasoline, diesel and jet fuel. Because of their similar economic characteristics, certain operations have been aggregated for segment reporting purposes.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies in the notes to consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 except that the Company evaluates segment performance based on income from operations. The Company accounts for intersegment sales and transfers at cost plus a specified mark-up. Reportable segment information is as follows:


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

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

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

Net income											75,638

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


	Specialty			Fuel		Combined					Consolidated
Three Months Ended March 31, 2008	Products			Products		Segments		Eliminations			Total
Sales:
External customers	$	378,479		$	216,244	$	594,723	$	—		$	594,723
Intersegment sales		257,102			11,051		268,153		(268,153	)		—

Total sales	$	635,581		$	227,295	$	862,876	$	(268,153	)	$	594,723

Depreciation and amortization		11,680			—		11,680		—			11,680
Income from operations		(9,059	)		10,503		1,444		—			1,444
Reconciling items to net loss:
Interest expense												(5,166	)
Debt extinguishment costs												(526	)
Gain on derivative instruments												693
Other												171
Income tax expense												(8	)

Net loss											$	(3,392	)

Capital expenditures	$	90,274		$	—	$	90,274	$	—		$	90,274


	March 31, 2009			December 31, 2008
Segment assets:
Specialty products	$	2,215,912		$	2,208,741
Fuel products		1,545,736			1,483,457

Combined segments		3,761,648			3,692,198
Eliminations		(2,658,666	)		(2,611,136	)

Total assets	$	1,102,982		$	1,081,062

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three months ended March 31, 2009 and 2008. All of the Company’s long-lived assets are domestically located.

c. Product Information

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


	Three Months Ended March 31,
	2009		2008
Specialty products:
Lubricating oils	$	118,316	$	193,922
Solvents		54,487		112,821
Waxes		22,409		34,155
Fuels		2,659		12,120
Asphalt and other by-products		19,101		25,461

Total	$	216,972	$	378,479

Fuel products:
Gasoline		74,855		91,229
Diesel		81,657		82,273
Jet fuel		39,214		39,909
By-products		1,566		2,833

Total	$	197,292	$	216,244

Consolidated sales	$	414,264	$	594,723

d. Major Customers

During the three months ended March 31, 2009, the Company had no customer that represented 10% or greater of consolidated sales. During the three months ended March 31, 2008, the Company had one customer, Murphy Oil U.S.A., which represented approximately 11% of consolidated sales. No other customer represented 10% or greater of consolidated sales in the three months ended March 31, 2008.

16. Subsequent Events

On April 16, 2009, the Company declared a quarterly cash distribution of $0.45 per unit on all outstanding units, or $14,813, for the quarter ended March 31, 2009. The distribution will be paid on May 15, 2009 to unitholders of record as of the close of business on May 5, 2009. This quarterly distribution of $0.45 per unit equates to $1.80 per unit, or $59,252 on an annualized basis.

On April 20, 2009, the Company entered into Amendment No. 2 to its Crude Oil Supply Agreement with Legacy Resources Co., L.P., a related party (the “Amendment”). The Amendment, effective April 1, 2009, modifies the market-based pricing mechanism established in the Crude Oil Supply Agreement under which Legacy supplies the Partnership’s Princeton, Louisiana refinery with all of its crude oil requirements on a just in time basis.

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

The historical consolidated financial statements included in this Quarterly Report on Form 10-Q reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet”). The following discussion analyzes the financial condition and results of operations of Calumet for the three months ended March 31, 2009 and 2008. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Calumet in conjunction with the historical unaudited condensed consolidated financial statements and notes of Calumet included elsewhere in this Quarterly Report on Form 10-Q.

Overview

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We own plants located in Princeton, Louisiana, Cotton Valley, Louisiana, Shreveport, Louisiana, Karns City, Pennsylvania, and Dickinson, Texas, 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 our Princeton and Cotton Valley refineries and our Karns City facility are included in our specialty products segment. For the three months ended March 31, 2009, approximately 75.8% of our gross profit was generated from our specialty products segment and approximately 24.2% of our gross profit was generated from our fuel products segment.

Refining Industry Dynamics

The overall refining industry and, specifically, the specialty petroleum products refining industry experienced a continuation of sales price declines during the first quarter of 2009 as pricing adjusted downward due to the lower price of crude oil. The overall volatility in crude oil prices was much lower in the first quarter of 2009, ranging from a low of approximately $34 per barrel to a high of approximately $54 per barrel, as compared to the significant volatility during 2008 where crude oil prices ranged from a low of approximately $42 per barrel to a high of approximately $145 per barrel. This reduction in crude oil volatility has contributed generally to lower overall volatility in cash flows, specialty products gross profit and hedging gains and losses; however, reductions in prices have led to lower gross profit per barrel of product for most refiners, including Calumet. Lower demand for fuel products due to the overall weakness in the economy has led to reduced crack spreads for refiners as well. Most refiners have seen an overall reduction in demand for their products due to the weakness in the overall economic environment, especially demand for products closely tied to the automotive and construction industries. Given these factors, upcoming quarters will likely continue to be challenging for refiners, including specialty products refiners like us.

Calumet seeks to differentiate itself from its competitors, especially in this challenging economic environment, through continued focus on a wide range of specialty products sold in many different industries and enhanced operations, including continued increases in throughput rates at our recently expanded Shreveport refinery. Despite the continuing economic weakness during the first quarter of 2009, we were able to pay approximately $14.8 million in distributions to our unitholders, continued to maintain compliance with the financial covenants of our credit agreements and improved our liquidity by reducing outstanding borrowings under our revolving credit facility by approximately $9.6 million.

Acquisition and Refinery Expansion

On January 3, 2008, we acquired Penreco, a Texas general partnership, for $269.1 million. Penreco was owned by ConocoPhillips Company and M.E. Zukerman Specialty Oil Corporation. Penreco manufactures and markets highly refined products and specialty solvents including white mineral oils, petrolatums, natural petroleum sulfonates, cable-filling compounds, refrigeration oils, food-grade compressor lubricants and gelled products. The acquisition included facilities in Karns City, Pennsylvania and Dickinson, Texas, as well as several long-term supply agreements with ConocoPhillips Company. We funded the transaction through a portion of the combined proceeds from a public equity offering and a new senior secured first lien term loan facility. For further discussion, please read “Liquidity and Capital Resources — Debt and Credit Facilities.” We believe that this acquisition provides several key long term strategic benefits, including market synergies within our solvents and lubricating oil product lines, additional operational and logistics flexibility and overhead cost reductions. The acquisition has broadened our customer base and has given the Company access to new specialty product markets.

In the second quarter of 2008 we completed a $374.0 million expansion project at our Shreveport refinery to increase aggregate crude oil throughput capacity from approximately 42,000 bpd to approximately 60,000 bpd and improve feedstock flexibility. For 2008, the Shreveport refinery had total average feedstock throughput of 37,096 bpd, which represents an increase of approximately 2,744 bpd from 2007, before completion of the Shreveport expansion project. The Shreveport refinery did not achieve the expected significant increase in feedstock throughput year over year due primarily to unscheduled downtime due to hurricane Ike and scheduled downtime in the fourth quarter to complete a three-week turnaround. In the first quarter of 2009, feedstock throughput rates at Shreveport averaged approximately 45,621 bpd, a 23.0% increase over the 2008 fiscal year average throughput rate.

Key Performance Measures

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

Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our control. We monitor these risks and enter into financial derivatives designed to mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities which do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Item 3 “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” As of March 31, 2009, we have hedged approximately 16.5 million barrels of fuel products through December 2011 at an average refining margin of $11.49 per barrel. As of March 31, 2009, we have approximately 0.4 million barrels of crude oil options through June 2009 to hedge our purchases of crude oil for specialty products production. The strike prices and types of these crude oil options vary. Please refer to Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk — Existing Commodity Derivative Instruments” 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. We seek the optimal product mix for each barrel of crude oil we refine, which we refer to as production yield, in order to maximize our gross profit and minimize lower margin by-products.

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.

Three Months Ended March 31, 2009 and 2008 Results of Operations

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


	Three Months Ended March 31,
	2009			2008
	(In bpd)
Total sales volume (1)		54,422			59,407
Total feedstock runs (2)		63,219			55,998
Facility production: (3)
Specialty products:
Lubricating oils		11,650			13,120
Solvents		8,267			8,882
Waxes		1,101			2,054
Fuels		666	��		1,487
Asphalt and other by-products		7,735			6,758

Total		29,419			32,301

Fuel products:
Gasoline		11,078			9,212
Diesel		12,750			8,367
Jet fuel		7,346			5,898
By-products		275			203

Total		31,449			23,680

Total facility production		60,868			55,981


(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 represents the barrels per day of crude oil and other feedstocks processed at our facilities and certain third-party facilities pursuant to supply and/or processing agreements. The increase in feedstock runs for the three months ended March 31, 2009 is primarily due to the completion of the Shreveport expansion project in May 2008. This increase was offset by decreases in specialty feedstock run rates in the first quarter of 2009 at other facilities due to lower overall demand for certain lubricating oils.

(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. The difference between total production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of finished products and volume loss.

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


	Three Months Ended March 31,
	2009			2008
	(In millions)
Sales	$	414.3		$	594.7
Cost of sales		335.3			559.9

Gross profit		79.0			34.8

Operating costs and expenses:
Selling, general and administrative		9.3			8.3
Transportation		15.2			23.9
Taxes other than income taxes		1.1			1.1
Other		0.4			0.1

Operating income		53.0			1.4

Other income (expense):
Interest expense		(8.6	)		(5.2	)
Debt extinguishment costs		—			(0.5	)
Realized loss on derivative instruments		(8.5	)		(2.9	)
Unrealized gain on derivative instruments		39.7			3.6
Other		0.1			0.2

Total other income (expense)		22.7			(4.8	)

Net income (loss) before income taxes		75.7			(3.4	)
Income tax expense		(0.1	)		—

Net income (loss)	$	75.6		$	(3.4	)

EBITDA	$	99.6		$	12.2

Adjusted EBITDA	$	50.1		$	14.9

Non-GAAP Financial Measures

We include in this Quarterly Report on Form 10-Q the non-GAAP financial measures EBITDA and Adjusted EBITDA, and provide reconciliations of EBITDA and Adjusted EBITDA to net income (loss) and net cash provided by operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.

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

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

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

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

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

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

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

EBITDA and Adjusted EBITDA should not be considered alternatives to net income, operating income, net cash provided by (used in) operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA and Adjusted EBITDA in the same manner. The following table presents a reconciliation of both net income (loss) to EBITDA and Adjusted EBITDA and Adjusted EBITDA and EBITDA to net cash provided by operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.


	Three Months Ended March 31,
	2009			2008
	(In millions)
Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA:
Net income (loss)	$	75.6		$	(3.4	)
Add:
Interest expense and debt extinguishment costs		8.6			5.7
Depreciation and amortization		15.3			9.9
Income tax expense		0.1			—

EBITDA	$	99.6		$	12.2

Add:
Unrealized losses (gains) from mark to market accounting for hedging activities	$	(46.4	)	$	0.5
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		(3.1	)		2.2

Adjusted EBITDA	$	50.1		$	14.9


	Three Months Ended March 31,
	2009			2008
	(In millions)
Reconciliation of Adjusted EBITDA and EBITDA to net cash provided by operating activities:
Adjusted EBITDA	$	50.1		$	14.9
Add:
Unrealized (losses) gains from mark to market accounting for hedging activities		46.4			(0.5	)
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		3.1			(2.2	)

EBITDA	$	99.6		$	12.2

Add:
Cash interest expense and debt extinguishment costs		(7.7	)		(4.2	)
Unrealized gains on derivative instruments		(39.7	)		(3.6	)
Income taxes		(0.1	)		—
Provision for doubtful accounts		0.2			0.4
Debt extinguishment costs		—			0.5
Changes in assets and liabilities:
Accounts receivable		7.0			(16.7	)
Inventory		(30.5	)		24.5
Other current assets		4.7			6.2
Derivative activity		(7.2	)		6.0
Accounts payable		2.8			32.9
Accrued liabilities		1.6			2.1
Other, including changes in noncurrent assets and liabilities		1.9			2.1

Net cash provided by operating activities	$	32.6		$	62.4

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

Sales. Sales decreased $180.5 million, or 30.3%, to $414.3 million in the three months ended March 31, 2009 from $594.7 million in the three months ended March 31, 2008. Sales for each of our principal product categories in these periods were as follows:


	Three Months Ended March 31,
	2009		2008		% Change
	(Dollars in millions)
Sales by segment:
Specialty products:
Lubricating oils	$	118.3	$	193.9		(39.0	)%
Solvents		54.5		112.8		(51.7	)%
Waxes		22.4		34.2		(34.4	)%
Fuels (1)		2.7		12.1		(78.1	)%
Asphalt and by-products (2)		19.1		25.5		(25.0	)%

Total specialty products	$	217.0	$	378.5		(42.7	)%

Total specialty products sales volume (in barrels)		2,213,000		2,920,000		(24.2	)%
Fuel products:
Gasoline	$	74.9	$	91.2		(18.0	)%
Diesel		81.7		82.3		(0.8	)%
Jet fuel		39.2		39.9		(1.7	)%
By-products (3)		1.5		2.8		(44.7	)%

Total fuel products	$	197.3	$	216.2		(8.8	)%

Total fuel products sales volume (in barrels)		2,685,000		2,486,000		8.0	%
Total sales	$	414.3	$	594.7		(30.3	)%

Total sales volume (in barrels)		4,898,000		5,406,000		(9.4	)%


(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.

This $180.5 million decrease in sales resulted from a $161.5 million decrease in sales in the specialty products segment and a $19.0 million decrease in sales in the fuel products segment.

Specialty products segment sales for the three months ended March 31, 2009 decreased $161.5 million, or 42.7%, as a result of a 24.2% decrease in volumes sold, from approximately 2.9 million barrels in first quarter of 2008 to approximately 2.2 million barrels in the first quarter of 2009 primarily due to lower sales of lubricating oils, solvents and waxes from all facilities as a result of reduced demand. The demand reductions impacting our sales volumes were not consistent among all products as certain lubricating oils, solvents and waxes continued to sell at historical rates. Partially offsetting the reduced sales volume in the above categories were increased sales of asphalt and other by-products as a result of the Shreveport refinery expansion completed in May 2008. Specialty products segment sales were also negatively affected by a 25.1% decrease in the average selling price per barrel of specialty products compared to the prior period due to price decreases in all specialty products categories, except waxes. The sales price decreases were in response to the falling cost of crude oil experienced late in 2008. The average cost of crude oil per barrel decreased 58.1% from the first quarter of 2008 to the first quarter of 2009.

Fuel products segment sales for the three months ended March 31, 2009 decreased $19.0 million, or 8.8%, due to a 50.5% decrease in the average selling price per barrel as compared to the first quarter of 2008. This decrease compares to a 58.8% decrease in the average cost of crude oil per barrel over the first quarter of 2008. The decreased sales price per barrel was a result of decreases in all fuel products as prices decreased in relation to the decrease in the price of crude oil. The decrease in sales prices was not as high as the decrease in the average cost of crude oil due primarily to a product mix change to more diesel and jet fuel and less gasoline compared to the first quarter of 2008 and increased throughput of sour crude oil at Shreveport after the refinery expansion was completed, which lowered our feedstock costs. Our Shreveport refinery has the ability to switch portions of its production between diesel and other fuel and specialty products to allow it to take advantage of the most advantageous markets. The decreased sales prices were offset by an 8.0% increase in sales volume and a $111.0 million increase 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 $44.1 million, or 126.7%, to $79.0 million for the three months ended March 31, 2009 from $34.8 million for the three months ended March 31, 2008. Gross profit for our specialty products and fuel products segments were as follows:


	Three Months Ended March 31,
	2009			2008			% Change
	(Dollars in millions)
Gross profit by segment:
Specialty products	$	59.8		$	22.3			167.9	%
Percentage of sales		27.6	%		5.9	%
Fuel products	$	19.2		$	12.5			53.2	%
Percentage of sales		9.7	%		5.8	%
Total gross profit	$	79.0		$	34.8			126.7	%
Percentage of sales		19.1	%		5.9	%

This $44.1 million increase in total gross profit includes an increase in gross profit of $37.5 million in the specialty products segment and a $6.6 million increase in gross profit in the fuel products segment.

The increase in specialty products segment gross profit was primarily due to sales prices falling only 25.1% while the average cost of crude oil fell 58.1% and abnormally low profit margins recognized in the first quarter of 2008 due to rapidly rising crude oil costs in that period. In 2009 we were able to maintain sales prices on certain products during the period despite the reduced price of crude oil. Offsetting this improvement in gross profit was a reduction in sales volume of 24.2% as discussed above and a reduction in derivative gains of $5.9 million related to crude oil hedging. Additionally, in the first quarter of 2009 we settled derivative contracts economically hedging crude oil for specialty products production and recognized a net loss of $2.0 million which is recorded as a $14.3 million realized loss on derivative instruments and a $12.3 million unrealized gain on derivative instruments in our unaudited condensed consolidated statements of operations as discussed below.

Fuel products segment gross profit was positively impacted by an 8.0% increase in fuel products sales volume as discussed above and the average selling price per barrel of our fuel products falling by 50.5% while the average cost of crude oil cost fell by 58.8% due to the change in product mix to more diesel and jet fuel and increased throughput of cheaper sour crude oil. The product mix change and sour crude oil impacts are the result of our Shreveport refinery expansion completed in May 2008. In addition, derivative gains on our fuel products hedges increased $10.0 million in the first quarter of 2009 compared to the first quarter of 2008.

Selling, general and administrative. Selling, general and administrative expenses increased $1.1 million, or 13.0%, to $9.3 million in the three months ended March 31, 2009 from $8.3 million in the three months ended March 31, 2008. This increase is primarily due to additional accrued incentive compensation costs in the three months ended March 31, 2009 as compared to the three months ended March 31, 2008.

Transportation. Transportation expenses decreased $8.7 million, or 36.5%, to $15.2 million in the three months ended March 31, 2009 from $23.9 million in the three months ended March 31, 2008. This decrease is primarily related to a reduction in transportation expenses due to lower lubricating oils, solvents and waxes sales volumes.

Interest expense. Interest expense increased $3.5 million, or 67.3%, to $8.6 million in the three months ended March 31, 2009 from $5.2 million in the three months ended March 31, 2008. This increase was primarily due to a decrease in capitalized interest as a result of the completion of the Shreveport refinery expansion project, combined with increased borrowings on our revolving credit facility. These increases were partially offset by lower interest rates on our revolving and term loan credit facilities.

Realized loss on derivative instruments. Realized loss on derivative instruments increased $5.6 million to $8.5 million in the three months ended March 31, 2009 from $2.9 million in the three months ended March 31, 2008. This increased loss was primarily due to additional losses incurred due to falling crude oil prices on specialty segment crude oil derivatives used to economically hedge our exposure to crude oil price risk. Partially offsetting these realized losses were realized gains on our crack spread derivatives that were executed to economically lock in gains on a portion of our fuel products segment derivative hedging activity.

Unrealized gain on derivative instruments. Unrealized gain on derivative instruments increased $36.2 million, to $39.7 million in the three months ended March 31, 2009 from a gain of $3.6 million in the three months ended March 31, 2008. This increased gain is primarily due to increased unrealized gains 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 gain ineffectiveness on both our fuel products and crude oil hedges. The unrealized gain or loss on derivatives at a given point in time is not necessarily indicative of the results realized when such contracts are settled.

Liquidity and Capital Resources

Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions and debt service. We expect that our principal uses of cash in the future will be for working capital as we continue to increase our throughput rate at the Shreveport refinery, distributions to our limited partners and general partner, debt service, and capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and cause us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs. Given the current credit environment and our continued efforts to reduce leverage to ensure continued covenant compliance under our credit facilities, we do not anticipate completing any significant acquisitions, internal growth projects or replacement and environmental capital expenditures which would cause total spending in these areas to exceed $25.0 million during 2009. With the uncertain status of the credit and equity markets, 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 change 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.

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


	Three Months Ended March 31,
	2009			2008
	(In millions)
Net cash provided by operating activities	$	32.6		$	62.4
Net cash used in investing activities	$	(4.9	)	$	(359.2	)
Net cash provided by (used in) financing activities	$	(27.7	)	$	296.8

Operating Activities. Operating activities provided $32.6 million in cash during the three months ended March 31, 2009 compared to $62.4 million during the three months ended March 31, 2008. The decrease in cash provided by operating activities during the three months ended March 31, 2009 was primarily due to increased inventory as a result of the increased production levels of the Shreveport refinery in addition to a reduction in accounts payable primarily from lower crude oil prices. This reduction was partially offset by increased net income.

Investing Activities. Cash used in investing activities decreased to $4.9 million during the three months ended March 31, 2009 compared to $359.2 million during the three months ended March 31, 2008. This decrease was primarily due to the acquisition of Penreco for $269.1 million and capital expenditures related to the Shreveport expansion in the first quarter of 2008 with no comparable uses of cash in the first quarter of 2009.

Financing Activities. Financing activities used cash of $27.7 million during the three months ended March 31, 2009 as compared to $296.8 million provided during the three months ended March 31, 2008. This change was primarily due to the net cash proceeds of approximately $325.5 million received from the term loan facility which closed on January 3, 2008 with no comparable transaction in 2009.

On April 16, 2009, the Company declared a quarterly cash distribution of $0.45 per unit on all outstanding units, or $14.8 million, for the quarter ended March 31, 2009. The distribution will be paid on May 15, 2009 to unitholders of record as of the close of business on May 5, 2009. This quarterly distribution of $0.45 per unit equates to $1.80 per unit, or $59.3 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 and to expand existing facilities, such as projects that increase operating capacity. Replacement capital expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.

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


	Three Months Ended March 31,
	2009		2008
	(In millions)
Capital improvement expenditures	$	1.9	$	88.8
Replacement capital expenditures		2.4		0.8
Environmental expenditures		0.6		0.7

Total	$	4.9	$	90.3

We anticipate that future capital expenditure requirements will be provided through cash provided by operations and available borrowings under our revolving credit facility unless the debt and equity capital markets improve in the near term. Management expects to invest up to $5 million in expenditures at its various locations during the remainder of 2009 to complete the majority of our items in construction in progress related to improving our product mix or operating cost leverage. In addition, management estimates its replacement and environmental capital expenditures to be approximately $3.5 million per quarter. We will continue to maintain a conservative capital expenditures budget until additional improvements in our liquidity and debt covenant compliance performance metrics have been achieved.

Debt and Credit Facilities

As of March 31, 2009, 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 number of lenders in our facility has been reduced from ten due to an acquisition. If further acquisitions occur, we will increase the concentration of our exposure to certain financial institutions. Currently, the largest member of our bank group provides a commitment for $87.5 million. The smallest commitment is $15.0 million and the median commitment is $42.5 million. In the event of a default by one of the lenders in the syndicate, the total commitments under the revolving credit facility would be reduced by the defaulting lenders’ commitment, unless another lender or a combination of lenders increase their commitments to replace the defaulting lender. In the alternative, the revolving credit facility also permits us to replace a defaulting lender. Although we do not expect any current lenders to default under the revolving credit facility, we can provide no assurances. Our borrowing base at March 31, 2009 was $182.3 million, thus, we would have to experience defaults in commitments totaling $192.7 million from our lender group before it would impact our liquidity as of March 31, 2009. This would require at least three of our nine lenders to default in order for it to impact our current liquidity position under the revolving credit facility.

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. This margin is currently at 50 basis points for prime and 200 basis points for LIBOR; however, it fluctuates based on quarterly measurement of our Consolidated Leverage Ratio as discussed below and will be reduced to 25 basis points for prime and 175 basis points for LIBOR based on the March 31, 2009 calculated Consolidated Leverage Ratio. The lenders under our revolving credit facility have a first priority lien on our cash, accounts receivable and inventory and a second priority lien on our fixed assets. The revolving credit facility matures in January 2013. On March 31, 2009, we had availability on our revolving credit facility of $69.2 million, based upon a $182.3 million borrowing base, $20.1 million in outstanding standby letters of credit, and outstanding borrowings of $93.0 million under the revolving credit facility. The improvement in our availability of $17.3 million from December 31, 2008 is due to cash generated from operations, offset by distributions to partners, debt service requirements and a net increase in working capital primarily due to increased inventory levels. We believe that we have sufficient cash flow from operations and borrowing capacity to meet our financial commitments, minimum quarterly distributions to unit holders, debt service obligations, contingencies and anticipated capital expenditures. 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 or a significant, sustained decline 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 financial covenants under our credit facilities. Further substantial declines in crude oil prices, if sustained, may materially diminish our borrowing base which is based, in part, on the value of our crude oil inventory and could result in a material reduction in our borrowing capacity under our revolving credit facility.

The term loan facility, fully drawn at $385.0 million on January 3, 2008, bears interest at a rate of LIBOR plus 400 basis points or prime plus 300 basis points, at our option. Management has historically kept the outstanding balance on a LIBOR basis, however, that decision is evaluated every three months to determine if a portion is to be converted back to the prime rate. Each lender under this facility has a first priority lien on our fixed assets and a second priority lien on our cash, accounts receivable and inventory. Our term loan facility matures in January 2015. We are required to make mandatory repayments of approximately $1.0 million at the end of each fiscal quarter, beginning with the fiscal quarter ended March 31, 2008 and ending with the fiscal quarter ending September 30, 2014, with the remaining balance due at maturity on January 3, 2015.

Our letter of credit facility to support crack spread hedging bears interest at a rate of 4.0% and is secured by a first priority lien on our fixed assets. We have issued a letter of credit in the amount of $50.0 million, the full amount available under this letter of credit facility, to one counterparty. As long as this first priority lien is in effect and such counterparty remains the beneficiary of the $50.0 million letter of credit,

we will have no obligation to post additional cash, letters of credit or other collateral with such counterparty to provide additional credit support for a mutually-agreed maximum volume of executed crack spread hedges. In the event such counterparty’s exposure to us exceeds $100.0 million, we would be required to post additional credit support to enter into additional crack spread hedges up to the aforementioned maximum volume. In addition, we have other crack spread hedges in place with other approved counterparties under the letter of credit facility whose credit exposure to us is also secured by a first priority lien on our fixed assets.

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 have historically been obligated to comply with certain financial covenants requiring us to maintain a Consolidated Leverage Ratio of no more than 4.0 to 1 and a Consolidated Interest Coverage Ratio of no less than 2.50 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 agreement) and Available Liquidity (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). For the fiscal quarter ended June 30, 2009 and all future quarters, we are obligated to comply with 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. 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. available liquidity is a measure used under our revolving credit facility and is the sum of the cash and borrowing capacity that we have as of a given date. 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 Available Liquidity 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 the Company’s credit agreements is tested quarterly based upon performance over the most recent four fiscal quarters and as of March 31, 2009 the Company was in compliance with all financial covenants under its credit agreements and achieved improvement in our financial covenant performance metrics compared to the fourth quarter of 2008. The Company’s ability to maintain compliance with these financial covenants in the quarter ended March 31, 2009 was enhanced by improved Adjusted EBITDA (as defined in the credit agreements) for the first quarter of 2009 as compared to the first quarter of 2008 and a reduction in our Consolidated Indebtedness of approximately $10.5 million at March 31, 2009 compared to December 31, 2008.

While assurances cannot be made regarding our future compliance with these covenants and being cognizant of the general uncertain economic environment, we anticipate that we will maintain compliance with such financial covenants and improve our liquidity.

Failure to achieve our anticipated results may result in a breach of certain of the financial covenants contained in our credit agreements. If this occurs, we will enter into discussions with our lenders to either modify the terms of the existing credit facilities or obtain waivers of non-compliance with such covenants. There can be no assurances of the timing of the receipt of any such modification or waiver, the term or costs associated therewith or our ultimate ability to obtain the relief sought. Our failure to obtain a waiver of non-compliance with certain of the financial covenants or otherwise amend the credit facilities would constitute an event of default under our credit facilities and would permit the lenders to pursue remedies. These remedies could include acceleration of maturity under our credit facilities and limitations on, or the elimination of, our ability to make distributions to our unitholders. If our lenders accelerate maturity under our credit facilities, a significant portion of our indebtedness may become due and payable immediately. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. If we are unable to make these accelerated payments, our lenders could seek to foreclose on our assets.

In addition, our credit agreements contain various covenants that limit our ability, among other things, to: incur indebtedness; grant liens; make certain acquisitions and investments; make capital expenditures above specified amounts; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; enter into a merger, consolidation or sale of assets; and cease our refining margin hedging program (our lenders have required us to obtain and maintain derivative contracts for fuel products margins in our fuel products segment for a rolling period of 1 to 12 months for at least 60% and no more than 90% of our anticipated fuels production, and for a rolling 13-24 months forward for at least 50% and no more than 90% of our anticipated fuels production).

If an event of default exists under our credit agreements, the lenders will be able to accelerate the maturity of the credit facilities and exercise other rights and remedies. An event of default is defined as nonpayment of principal interest, fees or other amounts; failure of any representation or warranty to be true and correct when made or confirmed; failure to perform or observe covenants in the credit agreement or other loan documents, subject to certain grace periods; payment defaults in respect of other indebtedness; cross-defaults in other indebtedness if the effect of such default is to cause the acceleration of such indebtedness under any material agreement if such default could have a material adverse effect on us; bankruptcy or insolvency events; monetary judgment defaults; asserted invalidity of the loan documentation; and a change of control in us. We believe we are in compliance with all debt covenants and have adequate liquidity to conduct our business as of March 31, 2009.

Contractual Obligations and Commercial Commitments

A summary of our total contractual cash obligations as of March 31, 2009, is as follows:


			Payments Due by Period
			Less Than		1-3		3-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Long-term debt obligations	$	469,474	$	3,590	$	9,054	$	100,995	$	355,835
Interest on long-term debt at contractual rates		140,620		26,730		52,305		45,727		15,858
Capital lease obligations		2,381		928		1,289		164		—
Operating lease obligations (1)		41,941		12,193		16,879		9,752		3,117
Letters of credit (2)		70,055		20,055		—		50,000		—
Purchase commitments (3)		141,837		141,837		—		—		—
Pension obligations		13,000		—		8,000		5,000		—
Employment agreements (4)		680		371		309		—		—

Total obligations	$	879,988	$	205,704	$	87,836	$	211,638	$	374,810


(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 from various suppliers based on current market prices at the time of delivery.

(4)		Annual base salary compensation under the employment agreement of F. William Grube, chief executive officer and president.

In connection with the closing of the Penreco acquisition on January 3, 2008, we entered into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, ConocoPhillips is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, we are obligated to purchase $34.3 million of feedstock for the LVT unit in each of the next four years based on pricing estimates as of March 31, 2009. 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

Fair Value of Financial Instruments

In accordance with Statement of Financial Accounting Standards (SFAS) No. 133,Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138 and in May 2003 by SFAS No. 149 (collectively referred to as “SFAS 133”), the Company recognizes all derivative transactions as either assets or liabilities at fair value on the consolidated balance sheets. The Company utilized third party valuations and published market data to determine the fair value of these derivatives and thus does not directly rely on market indices. The Company performs an independent verification of the third party valuation statements to validate inputs for reasonableness and completes a comparison of implied crack spread mark-to-market valuations among our counterparties.

The Company’s derivative instruments, consisting of derivative assets and derivative liabilities of $86.8 million and $5.8 million, respectively, as of March 31, 2009, are valued at Level 1, Level 2, and Level 3 fair value measurement under SFAS No. 157,Fair Value Measurements, depending upon the degree by which inputs are observable. The Company’s derivative instruments are the only assets and liabilities measured at fair value as of March 31, 2009. The Company recorded unrealized gains of derivative instruments and realized losses on derivative instruments of $39.7 million and $8.5 million, respectively, on our derivative instruments in the three months ended March 31, 2009. The increase in the fair market value of our outstanding derivative instruments from a net asset of $55.4 million as of December 31, 2008 to a net asset of $81.0 million as of March 31, 2009 was primarily due to decreases in the forward market values of fuel products margins, or cracks spreads, relative to our hedged fuel products margins. The Company believes that the fair values of our derivative instruments may diverge materially from the amounts currently recorded to fair value at settlement due to the volatility of commodity prices.

Holding all other variables constant, we expect a $1 increase in these commodity prices would change our recorded mark-to-market valuation by the following amounts based upon the volume hedged as of March 31, 2009:


	In millions
Crude oil swaps	$	(16.5	)
Diesel swaps	$	10.7
Gasoline swaps	$	5.8
Crude oil collars	$	0.4
Jet collars	$	0.6

The Company enters into crude oil, gasoline, diesel and jet fuel hedges to hedge an implied crack spread. Therefore, any increase in crude oil swap mark-to-market valuation due to changes in commodity prices will generally be accompanied by a decrease in gasoline, diesel and jet fuel swap mark-to-market valuation.

Recent Accounting Pronouncements

In March 2008, the FASB issued FASB Statement No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133(“SFAS 161”). SFAS 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS 133 have been applied, and the impact that hedges have on an entity’s financial position, results of operations, and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company currently provides an abundance of information about its hedging activities and use of derivatives in its quarterly and annual filings with the SEC, including many of the disclosures contained within SFAS 161. The Company adopted SFAS 161 on January 1, 2009 and applied the various disclosures as required by SFAS 161. SFAS 161 did not have a material affect on the Company’s financial position, results of operations or cash flows.

In March 2008, FASB issued Emerging Issues Task Force Issue No. 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships(“EITF 07-4”). EITF 07-4 requires master limited partnerships to treat incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to pay IDRs. EITF 07-4 requires that undistributed earnings be allocated to the partnership interests based on the allocation of earnings to capital accounts as specified in the respective partnership agreement. When distributions exceed earnings, EITF 07-4 requires that net income be reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the respective partnership agreement. EITF 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Company adopted EITF 07-4 on January 1, 2009 and applied the various disclosures as required. All prior year computations and disclosures of earnings per unit were restated in this filing for the impacts of this new EITF. EITF 07-4 did not have a material affect on our financial position, results of operations or cash flows. The impact of EITF 07-4 on our calculation of earnings per unit is as follows:


	Three Months Ended March 31, 2008, as Adjusted
	for EITF 07-4
Net income (loss)	$	(3,392	)
Less:
General partner’s interest in net income (loss)		(68	)
Subordinated unitholders interest in net income (loss)		(1,347	)

Net income (loss) available to common unitholders	$	(1,977	)


Weighted average number of common units outstanding – basic and diluted		19,166
Weighted average number of subordinated units outstanding – basic and diluted		13,066

Common and subordinated unitholders’ basic and diluted net income (loss) per unit		(0.10	)
Cash distributions declared per common and subordinated unit	$	0.63

	Three Months Ended March 31, 2008, as Previously
	Reported
Net income (loss)	$	(3,392	)
Minimum quarterly distribution to common unitholders		(8,625	)
General partner’s incentive distribution rights		—
General partner’s interest in net (income) loss		68
Common unitholders’ share of income in excess of minimum quarterly distribution		—

Subordinated unitholders’ interest in net income (loss)	$	(11,949	)

Basic and diluted net income (loss) per limited partner unit:
Common	$	0.45
Subordinated	$	(0.91	)

Weighted average limited partner common units outstanding – basic and diluted		19,166
Weighted average limited partner subordinated units outstanding – basic and diluted		13,066

Cash distributions declared per common and subordinated unit	$	0.63

In June 2008, the FASB issued FASB Staff Position EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities(FSP EITF 03-6-1). FSP EITF 03-6-1 clarifies that unvested share-based payment awards with a right to receive nonforfeitable dividends are participating securities for the purposes of applying the two-class method of calculating EPS (earnings per share). FSP EITF 03-6-1 also provides guidance on how to allocate earnings to participating securities and compute basic EPS using the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company has adopted FSP EITF 03-6-1 as of January 1, 2009 and applied it retrospectively.

In April 2008, the FASB issued FASB Staff Position No. 142-3,Determination of the Useful Life of Intangible Assets, (“FSP No. 142-3”) that amends the factors considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142,Goodwill and Other Intangible Assets(“SFAS No. 142”). FSP No. 142-3 requires a consistent approach between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of an asset under SFAS No. 141(R),Business Combinations. FSP No. 142-3 also requires enhanced disclosures when an intangible asset’s expected future cash flows are affected by an entity’s intent and/or ability to renew or extend the arrangement. FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and is applied prospectively. The Company has adopted FSP No. 142-3 and applied its various provisions as required as of January 1, 2009. The adoption of FSP No. 142-3 did not have a material affect on our financial position, results of operations or cash flows.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

Crude Oil Price Volatility

We are exposed to significant fluctuations in the price of crude oil, our principal raw material. Given the historical volatility of crude oil prices, this exposure can significantly impact product costs and gross profit. Holding all other variables constant, and excluding the impact of our current hedges, we expect a $1.00 change in the per barrel price of crude oil would change our specialty product segment cost of sales by $9.3 million and our fuel product segment cost of sales by $11.2 million based on the annualized results for the three months ended March 31, 2009.

Crude Oil Hedging Policy

Because we typically do not set prices for our specialty products in advance of our crude oil purchases, we can generally take into account the cost of crude oil in setting specialty products prices. However we are not always able to adjust our sales prices as quickly as increases in the price of crude oil. Due to this lack of correlation between our specialty products sales prices and crude oil prices in periods of high volatility, we further manage our exposure to fluctuations in crude oil prices in our specialty products segment through the use of derivative instruments, which can include both swaps and options, generally executed in the over-the-counter (OTC) market. Our policy is generally to enter into crude oil derivative contracts that match our expected future cash out flows for up to 70% of our anticipated crude oil purchases related to our specialty products production. These positions generally will be short term in nature and expire within three to nine months from execution; however, we may execute derivative contracts for up to two years forward if our expected future cash flows support lengthening our position. As of March 31, 2009 we are hedged at the lower end of our guideline and at a hedge percentage of approximately 16% of forecasted specialty products production through June 30, 2009. Our fuel products sales are based on market prices at the time of sale. Accordingly, in conjunction with our fuel products hedging policy discussed below, we enter into crude oil derivative contracts related to our fuel products segment for up to five years and no more than 75% of our fuel products sales on average for each fiscal year.

Natural Gas Price Volatility

Since natural gas purchases comprise a significant component of our cost of sales, changes in the price of natural gas also significantly affect our profitability and our cash flows. Holding all other cost and revenue variables constant, and excluding the impact of our current hedges, we expect a $0.50 change per MMBtu (one million British Thermal Units) in the price of natural gas would change our cost of sales by $4.2 million based on the annualized results for the three months ended March 31, 2009.

Natural Gas Hedging Policy

We enter into derivative contracts to manage our exposure to natural gas prices. Our policy generally is to enter into natural gas swap contracts during the summer months for up to approximately 50% of our anticipated natural gas requirements for the upcoming fall and winter months with time to expiration not to exceed three years.

Fuel Products Selling Price Volatility

We are exposed to significant fluctuations in the prices of gasoline, diesel, and jet fuel. Given the historical volatility of gasoline, diesel, and jet fuel prices, this exposure can significantly impact sales and gross profit. Holding all other variables constant, and excluding the impact of our current hedges, we expect that a $1 change in the per barrel selling price of gasoline, diesel, and jet fuel would change our fuel products segment sales by $10.7 million based on the annualized results for the three months ended March 31, 2009.

Fuel Products Hedging Policy

In order to manage our exposure to changes in gasoline, diesel, and jet fuel selling prices, our policy generally is to enter into derivative contracts to hedge our fuel products sales for a period no greater than five years forward and for no more than 75% of anticipated fuels sales on average for each fiscal year, which is consistent with our crude oil purchase hedging policy for our fuel products segment discussed above. We believe this policy lessens the volatility of our cash flows. In addition, in connection with our credit facilities, our lenders require us to obtain and maintain derivative contracts to hedge our fuel products margins for a rolling period of 1 to 12 months forward for at least 60% and no more than 90% of our anticipated fuels production, and for a rolling 13 to 24 months forward for at least 50% and no more than 90% of our anticipated fuels production. As of March 31, 2009, we were over 60% and 50% hedged for the forward 12 and 24 month periods, respectively. We are currently hedging in calendar year 2011, with no positions currently in 2012 or 2013.

Interest Rate Risk

We are exposed to market risk from fluctuations in interest rates. Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates. As of March 31, 2009, we had approximately $467.1 million of variable rate debt. Holding other variables constant (such as debt levels), a one hundred basis point change in interest rates on our variable rate debt as of March 31, 2009 would be expected to have an impact on net income and cash flows of approximately $4.7 million.

We have a $375.0 million revolving credit facility as of March 31, 2009, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had borrowings of $93.0 million outstanding under this facility as of March 31, 2009, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin.

Existing Interest Rate Derivative Instruments

In 2008, the Company entered into a forward swap contract to manage interest rate risk related to its current variable rate senior secured first lien term loan, which closed January 3, 2008. The Company has hedged the future interest payments related to $150.0 million and $50.0 million 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.

Existing Commodity Derivative Instruments

Fuel Products Segment

The following tables provide information about our derivative instruments related to our fuel products segment as of March 31, 2009:


	Barrels
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Second Quarter 2009		2,047,500		22,500	$	66.26
Third Quarter 2009		2,070,000		22,500		66.26
Fourth Quarter 2009		2,070,000		22,500		66.26
Calendar Year 2010		7,300,000		20,000		67.29
Calendar Year 2011		3,009,000		8,244		76.98

Totals		16,496,500
Average price					$	68.67


Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2009		1,183,000		13,000	$	80.51
Third Quarter 2009		1,196,000		13,000		80.51
Fourth Quarter 2009		1,196,000		13,000		80.51
Calendar Year 2010		4,745,000		13,000		80.41
Calendar Year 2011		2,371,000		6,496		90.58

Totals		10,691,000
Average price					$	82.70


Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2009		864,500		9,500	$	73.83
Third Quarter 2009		874,000		9,500		73.83
Fourth Quarter 2009		874,000		9,500		73.83
Calendar Year 2010		2,555,000		7,000		75.28
Calendar Year 2011		638,000		1,748		83.42

Totals		5,805,500
Average price					$	75.52

The following table provides a summary of these derivatives and implied crack spreads for the crude oil, diesel and gasoline swaps disclosed above, all of which are designated as hedges.


	Barrels				Implied Crack
Swap Contracts by Expiration Dates	Purchased		BPD		Spread ($/Bbl)
Second Quarter 2009		2,047,500		22,500	$	11.43
Third Quarter 2009		2,070,000		22,500		11.43
Fourth Quarter 2009		2,070,000		22,500		11.43
Calendar Year 2010		7,300,000		20,000		11.32
Calendar Year 2011		3,009,000		8,244		11.99

Totals		16,496,500
Average price					$	11.48

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


Crude Oil Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Second Quarter 2009		455,000		5,000	$	62.66
Third Quarter 2009		460,000		5,000		62.66
Fourth Quarter 2009		460,000		5,000		62.66
Calendar Year 2010		547,500		1,500		58.25

Totals		1,922,500
Average price					$	61.40


	Barrels
Gasoline Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Second Quarter 2009		455,000		5,000	$	60.53
Third Quarter 2009		460,000		5,000		60.53
Fourth Quarter 2009		460,000		5,000		60.53
Calendar Year 2010		547,500		1,500		58.42

Totals		1,922,500
Average price					$	59.93

The following table provides a summary of these derivatives and implied crack spreads for the crude oil and gasoline swaps disclosed above. These trades were used to economically freeze a portion of the mark-to-market valuation gain for the above crack spread trades.


	Barrels				Implied Crack
Swap Contracts by Expiration Dates	Purchased		BPD		Spread ($/Bbl)
Second Quarter 2009		455,000		5,000		(2.13	)
Third Quarter 2009		460,000		5,000		(2.13	)
Fourth Quarter 2009		460,000		5,000		(2.13	)
Calendar 2010		547,500		1,500		0.17

Totals		1,922,500
Average price					$	(1.47	)

The above derivative instruments to purchase the crack spread have effectively locked in a gain of $9.70 per barrel on approximately 1.4 million barrels, or $13.3 million, to be recognized in 2009 and a gain of $7.82 per barrel on approximately 0.5 million barrels, or $4.3 million, to be recognized in 2010.

Jet Fuel Put Spread Contracts

At March 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)
January 2011		216,500		6,984	$	4.00	$	6.00
February 2011		197,000		7,036		4.00		6.00
March 2011		216,500		6,984		4.00		6.00

Totals		630,000
Average price					$	4.00	$	6.00

Specialty Products Segment

At March 31, 2009, the Company had the following crude oil derivative positions related to crude oil purchases in its specialty products segment, none of which are designated as hedges. At March 31, 2009, we have provided no cash collateral in credit support to our hedging counterparties.


					Average		Average		Average		Average
					Bought Put		Sold Put		Bought Call		Sold Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)		($/Bbl)
April 2009		105,000		3,500	$	33.49	$	43.49	$	53.49	$	63.49
May 2009		93,000		3,000		34.55		44.55		54.55		64.55
June 2009		30,000		1,000		34.50		44.50		54.50		64.50

Totals		228,000
Average price					$	34.06	$	44.06	$	54.06	$	64.06


					Average		Average		Average
					Bought Put		Bought Swap		Sold Call
Crude Oil Put/Swap/Call Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)
April 2009		60,000		2,000	$	41.33	$	53.55	$	63.55
May 2009		62,000		2,000		45.53		55.30		64.50
June 2009		90,000		3,000		43.47		53.42		62.83

Totals		212,000
Average price					$	43.46	$	54.01	$	63.52

At March 31, 2009, the Company had no natural gas derivatives outstanding as the current hedging period just ended. The Company anticipates adding natural gas derivatives throughout the summer months to reach its desired hedging levels.

Item 4.Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(b) Changes in Internal Controls

During the fiscal quarter covered by this report, there were no changes in our “internal control over financial reporting” (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1.Legal Proceedings

We are not a party to any material litigation. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. Please see Note 5 “Commitments and Contingencies” in Part I Item 1 “Financial Statements” for a description of our current regulatory matters related to the environment.

Item 1A.Risk Factors

Recent proposals to restrict emissions of carbon dioxide and other “greenhouse gases” could increase our costs of doing business and the costs of our products.

On April 17, 2009, EPA issued a notice of its finding and determination that emissions of carbon dioxide, methane, and other “greenhouse gases” (GHGs) presented an endangerment to human health and the environment because emissions of such gases were contributing to warming of the earth’s atmosphere. EPA’s finding and determination allows it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take EPA several years to adopt and impose regulations limiting emissions of GHGs, any limitation on emissions of GHGs from our refinery and terminal operations or from the combustion of the fuels we produce could increase our costs of doing business and/or increase the cost and reduce demand for the fuels we produce. In addition, the U.S. Congress is currently considering legislation that would impose a national cap on emissions of GHGs and would require major sources of GHG emissions to purchase “allowances” that would permit such sources to continue to emit GHGs into the atmosphere. Furthermore, such legislation could require producers of fuels to acquire allowances to offset emissions of GHGs that result from the combustion of the fuels they produce. Any such legislation, if adopted, could increase our costs of doing business and/or increase the cost and reduce demand for the fuels we produce.

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

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


					Total Number of
					Common Units		Maximum Number of
	Total Number of				Purchased as a		Common Units that
	Common Units		Average Price Paid		Part of Publicly		May Yet be
	Purchased		per Common Unit		Announced Plans		Purchased Under Plans
January 2009		—	$	—		—		—
February 2009		—		—		—		—
March 2009 (1)		10,992		9.5389		—		—

Total		10,992	$	9.5389		—		—


(1)		None of the common units were purchased pursuant to publicly announced plans or programs. The common units were purchased through a single broker in open market transactions. A total of 10,992 common units were purchased by Calumet GP, LLC, our general partner, related to the Calumet GP, LLC Long-Term Incentive Plan (the “Plan”). The Plan provides for the delivery of up to 783,960 common units to satisfy awards of phantom units, restricted units or unit options to the employees, consultants or directors of Calumet. Such units may be newly issued by Calumet or purchased in the open market. For more information on the Plan, which did not require approval by our limited partners, refer to Item 11 “Executive and Director Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation — Long-Term, Unit-Based Awards” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008.

Item 3.Defaults Upon Senior Securities

None.

Item 4.Submission of Matters to a Vote of Security Holders

None.

Item 5.Other Information

None.

Item 6.Exhibits

The following documents are filed as exhibits to this Quarterly Report on Form 10-Q:


Exhibit
Number		Description
10.1*		Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No 000-51734)).

10.2		Master Crude Oil Purchase and Sale Agreement, effective as of January 26, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on January 30, 2009 (File No 000-51734)).

10.3		Amendment No. 2 to Crude Oil Supply Agreement, dated as of April 20, 2009 and effective April 1, 2009, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on April 22, 2009 (File No 000-51734)).

10.4*		Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009 (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K filed with the Commission on March 3, 2009 (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.


*		Identifies management contract and compensatory plan arrangements.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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:	/s/ CALUMET GP, LLC
		its general partner



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

Date: May 8, 2009

Index to Exhibits


Exhibit
Number		Description
10.1*		Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the Commission on January 28, 2009 (File No 000-51734)).

10.2		Master Crude Oil Purchase and Sale Agreement, effective as of January 26, 2009, between Calumet Shreveport Fuels, LLC, customer, and Legacy Resources Co., L.P., supplier (incorporated by reference Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on January 30, 2009 (File No 000-51734)).

10.3		Amendment No. 2 to Crude Oil Supply Agreement, dated as of April 20, 2009 and effective April 1, 2009, between Calumet Lubricants Co., L.P., customer, and Legacy Resources Co., L.P., supplier (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on April 22, 2009 (File No 000-51734)).

10.4*		Amended and Restated Long-Term Incentive Plan, dated and effective January 22, 2009 (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K filed with the Commission on March 3, 2009 (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.


*		Identifies management contract and compensatory plan arrangements.

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Litigous
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Calumet Specialty Products Partners (CLMT) 10-Q2009 Q1 Quarterly report

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