Edgar Filing: Calumet Specialty Products Partners, L.P.

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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


		For the quarterly period ended September 30, 2008.


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


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

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

At October 31, 2008, the registrant had 19,166,000 common units and 13,066,000 subordinated units outstanding.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
FORM 10-Q — September 30, 2008 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		48
Item 4. Controls and Procedures		52

Part II
Item 1. Legal Proceedings		52
Item 1A. Risk Factors		52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 3. Defaults Upon Senior Securities		53
Item 4. Submission of Matters to a Vote of Security Holders		53
Item 5. Other Information		53
Item 6. Exhibits		54
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 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. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “intend,” “forecast,” “estimate,” “continue,” or other similar words. The statements regarding (i) the Shreveport refinery expansion project’s resulting increases in production levels, (ii) expected settlements with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental and regulatory liabilities, (iii) the future benefits and risks of the Penreco acquisition, (iv) future anticipated levels of inventory, (v) our anticipated levels of use of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes and (vi) future compliance with our debt covenants, as well as other matters discussed in this 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 many of which are beyond our control. When considering these forward-looking statements, unitholders should keep in mind the risk factors and other cautionary statements included in this Form 10-Q, in our Form 10-Q for the three and six months ended June 30, 2008, filed on August 11, 2008, and in our Annual Report on Form 10-K for the year ended December 31, 2007, filed on March 4, 2008. These risk factors and cautionary statements noted throughout this 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 crude oil and crack spread price fluctuations and rapid increases or decreases including the impact on our liquidity;

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

	•		risks associated with our Shreveport expansion project;

	•		difficulties in successfully integrating the operations and employees of Penreco and the timing of such integration;

	•		our ability to comply with the 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 from our suppliers and hedging counterparties;

	•		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 and other weather interference with business operations or project construction;

	•		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 statement 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 Form 10-Q to “Calumet,” “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


	September 30, 2008			December 31, 2007
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	107		$	35
Accounts receivable:
Trade		218,698			109,501
Other		438			4,496

		219,136			113,997
Inventories		89,450			107,664
Prepaid expenses and other current assets		3,017			7,588

Total current assets		311,710			229,284
Property, plant and equipment, net		666,654			442,882
Goodwill		48,336			—
Other intangible assets, net		52,915			2,460
Other noncurrent assets, net		11,875			4,231

Total assets	$	1,091,490		$	678,857

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	157,518		$	167,977
Accrued salaries, wages and benefits		10,143			2,745
Taxes payable		8,211			6,215
Other current liabilities		7,743			4,882
Current portion of long-term debt		4,842			943
Derivative liabilities		117,835			57,503

Total current liabilities		306,292			240,265
Pension and postretirement benefit obligations		4,720			—
Long-term debt, less current portion		451,295			38,948

Total liabilities		762,307			279,213
Commitments and contingencies Partners’ capital:
Common unitholders (19,166,000 units issued and outstanding)		361,669			375,925
Subordinated unitholders (13,066,000 units issued and outstanding)		34,295			43,996
General partner’s interest		17,858			19,364
Accumulated other comprehensive loss		(84,639	)		(39,641	)

Total partners’ capital		329,183			399,644

Total liabilities and partners’ capital	$	1,091,490		$	678,857

See accompanying notes to unaudited condensed consolidated financial statements.

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


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands, except per unit data)						(In thousands, except per unit data)
Sales	$	724,371		$	428,084		$	1,990,315		$	1,200,923
Cost of sales		647,397			390,209			1,817,625			1,047,542

Gross profit		76,974			37,875			172,690			153,381
Operating costs and expenses:
Selling, general and administrative		11,995			4,235			29,666			16,069
Transportation		21,656			13,218			66,685			40,835
Taxes other than income taxes		1,324			923			3,386			2,719
Other		393			2,220			957			2,562

Operating income		41,606			17,279			71,996			91,196

Other income (expense):
Interest expense		(10,670	)		(1,346	)		(24,373	)		(3,474	)
Interest income		23			290			346			1,849
Debt extinguishment costs		—			(347	)		(898	)		(347	)
Realized loss on derivative instruments		(12,621	)		(3,870	)		(12,971	)		(9,658	)
Unrealized loss on derivative instruments		(30,892	)		(2,445	)		(13,866	)		(3,937	)
Gain on sale of mineral rights		—			—			5,770			—
Other		187			(9	)		205			(145	)

Total other expense		(53,973	)		(7,727	)		(45,787	)		(15,712	)

Net income (loss) before income taxes		(12,367	)		9,552			26,209			75,484
Income tax expense		148			96			308			401

Net income (loss)	$	(12,515	)	$	9,456		$	25,901		$	75,083

Minimum quarterly distribution to common unitholders		(8,625	)		(7,365	)		(25,875	)		(22,095	)
General partner’s incentive distribution rights		—			—			(10,658	)		(14,102	)
General partner’s interest in net (income) loss		250			(189	)		(8	)		(783	)
Common unitholders’ share of net income in excess of minimum quarterly distribution		—			—			(9,704	)		(13,592	)

Subordinated unitholders’ interest in net income (loss)	$	(20,890	)	$	1,902		$	(20,344	)	$	24,511

Basic and diluted net income (loss) per limited partner unit:
Common	$	0.45		$	0.45		$	1.86		$	2.18
Subordinated	$	(1.60	)	$	0.15		$	(1.55	)	$	1.88
Weighted average limited partner common units outstanding — basic		19,166			16,366			19,166			16,366
Weighted average limited partner subordinated units outstanding — basic		13,066			13,066			13,066			13,066
Weighted average limited partner common units outstanding — diluted		19,166			16,369			19,166			16,369
Weighted average limited partner subordinated units outstanding — diluted		13,066			13,066			13,066			13,066
Cash distributions declared per common and subordinated unit	$	0.45		$	0.63		$	1.53		$	1.86

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Accumulated
	Other			Partners' Capital
	Comprehensive			General			Limited Partners
	Loss			Partner			Common			Subordinated			Total
	(In thousands)
Balance at December 31, 2007	$	(39,641	)	$	19,364		$	375,925		$	43,996		$	399,644
Comprehensive loss:
Net income					518			15,093			10,290			25,901
Cash flow hedge loss reclassified to net income		10,993			—			—			—			10,993
Change in fair value of cash flow hedges		(55,991	)		—			—			—			(55,991	)

Comprehensive loss														(19,097	)
Common units repurchased for phantom unit grants								(115	)					(115	)
Amortization of phantom units					—			90			—			90
Distributions to partners					(2,024	)		(29,324	)		(19,991	)		(51,339	)

Balance at September 30, 2008	$	(84,639	)	$	17,858		$	361,669		$	34,295		$	329,183

See accompanying notes to unaudited condensed consolidated financial statements.

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


	For the Nine Months Ended
	September 30,
	2008			2007
	(In thousands)
Operating activities
Net income	$	25,901		$	75,083
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		42,369			10,978
Amortization of turnaround costs		1,041			2,586
Provision for doubtful accounts		1,320			—
Non-cash debt extinguishment costs		898			347
Unrealized loss on derivative instruments		13,866			3,937
Gain on sale of mineral rights		(5,770	)		—
Other non-cash activities		1,223			205
Changes in operating assets and liabilities, net of business acquisition:
Accounts receivable		(64,410	)		(18,159	)
Inventories		84,606			9,605
Prepaid expenses and other current assets		4,641			1,773
Derivative activity		7,510			1,079
Intangible assets		(1,438	)		—
Other noncurrent assets		(547	)		(5,461	)
Accounts payable		(39,473	)		44,975
Accrued salaries, wages and benefits		1,621			(1,077	)
Taxes payable		1,996			361
Other current liabilities		518			(473	)
Other non-current liabilities		(193	)		—

Net cash provided by operating activities		75,679			125,759
Investing activities
Additions to property, plant and equipment		(161,811	)		(165,460	)
Acquisition of Penreco, net of cash acquired		(269,118	)		—
Settlement of derivative instruments		(6,042	)		—
Proceeds from sale of mineral rights		6,065			—
Proceeds from disposal of property, plant and equipment		24			61

Net cash used in investing activities		(430,882	)		(165,399	)
Financing activities
Proceeds from borrowings, net — revolving credit facility		85,933			34,020
Repayments of borrowings — prior term loan credit facility		(30,099	)		(19,327	)
Proceeds from borrowings, net — new term loan credit facility		367,600			—
Debt issuance costs		(9,633	)		—
Repayments of borrowings — new term loan credit facility		(8,953	)		—
Payments on capital lease obligations		(309	)		—
Change in bank overdraft		2,190			1,216
Purchase of common units for unit grants		(115	)		—
Distributions to partners		(51,339	)		(57,196	)

Net cash provided by (used in) financing activities		355,275			(41,287	)

Net increase (decrease) in cash		72			(80,927	)
Cash at beginning of period		35			80,955

Cash at end of period	$	107		$	28

Supplemental disclosure of cash flow information
Interest paid	$	24,180		$	6,285

Income taxes paid	$	19		$	120

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. Partnership Organization and Basis of Presentation

Calumet Specialty Products Partners, L.P. (Calumet, Partnership, or the Company) is a Delaware limited partnership. The general partner 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. On July 5, 2006 and November 20, 2007, the Partnership completed follow-on public offerings of its common units. As of September 30, 2008, 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 closed on the acquisition of Penreco, a Texas general partnership, for approximately $269,118. See Note 4 for further discussion of this acquisition. As a result, the assets and liabilities and results of the operation of these assets are included within the Company’s unaudited condensed consolidated balance sheet as of September 30, 2008 and the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2008. 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 September 30, 2008 and for the three and nine months ended September 30, 2008 and 2007 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 and nine months ended September 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. 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, 2007 filed on March 4, 2008.

2. New Accounting Pronouncements

In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (the “Position”), which amends certain aspects of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts. The Position permits companies to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The Position is effective for fiscal years beginning after November 15, 2007. The Company adopted the Position on January 1, 2008 and the adoption did not have a material effect on its financial position, results of operations, or cash flows.

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 anticipates that the Statement will not have a material effect on its financial position, results of operations, or cash flows.

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. Thus, the Company currently does not anticipate the adoption of SFAS 161 will have a material impact on the disclosures already provided.

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 is evaluating the potential impacts of EITF 07-4.

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. Early adoption is prohibited. The Company does not expect the adoption of FSP No. 142-3 to have a material impact on its consolidated results of operations or financial condition.

3. Inventories

The cost of inventories is determined using the last-in, first-out (“LIFO”) method. Inventories are valued at the lower of cost or market value.

Inventories consist of the following:


	September 30,		December 31,
	2008		2007
Raw materials	$	10,010	$	20,887
Work in process		34,388		21,325
Finished goods		45,052		65,452

	$	89,450	$	107,664

The replacement cost of these inventories, based on current market values, would have been $113,198 and $107,885 higher at September 30, 2008 and December 31, 2007, respectively. For the nine months ended September 30, 2008 and 2007, the Company recorded a reduction to cost of sales of $50,826 and $5,053, respectively, in the unaudited condensed consolidated statements of operations due to the liquidation of lower cost inventory layers as a result of the Company’s working capital reduction initiative.

4. Acquisition of Penreco

On January 3, 2008 the Company closed on the acquisition of Penreco, a Texas general partnership, for $269,118, net of the cash balance in Penreco’s accounts at closing. 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 provides several key strategic benefits, including market synergies within its solvents and lubricating oil product lines, additional operational and logistical flexibility and overhead cost reductions resulting from the acquisition. The acquisition also broadens the Company’s customer base and gives the Company access to new markets.

As a result of the acquisition, the assets and liabilities previously held by Penreco and results of the operation of these assets have been included in the Company’s unaudited condensed consolidated balance sheet and unaudited condensed consolidated statements of operations since the date of acquisition. The unaudited pro forma summary results of operations for the three and nine months ended September 30, 2007 below, combines the results of operations of Calumet and Penreco as if the acquisition had occurred on January 1, 2007.


	For the Three		For the Nine
	Months Ended		Months Ended
	September 30, 2007		September 30, 2007
	(Unaudited)		(Unaudited)
Sales	$	540,140	$	1,516,492
Net income	$	13,803	$	91,390
Basic and diluted net income per limited partner unit	$	0.46	$	2.40

The Company is negotiating the final settlement with ConocoPhillips Company and M.E. Zukerman Specialty Oil Corporation for working capital adjustments, which the Company believes is unlikely to result in a material change to the purchase price. The Company recorded $48,336 of goodwill as a result of this acquisition, all of which was recorded within the Company’s specialty products segment. The preliminary allocation of the aggregate purchase price, which is preliminary pending the final working capital adjustments, is as follows:


Accounts receivable	$	42,049
Inventories		66,392
Prepaid expenses and other current assets		70
Property, plant and equipment		91,790
Other noncurrent assets		288
Intangible assets		59,325
Goodwill		48,336
Accounts payable		(29,014	)
Other current liabilities		(5,930	)
Other noncurrent liabilities		(4,188	)

Total purchase price, net of cash acquired	$	269,118

The components of intangible assets listed in the table above as of January 3, 2008, based upon a third party appraisal, were as follows:


	Amount		Life
Customer relationships	$	28,482		20
Supplier agreements		21,519		4
Patents		1,573		12
Non-competition agreements		5,732		5
Distributor agreements		2,019		3

Total	$	59,325
Weighted average amortization period				12

The Company formulated its plan associated with the involuntary termination of certain Penreco employees and accrued $1,829 for such costs, all of which has been included in the acquisition cost allocation. All affected employees have been terminated as of September 30, 2008. For the three and nine months ended September 30, 2008, the Company paid $90 and $1,804, respectively, of termination benefits against the liability and has $25 of remaining liability for termination costs, all of which were recorded in connection with the acquisition.

5. Sale of Mineral Rights

In June 2008, the Company received one-time lease bonuses of $6,065 associated with the lease of mineral rights on the real property at the Shreveport and Princeton refineries to an unaffiliated third party which have been accounted for as a sale. The Company has retained a royalty interest in any future production associated with these mineral rights. As a result of these transactions, the Company recorded a gain of $5,770 in other income (expense) in the unaudited condensed consolidated statements of operations.

Under the term loan agreement, cash proceeds resulting from the disposition of property, plant and equipment must be used as a mandatory prepayment of the term loan. As a result, the Company made a prepayment of $6,065 in June 2008 on the term loan.

6. Shreveport Refinery Expansion

As of December 31, 2007, the Company had invested $254,414 in its Shreveport refinery expansion project. Through September 30, 2008, the Company has invested an additional $118,222 for a total of $372,636 in its Shreveport refinery expansion project. The project was completed and operational in May 2008.

Additionally, for the year ended December 31, 2007 and the nine months ended September 30, 2008, the Company had invested $65,633 and $37,549, respectively, in the Shreveport refinery for other capital expenditures including projects to improve efficiency, de-bottleneck certain operating units and for new product development.

7. Goodwill and Intangible Assets

The Company has preliminarily recorded $48,336 of goodwill as a result of the Penreco acquisition, all of which is recorded within the Company’s specialty products segment. The Company had none recorded as of December 31, 2007.

Intangible assets consist of the following:


			September 30, 2008					December 31, 2007
	Weighted		Gross		Accumulated			Gross		Accumulated
	Average Life		Amount		Amortization			Amount		Amortization
Customer relationships		20	$	30,757	$	(5,328	)	$	2,276	$	(2,165	)
Supplier agreements		4		21,519		(5,655	)		—		—
Patents		12		1,573		(235	)		—		—
Non-competition agreements		5		5,732		(576	)		—		—
Distributor agreements		3		2,019		(568	)		—		—
Royalty agreements		19		4,116		(439	)		2,680		(331	)

		12	$	65,716	$	(12,801	)	$	4,956	$	(2,496	)

Intangible assets associated with supplier agreements, non-competition agreements, patents and distributor agreements are being amortized using the discounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships of Penreco are being amortized using the discounted estimated future cash flows based upon an assumed rate of annual customer attrition. For the three and nine months ended September 30, 2008, the Company recorded amortization expense of intangible assets of $3,337 and $10,306, respectively, as compared to $121 and $597 for the three and nine months ended September 30, 2007. The Company estimates that amortization of intangible assets will be $3,413 for the remainder of 2008, with annual amortization of $11,409, $8,808, $6,972, and $5,728 for the years ended December 31, 2009, 2010, 2011, and 2012, respectively.

8. Fair Value of Financial Instruments

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 has adopted the provisions of SFAS 157 as of January 1, 2008 for financial instruments. In February 2008, the FASB agreed to defer for one year the effective date of SFAS 157 for certain nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.

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 No. 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 September 30, 2008, the Company held certain assets 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 our derivative instruments are with counterparties that have long-term credit ratings of single A or better. These derivative instruments include swap contracts as well as different types of option contracts. See Note 9 for further information on the Company’s derivative instruments and hedging activities. The fair values of swap contracts 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 in a net liability position. Based on the use of various unobservable inputs, principally non-performance risk, unobservable inputs in volatility of crude collars 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. These option contracts are also adjusted for non-performance risk as discussed above.

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 September 30, 2008, were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total

Assets:
Crude oil swaps	$	—	$	—	$	688,747		$	688,747
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Natural gas swaps		—		—		—			—
Crude oil options		—		—		—			—
Pension plan investments		18,142		—		—			18,142

Total assets at fair value	$	18,142	$	—	$	688,747		$	706,889

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(234,047	)		(234,047	)
Diesel swaps		—		—		(550,186	)		(550,186	)
Natural gas swaps		—		—		(1,913	)		(1,913	)
Crude oil options		—		—		(17,775	)		(17,775	)
Interest rate swaps		—		—		(2,661	)		(2,661	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(806,582	)	$	(806,582	)

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the nine months ended September 30, 2008:


	Derivative
	Instruments,
	Net
Fair value at January 1, 2008	$	(600,051	)
Realized losses		12,971
Unrealized gains (losses)		5,418
Comprehensive income (loss)		(65,498	)
Purchases, issuances and settlements		(13,223	)
Transfers in (out) of Level 3		542,548

Fair value at September 30, 2008	$	(117,835	)

Total gains or losses included in net income attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of September 30, 2008	$	(13,866	)

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 (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative contracts not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 9 for further information on SFAS 133 and hedging.

9. Derivatives

The Company utilizes derivative instruments to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas, the sale of fuel products and interest payments.

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 as either assets or liabilities at fair value on the consolidated balance sheets. The Company utilizes third party valuations and published market data to determine the fair value of these derivatives. The Company considers its derivative instrument valuations to be Level 3 fair value measurements under SFAS 157 (see Note 8).

To the extent a derivative instrument is designated effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations. The Company accounts for certain derivatives hedging purchases of crude oil and natural gas, the sale of gasoline, diesel and jet fuel and the payment of interest as cash flow hedges. The derivatives hedging purchases and sales are recorded to cost of sales and 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.

For the three months ended September 30, 2008 and 2007, the Company has recorded derivative losses of $124,445 and $10,316, respectively, to sales and derivative gains of $112,137 and $9,538, respectively, to cost of sales in the unaudited condensed consolidated financial statements of operations. For the nine months ended September 30, 2008 and 2007, the Company recorded derivative losses of $320,522 and $1,919, respectively, to sales and a derivative gain of $311,065 and a derivative loss of $19,058, respectively, to cost of sales in the unaudited condensed consolidated financial statements of operations. During the three months ended September 30, 2008 and 2007, the Company recorded a loss of $10,683 and $0, respectively, on crude oil collar derivative settlements in realized loss on derivative instruments in the unaudited condensed consolidated financial statements of operations due to the derivative transactions not being designated as cash flow hedges. For the nine months ended September 30, 2008 and 2007, the Company recorded losses of $5,574 and $0, respectively, on crude oil collar derivative settlements in realized loss on derivative instruments in the unaudited condensed consolidated financial statements of operations due to the derivative transactions not being designated as cash flow hedges. An interest rate swap loss of $251 and a gain of $3 for the three months ended September 30, 2008 and 2007, respectively, was recorded to interest expense in the unaudited condensed consolidated financial statements of operations. An interest rate swap loss of $328 and a gain of $3 for the nine months ended September 30, 2008 and 2007, respectively, was recorded to interest expense in the unaudited condensed consolidated financial statements of operations. For derivative instruments not designated as cash flow hedges and the portion of any cash flow hedge that is determined to be ineffective, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations.

The Company 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. The Company’s estimate of the ineffective portion of the hedges for the nine months ended September 30, 2008 and 2007 were losses of $4,398 and $7,733, respectively, which were recorded to unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations. The Company recorded the time value on its crude oil collar derivative instruments, which is excluded from the assessment of hedge effectiveness, of $0 and a gain of $532, respectively, to unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008 and 2007.

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 and nine months ended September 30, 2008 and 2007 was as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Net income (loss)	$	(12,515	)	$	9,456		$	25,901		$	75,083
Cash flow hedge (gain) loss reclassified to net income		5,853			(4,035	)		10,993			(9,256	)
Change in fair value of cash flow hedges		39,978			18,883			(55,991	)		(65,016	)

Total comprehensive income (loss)	$	33,316		$	24,304		$	(19,097	)	$	811

The effective portion of the hedges classified in accumulated other comprehensive loss is $84,639 as of September 30, 2008 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)
2008	$	(2,466	)
2009		(29,955	)
2010		(35,005	)
2011		(17,223	)
2012		10

Total	$	(84,639	)

The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company executes all of its derivative instruments with a small number of counterparties, the majority of which are large financial institutions with ratings of at least A1 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 crosses 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. As of September 30, 2008, the Company had no cash collateral held by counterparties. As of September 30, 2008, the Company had issued $3,100 of standby letters of credit to its counterparties. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. As of October 31, 2008, the Company had issued $15,400 in cash collateral and no standby letters of credit to its counterparties to cover margin calls.

Crude Oil Collar and Swap Contracts — Specialty Products Segment

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 75% 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.

At September 30, 2008, the Company had the following four-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $1,161 of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					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)
October 2008		124,000		4,000		92.98	$	102.98	$	112.98	$	122.98
November 2008		120,000		4,000		92.98		102.98		112.98		122.98
December 2008		124,000		4,000		92.98		102.98		112.98		122.98

Totals		368,000
Average price					$	92.98	$	102.98	$	112.98	$	122.98

At September 30, 2008, the Company had the following three-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $11,676 of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					Average		Average		Average
					Sold Put		Bought Call		Sold Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)
Fourth Quarter 2008		951,000		10,337	$	109.44	$	127.29	$	136.20

Totals		951,000
Average price					$	109.44	$	127.29	$	136.20

At September 30, 2008, the Company had the following two-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $5,063 of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					Average		Average
					Sold Put		Bought Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
Fourth Quarter 2008		276,000		3,000	$	98.85	$	135.00
First Quarter 2009		180,000		2,000	$	112.05	$	145.00
Second Quarter 2009		91,000		1,000	$	111.45	$	145.00
Fourth Quarter 2009		276,000		3,000	$	86.40	$	120.00

Totals		823,000
Average price					$	98.95	$	133.26

At September 30, 2008, the Company had the following purchased put option derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. The Company entered into these derivatives to limit its downside risk on previously executed two-way and three-way crude collar derivatives. As a result of these derivatives not being designated as hedges, the Company recognized $125 of gains in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					Average
					Bought Put
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
October 2008		279,000		9,000	$	87.67

Totals		279,000
Average price					$	87.67

At December 31, 2007, the Company had the following derivatives related to crude oil purchases in its specialty products segment, all 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 2008		248,000		8,000	$	67.85	$	77.85	$	87.85	$	97.85
February 2008		232,000		8,000		76.13		86.13		96.13		106.13
March 2008		248,000		8,000		77.63		87.63		97.63		107.63
April 2008		60,000		2,000		74.30		84.30		94.30		104.30
May 2008		62,000		2,000		74.30		84.30		94.30		104.30
June 2008		60,000		2,000		74.30		84.30		94.30		104.30
July 2008		62,000		2,000		74.30		84.30		94.30		104.30
August 2008		62,000		2,000		74.30		84.30		94.30		104.30
September 2008		60,000		2,000		74.30		84.30		94.30		104.30

Totals		1,094,000
Average price					$	74.01	$	84.01	$	94.01	$	104.01

Crude Oil Swap Contracts by Expiration Dates

Barrels

BPD

($/Bbl)

First Quarter 2008

91,000

1,000

90.92

Crude Oil Swap Contracts -— Fuel Products Segment

The Company utilizes swap contracts to manage crude oil price risk and volatility of cash flows in its fuel products segment. The Company’s policy is generally to enter into crude oil swap contracts for a period no greater than five years forward and for no more than 75% of crude oil purchases used in fuels production. At September 30, 2008, 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)
Fourth Quarter 2008		2,116,000		23,000		66.49
Calendar Year 2009		8,212,500		22,500		66.26
Calendar Year 2010		7,482,500		20,500		67.27
Calendar Year 2011		3,009,000		8,244		76.98

Totals		20,820,000
Average price					$	68.20

At December 31, 2007, 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)
First Quarter 2008		2,184,000		24,000		67.87
Second Quarter 2008		2,184,000		24,000		67.87
Third Quarter 2008		2,208,000		24,000		66.54
Fourth Quarter 2008		2,116,000		23,000		66.49
Calendar Year 2009		8,212,500		22,500		66.26
Calendar Year 2010		7,482,500		20,500		67.27
Calendar Year 2011		2,096,500		5,744		67.70

Totals		26,483,500
Average Price					$	66.97

Fuel Products Swap Contracts

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 and Jet Fuel Swap Contracts

At September 30, 2008, 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 and Jet Fuel Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Fourth Quarter 2008		1,334,000		14,500		81.42
Calendar Year 2009		4,745,000		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		13,195,000
Average price					$	82.38

At December 31, 2007, 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 except for 42,520 barrels in 2008. As a result of these derivatives not being designated as hedges, the Company recognized $941 of losses in unrealized loss on derivative instruments in the consolidated statements of operations during the year ended December 31, 2007.


Diesel and Jet Fuel Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
First Quarter 2008		1,319,500		14,500		82.81
Second Quarter 2008		1,319,500		14,500		82.81
Third Quarter 2008		1,334,000		14,500		81.42
Fourth Quarter 2008		1,334,000		14,500		81.42
Calendar Year 2009		4,745,000		13,000		80.51
Calendar Year 2010		4,745,000		13,000		80.41
Calendar Year 2011		1,641,000		4,496		79.93

Totals		16,438,000
Average price					$	80.94

Gasoline Swap Contracts

At September 30, 2008, 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		BPD		($/Bbl)
Fourth Quarter 2008		782,000		8,500		74.62
Calendar Year 2009		3,467,500		9,500		73.83
Calendar Year 2010		2,737,500		7,500		75.10
Calendar Year 2011		638,000		1,748		83.42

Totals		7,625,000
Average price					$	75.17

At December 31, 2007, 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		BPD		($/Bbl)
First Quarter 2008		864,500		9,500		76.98
Second Quarter 2008		864,500		9,500		76.98
Third Quarter 2008		874,000		9,500		74.79
Fourth Quarter 2008		782,000		8,500		74.62
Calendar Year 2009		3,467,500		9,500		73.83
Calendar Year 2010		2,737,500		7,500		75.10
Calendar Year 2011		455,500		1,248		74.98

Totals		10,045,500
Average price					$	74.91

Natural Gas Swap Contracts

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 September 30, 2008, the Company had the following derivatives related to natural gas purchases, of which 180,000 MMbtus are designated as hedges. As a result of these derivative instruments not being designated as hedges, the Company recognized $1,822 of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


Natural Gas Swap Contracts by Expiration Dates	MMbtus		$/MMbtu
Fourth Quarter 2008		430,000	$	10.25
First Quarter 2009		330,000	$	10.38

Totals		760,000
Average price			$	10.31

At December 31, 2007, the Company had the following derivatives related to natural gas purchases, all of which are designated as hedges.


Natural Gas Swap Contracts by Expiration Dates	MMbtus		$/MMbtu
First Quarter 2008		850,000	$	8.76
Third Quarter 2008		60,000	$	8.30
Fourth Quarter 2008		90,000	$	8.30
First Quarter 2009		90,000	$	8.30

Totals		1,090,000
Average price			$	8.66

Interest Rate Swap Contracts

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 $100,000, $150,000 and $50,000 of the total outstanding term loan indebtedness in 2008, 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 3.37%, 3.09%, and 3.66% per annum in 2008, 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 loss on derivative instruments in the unaudited condensed consolidated statements of operations. For the three and nine months ended September 30, 2008, the Company recorded a gain of $408 and a loss of $2,705, respectively. 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.

10. 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”), Internal Revenue Service (“IRS”) and Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position, results of operations or cash flow.

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 $391 and supplemental 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) a number of similar matters at the Princeton refinery. 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 condensed consolidated balance sheets. Environmental expenses are recorded within other operating expenses on 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. While no significant compliance and enforcement expenditures have been requested as a result of the Company’s discussions with the LDEQ, the Company anticipates that it will ultimately be required to make emissions reductions requiring capital investments between approximately $1,000 and $3,000 over a three to five year period at the Company’s three Louisiana refineries. In addition to the above required capital spending, during the third quarter of 2008 we received notice from the LDEQ that we will be required to make additional environmental capital expenditures of approximately $700 during 2009 at our Cotton Valley refinery associated with groundwater remediation.

Voluntary remediation of subsurface contamination is in process at each of the Company’s facilities. 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 facilities can be controlled or remedied without having a material adverse effect on its financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.

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

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 two years from January 1, 2008 if there are no claims asserted by the Company and are generally subject to a $2,000 limit.

Health and Safety

The Company received an OSHA citation in the fourth quarter of 2007 for various process safety violations at its Shreveport refinery which resulted in a penalty. During the first quarter of 2008, the Company settled this penalty for $100. As a result of a third party review, we expect to incur additional capital expenditures at our Shreveport refinery to maintain compliance with OSHA regulations. We cannot estimate the total cost of these capital expenditures at this time as we are in the preliminary stages of assessing the required capital expenditures with third parties. However, we do not anticipate that these capital expenditures will be material. These expenditures are expected to occur over the next several years. With the exception of this citation, 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. At September 30, 2008 and December 31, 2007, the Company had outstanding standby letters of credit of $74,331 and $96,676, respectively, under its senior secured revolving credit facility. At September 30, 2008 and December 31, 2007, the Company had availability to issue letters of credit of $225,669 and $103,324, respectively, under its senior secured revolving credit facility. The Company also had a $50,000 letter of credit outstanding under the senior secured first lien letter of credit facility for its fuels hedging program, which bears interest at 4.0%.

11. Long-Term Debt

Long-term debt consisted of the following:


	September 30,			December 31,
	2008			2007
Borrowings under new senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 4.00% (6.80% at September 30, 2008), interest and principal payments quarterly with borrowings due January 3, 2015, effective interest rate of 7.96%	$	376,048			—
Borrowings under senior secured first lien term loan with third-party lenders, interest at rate of three-month LIBOR plus 3.50% (8.74% at December 31, 2007), interest and principal payments quarterly with borrowings due December 2012		—			30,099
Borrowings under senior secured revolving credit agreement with third-party lenders, interest at prime plus 0.50% (5.50% and 7.25% at September 30, 2008 and December 31, 2007, respectively), interest payments monthly, borrowings due January 2013		92,891			6,958
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly with borrowings due January 2012		2,891			2,834
Less unamortized discount on new senior secured first lien term loan with third-party lenders		(15,693	)		—

Total long-term debt		456,137			39,891
Less current portion of long-term debt		4,842			943

	$	451,295		$	38,948

The maximum borrowing capacity at September 30, 2008 under the senior secured revolving credit agreement was $303,724, with $136,503 available for additional borrowings based on collateral and specified availability limitations. The revolving credit facility has a first priority lien on the Company’s cash, accounts receivable and inventory and a second priority lien on the Company’s fixed assets.

On January 3, 2008, the Partnership closed a new $435,000 senior secured first lien term loan facility which includes a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. In addition, the Company incurred $17,400 of issuance discount in connection with the term loan facility. The proceeds of the term loan were used to (i) finance a portion of the acquisition of Penreco, (ii) fund the anticipated growth in working capital and remaining capital expenditures associated with the Shreveport refinery expansion project, (iii) refinance the existing term loan and (iv) to the extent available, for general partnership purposes. The term loan bears interest at a rate equal to (i) with respect to a LIBOR Loan, the LIBOR Rate plus 400 basis points (as defined in the term loan facility) and (ii) with respect to a Base Rate Loan, the Base Rate plus 300 basis points (as defined in the term loan facility).

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 matures in January 2015. The term loan facility requires quarterly principal payments of $963 until September 30, 2014, with the remaining balance due at maturity on January 3, 2015. In June 2008, the Company received $6,065 associated with the lease of mineral rights on the real property at its Shreveport and Princeton refineries to an unaffiliated third party which have been accounted for as a sale. As a result of these transactions, the Company recorded a gain of $5,770 in other income (expense) in the unaudited condensed consolidated statements of operations. Under the term loan agreement, cash proceeds resulting from the disposition of the Company’s property, plant and equipment must be used as a mandatory prepayment of the term loan. As a result, the Company made a prepayment of $6,065 in June 2008 on the term loan.

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 and (ii) conform certain of the financial covenants and other terms in the revolving credit facility to those contained in the term loan credit agreement. The existing senior secured revolving credit facility matures on January 3, 2013.

The Company has experienced adverse financial conditions primarily attributable with historically high crude oil costs, which have negatively affected specialty products gross profit for the three quarters ended June 30, 2008. Also contributing to these adverse financial conditions have been the significant cost overruns and delays in the startup of the Shreveport refinery expansion project. Compliance with the financial covenants pursuant to the Company’s credit agreements is tested quarterly based on performance over the most recent four fiscal quarters, and as of September 30, 2008, the Company was in compliance with all financial covenants under its credit agreements. The Company’s ability to maintain compliance with these covenants in the quarter ended September 30, 2008 was substantially enhanced by the significant increase in specialty products segment gross profit during the third quarter resulting from increased selling prices for specialty products and reductions in the cost of crude oil. The Company continues to take steps to ensure that it meets the requirements of its credit agreements and currently forecasts that it will be in compliance for future measurement dates. These steps have included increasing specialty products sales prices, increased crude oil price hedging for the specialty products segment and reductions in working capital.

While assurances cannot be made regarding its future compliance with the financial covenants in its credit agreements and being cognizant of the general uncertain economic environment, the Company anticipates that its completion of the Shreveport refinery expansion project, its continued integration of the Penreco acquisition, its forecasted capital expenditures, its marketing strategies and other strategic initiatives will allow it to maintain compliance with such financial covenants and to continue to improve its Adjusted EBITDA, 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 September 30, 2008, maturities of the Company’s long-term debt are as follows:


Year	Maturity
2008	$	1,216
2009		4,811
2010		4,594
2011		4,460
Thereafter		456,749

Total	$	471,830

12. Employee Benefit Plans

The Company has a noncontributory defined benefit plan (“Pension Plan”) for both those salaried employees as well as those employees represented by either the United Steelworkers (“USW”) or the International Union of Operating Engineers (“IUOE”) who were formerly employees of Penreco and who became employees of the Company as a result of the Penreco acquisition on January 3, 2008. The Company also has a contributory defined benefit postretirement medical plan for both those salaried employees as well as those employees represented by either the International Brotherhood of Teamsters (“IBT”), USW or IUOE who were formerly employees of Penreco and who became employees of the Company as a result of the Penreco acquisition, as well as a non-contributory disability plan for those salaried employees who were formerly employees of Penreco (collectively, “Other Plans”). The pension benefits are based primarily on years of service for USW and IUOE represented employees and both years of service and the employee’s final 60 months’ average compensation for salaried employees. The funding policy is consistent with funding requirements of applicable laws and regulations. The assets of these plans consist of corporate equity securities, municipal and government bonds, and cash equivalents.

The components of net periodic pension and other post retirement benefits cost for the three and nine months ended September 30, 2008 were as follows:


	Three Months Ended					Nine Months Ended
	September 30, 2008					September 30, 2008
				Other Post					Other Post
				Retirement					Retirement
	Pension			Employee		Pension			Employee
	Benefits			Benefits		Benefits			Benefits
Service cost	$	236		$	2	$	708		$	7
Interest cost		324			13		973			38
Expected return on assets		(334	)		—		(1,002	)		—

Net periodic pension cost	$	226		$	15	$	679		$	45

During the three and nine months ended September 30, 2008, the Company made contributions of $193 and $0 to its Pension Plan and Other Plans, respectively and expects no additional contributions to be made for the remainder of 2008.

The benefit obligations, plan assets, funded status, and amounts recognized in the condensed consolidated balance sheets were as follows:


				Other Post
				Retirement
	Pension			Employee
	Benefits			Benefits
Change in projected benefit obligation (“PBO”):
Benefit obligation at January 3, 2008	$	21,421		$	910
Service cost		708			7
Interest cost		973			38
Expected return on assets		(1,002	)		—

Benefit obligation at September 30, 2008	$	22,100		$	955
Fair value of plan assets at January 3, 2008		18,142			—
Employer contribution		193			—

Fair value of plan assets at September 30, 2008		18,335			—

Funded status—benefit obligation in excess of plan assets	$	(3,765	)	$	(955	)
Reconciliation of funded status:
Funded status—benefit obligation in excess of plan assets		(3,765	)		(955	)
Unrecognized prior service cost		—			—
Unrecognized loss		—			—

Prepaid (accrued) pension cost		(3,765	)		(955	)
Accrued benefit obligation		—			—

Net amount recognized on condensed consolidated balance sheet at September 30, 2008	$	(3,765	)	$	(955	)

The accumulated benefit obligation for the Pension Plan and Other Plans was $17,547 as of January 3, 2008. The accumulated benefit obligations for the Pension Plan and Other Plans were less than plan assets by $636 as of January 3, 2008. As of January 3,

2008, the Company had no prior service costs, actuarial gains (losses) or transition gains (losses) recorded in accumulated other comprehensive loss in the condensed consolidated balance sheets.

The significant weighted average assumptions used for the three and nine months ended September 30, 2008 and as of January 3, 2008 were as follows:


	Pension	Other Post Retirement
	Benefits	Employee Benefits
Discount rate for benefit obligations	6.58%	6.20%
Discount rate for net periodic benefit costs	5.94%	5.74%
Expected return on plan assets for net periodic benefit costs	7.50%	0.00%
Rate of compensation increase for benefit obligations	4.50%	0.00%
Rate of compensation increase for net periodic benefit costs	4.50%	0.00%

The Company uses a measurement date of December 31 for the plans. For measurement purposes, a 9.50% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2008. The rate was assumed to decrease by .75% per year for an ultimate rate of 5% for 2014 and remain at that level thereafter. An increase or decrease by one percentage point in the assumed healthcare cost trend rates would not have a material effect on the benefit obligation and service and interest cost components of benefit costs for the Other Plans as of January 3, 2008. The Company considered the historical returns and the future expectation for returns for each asset class, as well as the target asset allocation of the Pension Plan portfolio, to develop the expected long-term rate of return on plan assets.

The Company’s Pension Plan and Other Plans asset allocations, as of January 3, 2008 by asset category, are as follows:


				Other Post
				Retirement
	Pension			Employee
	Benefits			Benefits
Cash		3	%		100	%
U.S equities		60	%		0	%
Foreign equities		20	%		0	%
Fixed income		17	%		0	%

		100	%		100	%

Investment Policy

The investment objective of the Penreco Pension Plan Trust (the “Trust”) is to generate a long-term rate of return which will fund the related pension liabilities and minimize the Company’s contributions to the Trust. Trust assets are to be invested with an emphasis on providing a high level of current income through fixed income investments and longer-term capital appreciation through equity investments. Trust assets are targeted to achieve an investment return of 7.75% or more compounded annually over any 5-year period. Due to the long-term nature of pension liabilities, the Trust will assume moderate risk only to the extent necessary to achieve its return objective.

The Trust pursues its investment objectives by investing in a customized profile of asset allocation which corresponds to the investment return target. Full discretion in portfolio investment decisions is given to Wells Fargo & Company or its affiliates (“the Manager”), subject to the investment policy guidelines. The Manager is required to utilize fiduciary care in all investment decisions and is expected to minimize all costs and expenses involved with the managing of these assets.

With consideration given to the long-term goals of the Trust, the following ranges reflect the long-term strategy for achieving the stated objectives:


	Range of
Asset Class	Asset Allocations	Target Allocation
Cash	0--5%	Minimal
Fixed income	20--50%	35%
Equities	50--80%	65%

Trust assets will be invested in accordance with the prudent expert standard as mandated by ERISA. In the event market environments create asset exposures outside of the policy guidelines, reallocations will be made in an orderly manner.

Fixed Income Guidelines

U.S. Treasury, agency securities, and corporate bond issues rated “investment grade” or higher are considered appropriate for this portfolio. Written approval will be obtained to hold securities downgraded below “investment grade” by either Moody’s or Standard & Poor’s. Money market and fixed-income funds that are consistent with the stated investment objective of the Trust are also considered acceptable.

Excluding U.S. Treasury and agency obligations, money market or fixed-income mutual funds, no single issuer shall exceed more than 10% of the total portfolio market value. The average maturity range shall be consistent with the objective of providing a high level of current income and long-term growth within the acceptable risk level established for the Trust.

Equity Guidelines

Any equity security that is on the Manager’s working list is considered appropriate for this portfolio. Equity mutual funds that are consistent with the stated investment objective of the Trust are also considered acceptable. No individual equity position, with the exception of equity mutual funds, should exceed 10% of the total market value of the Trust’s assets.

Performance of investment results will be reviewed, at least semi-annually, by the Calumet Retirement Savings Committee (“CRSC”) and annually at a joint meeting between the CRSC and the Manager. Written communication regarding investment performance occurs quarterly. Any major changes in the Manager’s investment strategy will be communicated to the Chairman of the CRSC on an ongoing basis and as frequently as necessary. The Manager shall be informed of special situations affecting Trust investments including substantial withdrawal or funding pattern changes and changes in investment policy guidelines and objectives.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of January 3, 2008:


			Other Post
	Pension		Retirement
	Benefits		Employee Benefits
2008	$	527	$	114
2009		602		106
2010		711		77
2011		820		90
2012		955		98
2013 to 2017		7,661		347

Total	$	11,276	$	832

13. Partners’ Capital

Calumet’s distribution policy is defined in its Partnership Agreement. During the nine months ended September 30, 2008 and 2007, the Company made distributions of $51,339 and $57,196, respectively, to its partners.

14. 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, which includes Penreco from the date of acquisition, produces a variety of lubricating oils, solvents and waxes. 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 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 September 30, 2008	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	486,165	$	238,206	$	724,371	$	—		$	724,371
Intersegment sales		328,821		4,895		333,716		(333,716	)		—

Total sales	$	814,986	$	243,101	$	1,058,087	$	(333,716	)	$	724,371

Depreciation and amortization		16,480				16,480					16,480
Income from operations		34,431		7,175		41,606					41,606
Reconciling items to net loss:
Interest expense											(10,670	)
Interest income											23
Debt extinguishment costs											—
Loss on derivative instruments											(43,513	)
Gain on sale of mineral rights											—
Other income											187
Income tax expense											(148	)

Net loss										$	(12,515	)

Capital expenditures	$	9,264	$	—	$	9,264	$	—		$	9,264


	Specialty		Fuel		Combined					Consolidated
Three Months Ended September 30, 2007	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	219,670	$	208,414	$	428,084	$	—		$	428,084
Intersegment sales		190,487		7,340		197,827		(197,827	)		—

Total sales	$	410,157	$	215,754	$	625,911	$	(197,827	)	$	428,084

Depreciation and amortization		4,248		—		4,248		—			4,248
Income from operations		3,000		14,279		17,279		—			17,279
Reconciling items to net income:
Interest expense											(1,346	)
Interest income											290
Debt extinguishment costs											(347	)
Loss on derivative instruments											(6,315	)
Other income											(9	)
Income tax expense											(96	)

Net income										$	9,456

Capital expenditures	$	58,814	$	—	$	58,814	$	—		$	58,814


	Specialty		Fuel		Combined					Consolidated
Nine Months Ended September 30, 2008	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	1,268,629	$	721,686	$	1,990,315	$	—		$	1,990,315
Intersegment sales		941,943		24,675		966,618		(966,618	)

Total sales	$	2,210,572	$	746,361	$	2,956,933	$	(966,618	)	$	1,990,315

Depreciation and amortization		43,410				43,410		—		$	43,410
Income from operations		17,887		54,109		71,996		—			71,996
Reconciling items to net income:
Interest expense											(24,373	)
Interest income											346
Debt extinguishment costs											(898	)
Loss on derivative instruments											(26,837	)
Gain on sale of mineral rights											5,770
Other income											205
Income tax expense											(308	)

Net income										$	25,901

Capital expenditures	$	161,811	$	—	$	161,811	$	—		$	161,811


	Specialty		Fuel		Combined					Consolidated
Nine Months Ended September 30, 2007	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	648,638	$	552,285	$	1,200,923	$	—		$	1,200,923
Intersegment sales		470,463		23,411		493,874		(493,874	)		—

Total sales	$	1,119,101	$	575,696	$	1,694,797	$	(493,874	)	$	1,200,923

Depreciation and amortization		13,564		—		13,564		—			13,564
Income from operations		46,592		44,604		91,196		—			91,196
Reconciling items to net income:
Interest expense											(3,474	)
Interest income											1,849
Debt extinguishment costs											(347	)
Loss on derivative instruments											(13,595	)
Other expense											(145	)
Income tax expense											(401	)

Net income											75,083

Capital expenditures	$	165,460	$	—	$	165,460	$	—		$	165,460


	September 30,			December 31,
	2008			2007
Segment assets:
Specialty Products	$	2,194,149		$	1,462,996
Fuel Products		1,357,131			1,019,149

Combined segments		3,551,280			2,482,145
Eliminations		(2,459,790	)		(1,803,288	)

Total assets	$	1,091,490		$	678,857

b. Geographic Information

International sales accounted for less than 10% of consolidated sales for each of the three and nine months ended September 30, 2008 and 2007.

c. Product Information

The Company offers specialty 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 major product category sales:


	Three Months Ended September 30,
	2008		2007
Specialty products:
Lubricating oils	$	271,365	$	116,726
Solvents		118,680		49,480
Waxes		39,638		20,293
Fuels		7,747		12,138
Asphalt and other by-products		48,735		21,033

Total	$	486,165	$	219,670

Fuel products:
Gasoline	$	82,550	$	80,097
Diesel		96,134		53,878
Jet fuel		57,335		64,285
By-products		2,187		10,154

Total	$	238,206	$	208,414

Consolidated sales	$	724,371	$	428,084


	Nine Months Ended September 30,
	2008		2007
Specialty products:
Lubricating oils	$	671,959	$	358,066
Solvents		343,688		150,855
Waxes		110,982		45,928
Fuels		27,254		38,165
Asphalt and other by-products		114,746		55,624

Total	$	1,268,629	$	648,638

Fuel products:
Gasoline	$	259,492	$	210,395
Diesel		302,526		154,050
Jet fuel		148,953		156,957
By-products		10,715		30,883

Total	$	721,686	$	552,285

Consolidated sales	$	1,990,315	$	1,200,923

d. Major Customers

During the nine months ended September 30, 2008, the Company had one customer, Murphy Oil U.S.A., which represented approximately 11% of consolidated sales due to rising gasoline and diesel prices and increased fuel sales to this customer. No other customer represented 10% or greater of consolidated sales in each of the three months and nine months ended September 30, 2008 and 2007.

15. Related Party Transactions

During the three and nine months ended September 30, 2008, the Company had sales of $140 and $677, respectively, to a new related party owned by one of its limited partners. The Company had no sales to this related party in 2007. The related party was a customer of the Company’s Dickinson facility, which the Company acquired on January 3, 2008.

In May 2008, the Company began purchasing all of its crude oil requirements for its Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources Co., L.P. (“Legacy”). Because Legacy is owned in part by one of the Company’s limited partners, an affiliate of our general partner, and our chief executive officer and president, F. William Grube, the terms of the agreement were reviewed by the conflicts committee of the board of directors of the Company’s general partner, which consists entirely of independent directors. The conflicts committee approved the agreement after determining that the terms of the agreement are fair and reasonable to the Company. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company is approximately 7,000 barrels per day. During the three and nine months ended September 30, 2008, the Company had crude oil purchases of $75,981 and $102,318, respectively, from Legacy.

16. Subsequent Events

On October 15, 2008, the Company declared a quarterly cash distribution of $0.45 per unit on all outstanding units, or $14,800, for the quarter ended September 30, 2008. The distribution will be paid on November 14, 2008 to unitholders of record as of the close of business on November 4, 2008. This quarterly distribution of $0.45 per unit equates to $1.80 per unit, or $59,202, on an annualized basis.

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

The historical unaudited condensed 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 and nine months ended September 30, 2008 and 2007. 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 the 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 the Shreveport refinery are included in our fuel products segment. The fuels produced in connection with the production of specialty products at the Princeton and Cotton Valley refineries are included in our specialty products segment. For the three and nine months ended September 30, 2008, approximately 85.8% and 63.6%, respectively, of our gross profit was generated from our specialty products segment and approximately 14.2% and 36.4%, respectively, of our gross profit was generated from our fuel products segment.

Our fuel products segment began operations in 2004, when we substantially completed the reconfiguration of the Shreveport refinery to add motor fuels production, including gasoline, diesel and jet fuel, to its existing specialty products slate, as well as to increase overall feedstock throughput. The project was fully completed in February 2005. The reconfiguration was undertaken to capitalize on strong fuels refining margins, or crack spreads, relative to historical levels, to utilize idled assets, and to enhance the profitability of the Shreveport refinery’s specialty products segment by increasing overall refinery throughput. Further, in the second quarter of 2008 we completed an expansion project at our Shreveport refinery to increase throughput capacity and feedstock flexibility. Please read “—Liquidity and Capital Resources — Capital Expenditures.”

On January 3, 2008, we closed the acquisition of Penreco, a Texas general partnership, for a purchase price of approximately $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 includes facilities in Karns City, Pennsylvania and Dickinson, Texas, as well as several long-term supply agreements with ConocoPhillips Company. We funded the transaction using a percentage of the proceeds from a public equity offering and a percentage of the proceeds from 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 strategic benefits, including market synergies within our solvents and lubricating oil product lines, additional operational and logistics flexibility and overhead cost reductions resulting from the acquisition. The acquisition also broadens our customer base and gives the Company access to new markets.

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.

High crude oil prices posed significant challenges for us during the three quarters ended June 30, 2008. Market prices for crude oil have declined from a high of $140.21 per barrel during the quarter ended June 30, 2008 to $100.64 per barrel by September 30, 2008. As of October 31, 2008, the market price for crude oil had declined to $67.81 per barrel. As a result, we have experienced significant improvement in specialty products gross profit. However, we are still working through this unprecedented period of crude oil price volatility. In response to this volatility, we have implemented multiple rounds of specialty product price increases to customers over the last several quarters and we are working diligently on other strategic initiatives, including optimizing our new assets from our Shreveport refinery expansion project and Penreco acquisition,

using derivative instruments to mitigate the risk of price fluctuations in specialty products, crude oil input prices, and working capital reductions. For further discussion of our strategic initiatives and our progress on such initiatives during the third quarter of 2008, please read “Liquidity and Capital Resources — Debt and Credit Facilities.” While we are taking steps to mitigate the adverse impact of this volatile environment on our operating results, we can provide no assurances as to the sustainability of the improvements in our operating results that were achieved during the third quarter of 2008 and to the extent we experience further periods of rapidly escalating or declining crude oil prices, our operating results and liquidity could be adversely affected.

As announced on October 15, 2008, we declared a quarterly cash distribution of $0.45 per unit on all outstanding units for the three months ended September 30, 2008. Our general partner determined that maintaining the distribution at $0.45 per unit consistent with the prior quarter was prudent given our current financial condition and general economic conditions.

Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our control. We monitor these risks and enter into financial derivatives designed to mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities which do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Item 3 “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” As of September 30, 2008, we have hedged approximately 20.8 million barrels of fuel products through December 2011 at an average refining margin of $11.53 per barrel with average refining margins ranging from a low of $11.20 per barrel in 2010 to a high of $12.42 per barrel for the remainder of 2008. As of September 30, 2008, we have 2.1 million barrels of crude oil options through December 2009 to hedge our purchase of crude oil for specialty products production. The strike prices and types of 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 fuel products sold as an important measure of our ability to effectively utilize our refining assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.

Production yields. 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 and Nine Months Ended September 30, 2008 and 2007 Results of Operations

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Total sales volume (bpd)(1)		57,054		49,108		58,938		47,435
Total feedstock runs (bpd)(2)		57,263		51,305		57,985		48,758
Facility production (bpd)(3):
Specialty products:
Lubricating oils		13,257		10,768		13,108		10,785
Solvents		7,779		5,294		8,489		5,162
Waxes		1,518		1,287		1,851		1,177
Fuels		1,141		1,798		1,157		1,985
Asphalt and other by-products		6,691		6,980		6,872		6,254

Total		30,386		26,127		31,477		25,363

Fuel products:
Gasoline		8,394		7,651		8,636		7,382
Diesel		10,548		6,309		10,580		5,627
Jet fuel		6,613		8,627		6,089		7,922
By-products		271		1,409		344		1,618

Total		25,826		23,996		25,649		22,549

Total facility production		56,212		50,123		57,126		47,912

____________

(1)

Total sales volume includes sales from the production of our facilities and sales of inventories.

(2)

Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities. The increase in feedstock runs for the three and nine months ended September 30, 2008 was primarily due to feedstock runs at our operations acquired in the Penreco acquisition which closed in January 2008, as well as increased crude oil runs at our Shreveport refinery due to the startup of the Shreveport refinery expansion. The increase due to the Shreveport refinery expansion was lower than expected primarily as a result of lower crude oil supply due to hurricanes Ike and Gustav, unscheduled downtime at the Shreveport refinery due to hurricane Ike, and reduced production rates due to incremental refining economics associated with the cost of crude oil early in the third quarter of 2008.

(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. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of end 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						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In millions)
Sales	$	724.4		$	428.1		$	1,990.3		$	1,200.9
Cost of sales		647.4			390.2			1,817.6			1,047.5

Gross profit		77.0			37.9			172.7			153.4

Operating costs and expenses:
Selling, general and administrative		12.0			4.2			29.7			16.1
Transportation		21.7			13.2			66.7			40.8
Taxes other than income taxes		1.3			1.0			3.4			2.7
Other		0.4			2.3			0.9			2.6

Operating income		41.6			17.2			72.0			91.2

Other income (expense):
Interest expense		(10.7	)		(1.3	)		(24.4	)		(3.5	)
Interest income		—			0.3			0.3			1.8
Debt extinguishment costs		—			(0.3	)		(0.9	)		(0.3	)
Realized gain loss derivative instruments		(12.6	)		(3.9	)		(13.0	)		(9.7	)
Unrealized loss on derivative instruments		(30.9	)		(2.4	)		(13.9	)		(3.9	)
Gain on sale of mineral rights		—			—			5.8			—
Other		0.2			—			0.3			(0.1	)

Total other expense		(54.0	)		(7.6	)		(45.8	)		(15.7	)

Net income (loss) before income taxes		(12.4	)		9.6			26.2			75.5
Income taxes		0.1			0.1			0.3			0.4

Net income (loss)	$	(12.5	)	$	9.5		$	25.9		$	75.1

EBITDA	$	13.6		$	14.7		$	91.3		$	90.0

Adjusted EBITDA	$	51.6		$	20.3		$	114.4		$	96.3

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 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, discount 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); (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.

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 test thereunder. On January 3, 2008, we entered into a new senior secured term loan credit facility and amended our existing senior secured revolving credit facility. Our new agreements require us to maintain a consolidated leverage ratio of consolidated debt to Adjusted EBITDA, after giving effect to any proposed distributions, of no greater than 4.0 to 1 in order to make distributions to our unitholders, with a step down to a ratio of 3.75 to 1 starting with the quarter ended June 30, 2009. Please refer to “—Liquidity and Capital Resources — Debt and Credit Facilities” within this item for additional details regarding debt covenants.

EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss), operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP. 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 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					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008		2007
	(In millions)					(In millions)
Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA:
Net income (loss)	$	(12.5	)	$	9.5	$	25.9	$	75.1
Add:
Interest expense and debt extinguishment costs		10.7			1.7		25.3		3.8
Depreciation and amortization		15.3			3.4		39.8		10.7
Income tax expense		0.1			0.1		0.3		0.4

EBITDA	$	13.6		$	14.7	$	91.3	$	90.0

Add:
Unrealized loss from mark to market accounting for hedging activities	$	33.4		$	3.4	$	15.2	$	5.0
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		4.6			2.2		7.9		1.3

Adjusted EBITDA	$	51.6		$	20.3	$	114.4	$	96.3


	Nine Months Ended
	September 30,
	2008			2007
	(In millions)
Reconciliation of Adjusted EBITDA and EBITDA to net cash provided by operating activities:
Adjusted EBITDA	$	114.4		$	96.3
Add:
Unrealized loss from mark to market accounting for hedging activities	$	(15.2	)	$	(5.0	)
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		(7.9	)		(1.3	)

EBITDA	$	91.3		$	90.0

Add:
Interest expense and debt extinguishment costs, net		(22.7	)		(3.5	)
Unrealized loss on derivative instruments		13.9			3.9
Income tax expense		(0.3	)		(0.4	)
Provision for doubtful accounts		1.3			—
Debt extinguishment costs		0.9			0.3
Changes in assets and liabilities:
Accounts receivable		(64.4	)		(18.2	)
Inventories		84.6			9.6
Other current assets		4.6			1.8
Derivative activity		7.5			1.1
Accounts payable		(39.5	)		45.0
Other current liabilities		4.2			(1.2	)
Other, including changes in noncurrent assets and liabilities		(5.7	)		(2.6	)

Net cash provided by operating activities	$	75.7		$	125.8

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Sales. Sales increased $296.3 million, or 69.2%, to $724.4 million in the three months ended September 30, 2008 from $428.1 million in the three months ended September 30, 2007. Sales for each of our principal product categories in these periods were as follows:


	Three Months Ended September 30,
	2008		2007		% Change
	(Dollars in millions)
Sales by segment:
Specialty products:
Lubricating oils	$	271.4	$	116.7		132.5	%
Solvents		118.7		49.5		139.9	%
Waxes		39.6		20.3		95.3	%
Fuels (1)		7.7		12.1		(36.2	)%
Asphalt and by-products (2)		48.8		21.0		131.7	%

Total specialty products	$	486.2	$	219.6		121.3	%

Total specialty products sales volume (in barrels)		2,619,000		2,097,000		24.9	%
Fuel products:
Gasoline	$	82.6	$	80.1		3.1	%
Diesel		96.1		53.9		78.4	%
Jet fuel		57.3		64.3		(10.8	)%
By-products (3)		2.2		10.2		(78.5	)%

Total fuel products	$	238.2	$	208.5		14.3	%

Total fuel products sales volume (in barrels)		2,630,000		2,421,000		8.6	%
Total sales	$	724.4	$	428.1		69.2	%

Total sales volume (in barrels)		5,249,000		4,518,000		16.2	%


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

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

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

This $296.3 million increase in sales resulted from a $266.5 million increase in sales in the specialty products segment and a $29.8 million increase in sales in the fuel products segment.

Specialty products segment sales for the three months ended September 30, 2008 increased $266.5 million, or 121.3%, primarily due to a 24.9% increase in sales volume, from approximately 2.1 million barrels in the third quarter of 2007 to 2.6 million barrels in the third quarter of 2008, primarily due to an additional 0.6 million barrels of sales volume of lubricating oils, solvents and waxes from our operations acquired in the Penreco acquisition which closed in January 2008. Excluding sales volume associated with our operations acquired in the Penreco acquisition, our specialty products sales volume decreased slightly due to lower sales volume of solvents, waxes and fuels. These decreases were partially offset by increased lubricating oil sales due to increased production from the Shreveport refinery expansion project. Specialty segment sales were also positively affected by a 70.9% increase in the average selling price per barrel of specialty products at our Shreveport, Princeton and Cotton Valley refineries as compared to the prior period due to increases in sales prices for all specialty products, with lubricating oils and solvents demonstrating the largest sales price increases. These sales price increases were implemented in response to the rising cost of crude oil experienced over the last several quarters. Prior to the third quarter of 2008 we were unable to increase sales prices at rates comparable to the increase in the cost of crude oil. During the third quarter of 2008, average selling prices per barrel for specialty products increased at rates greater than the overall 58.7% increase in our cost of crude oil per barrel over the prior period.

Fuel products segment sales for the three months ended September 30, 2008 increased $29.8 million, or 14.3%, primarily due to a 52.6% increase in the average selling price per barrel for fuel products primarily driven by increases in diesel sales prices due to market conditions as compared to a 58.7% increase in the average cost of crude oil. Fuel products sales were also positively affected by a 8.6% increase in fuel products sales volume, from approximately 2.4 million barrels in the third quarter of 2007 to approximately 2.6 million barrels in the third quarter of 2008, primarily driven by diesel sales volume. The increase in diesel sales volume was primarily due to the startup of the Shreveport refinery expansion project in May 2008 and shifts in product mix from jet fuel to diesel. These increases in sales due to pricing and volume were partially offset by increased derivative losses of $114.1 million on our fuel products hedges in the third quarter of 2008 as compared to the same period in the prior year. Please see the Gross Profit discussion for the net impact of our crude oil and fuel products derivative instruments designated as cash flow hedges.

Gross Profit. Gross profit increased $39.1 million, or 103.2%, to $77.0 million for the three months ended September 30, 2008 from $37.9 million for the three months ended September 30, 2007. Gross profit for our specialty and fuel products segments was as follows:


	Three Months Ended September 30,
	2008			2007			% Change
	(Dollars in millions)
Gross profit by segment:
Specialty products	$	66.1		$	21.7			205.2	%
Percentage of sales		13.6	%		9.9	%
Fuel products	$	10.9		$	16.2			(32.8	)%
Percentage of sales		4.6	%		7.8	%
Total gross profit	$	77.0		$	37.9			103.2	%
Percentage of sales		10.6	%		8.9	%

This $39.1 million increase in total gross profit includes an increase in gross profit of $44.4 million in the specialty products segment and a $5.3 million decrease in gross profit in the fuel products segment.

The increase in the specialty products segment gross profit was primarily due to price increases on the majority of our specialty products implemented in response to the rising cost of crude oil experienced early in 2008. Excluding sales resulting from our operations acquired in the Penreco acquisition, the average selling price per barrel of our specialty products increased by approximately 70.9%, while the average cost of crude oil increased by approximately 58.7% from the third quarter of 2007 to the third quarter of 2008. This increase was primarily due to increases in sales prices for all specialty products, with lubricating oils and solvents experiencing the largest sales price increases. Specialty products segment gross profit was also positively impacted by increased derivative gains of $3.3 million in the third quarter of 2008 as compared to the same period in the prior year. Specialty products gross profit was negatively impacted by increased operating costs, primarily driven by increased plant fuel and electricity.

The decrease in the fuel products segment gross profit was primarily due to increased derivative losses of $14.8 million in the third quarter of 2008 as compared to the same period in the prior year. In addition, the rising cost of crude oil outpaced increases in the selling price per barrel of our fuel products. The average cost of crude oil increased by approximately 58.7% from the third quarter of 2007 to the third quarter of 2008 while the average selling price per barrel of our fuel products increased by only 52.6%, primarily driven by diesel fuel selling prices due to market conditions. The overall decrease due to increased derivative losses and crude oil cost increases were partially offset by an 8.6% increase in fuel products sales volume, from approximately 2.4 million barrels in the third quarter of 2007 to approximately 2.6 million barrels in the third quarter of 2008, primarily driven by increased diesel sales volume. The increase in diesel sales volume was primarily due to the startup of the Shreveport refinery expansion project in May 2008 and shifts in product mix from jet fuel to diesel.

Selling, general and administrative. Selling, general and administrative expenses increased $7.8 million, or 183.2%, to $12.0 million in the three months ended September 30, 2008 from $4.2 million in the three months ended September 30, 2007. This increase was primarily due to additional selling, general and administrative expenses associated with the Penreco acquisition, which closed on January 3, 2008, with no similar expenses in the comparable period in the prior year. Selling, general and administrative expenses also increased due to additional accrued incentive compensation costs in the three months ended September 30, 2008 as compared to the same period in 2007.

Transportation. Transportation expenses increased $8.4 million, or 63.8%, to $21.7 million in the three months ended September 30, 2008 from $13.2 million in the three months ended September 30, 2007. This increase was primarily related to additional transportation expenses associated with increased sales from the Penreco acquisition, which closed on January 3, 2008, with no similar expenses in the comparable period in the prior year.

Interest expense. Interest expense increased $9.3 million to $10.7 million in the three months ended September 30, 2008 from $1.3 million in the three months ended September 30, 2007. This increase was primarily due to an increase in indebtedness as a result of our new senior secured term loan facility, which closed on January 3, 2008 and includes a $385.0 million term loan partially used to finance the acquisition of Penreco, as well as increased borrowings on our revolving credit facility as a result of higher than expected capital expenditures to complete the Shreveport refinery expansion project.

Interest income. Interest income decreased $0.3 million in the three months ended September 30, 2008 from $0.3 million in the three months ended September 30, 2007. This decrease was primarily due to a larger average cash and cash equivalents balance during the third quarter of 2007 as compared to the same period in 2008 due to the utilization of cash for capital expenditures on the Shreveport refinery expansion project.

Realized loss on derivative instruments. Realized loss on derivative instruments increased $8.8 million to $12.6 million in the three months ended September 30, 2008 from $3.9 million for the three months ended September 30, 2007. This increased loss primarily was the result of the unfavorable settlement in the third quarter of 2008 of certain derivative instruments not designated as cash flow hedges as compared to 2007, including certain crude oil collars and natural gas swaps related to our increased derivative activity in our specialty products segment.

Unrealized loss on derivative instruments. Unrealized loss on derivative instruments increased $28.4 million to $30.9 million in the three months ended September 30, 2008 from $2.4 million for the three months ended September 30, 2007. This increase is primarily due to the unfavorable mark-to-market change for certain crude oil collar derivatives in our specialty products segment not designated as cash flow hedges.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Sales. Sales increased $789.4 million, or 65.7%, to $1,990.3 million in the nine months ended September 30, 2008 from $1,200.9 million in the nine months ended September 30, 2007. Sales for each of our principal product categories in these periods were as follows:


	Nine Months Ended September 30,
	2008		2007		% Change
	(Dollars in millions)
Sales by segment:
Specialty products:
Lubricating oils	$	672.0	$	358.0		87.7	%
Solvents		343.7		150.9		127.8	%
Waxes		111.0		45.9		141.6	%
Fuels(1)		27.3		38.2		(28.6	)%
Asphalt and by-products(2)		114.6		55.6		106.3	%

Total specialty products	$	1,268.6	$	648.6		95.6	%

Total specialty products sales volume (in barrels)		8,279,000		6,416,000		29.0	%
Fuel products:
Gasoline	$	259.5	$	210.4		23.3	%
Diesel		302.5		154.0		96.4	%
Jet fuel		149.0		157.0		(5.1	)%
By-products(3)		10.7		30.9		(65.3	)%

Total fuel products	$	721.7	$	552.3		30.7	%

Total fuel products sales volume (in barrels)		7,870,000		6,534,000		20.5	%
Total sales	$	1,990.3	$	1,200.9		65.7	%

Total sales volume (in barrels)		16,149,000		12,950,000		24.7	%


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

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

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

This $789.4 million increase in sales resulted from a $620.0 million increase in our specialty products segment and a $169.4 million increase in our fuel products segment.

Specialty products segment sales for the nine months ended September 30, 2008 increased $620.0 million, or 95.6%, primarily due to a 29.0% increase in volumes sold, from approximately 6.4 million barrels in the nine months ended September 30, 2007 to 8.3 million barrels in the nine months ended September 30, 2008 primarily due to an additional 1.9 million barrels of sales volume of lubricating oils, solvents and waxes from our operations acquired in the Penreco acquisition which closed in January 2008. Excluding sales volume associated with our operations acquired in the Penreco acquisition, our specialty products sales volume decreased slightly primarily due to lower fuels and solvents sales volume. These decreases were partially offset by increased lubricating oil sales volume due to increased production from the Shreveport refinery expansion project. Specialty products segment sales were also positively affected by a 43.1% increase in the average selling price per barrel of specialty products at our Shreveport, Princeton and Cotton Valley refineries compared to the prior period due to price increases in all specialty products, with lubricating oils and solvents experiencing the largest sales price increases. The sales price increases were implemented in response to the rising cost of crude oil experienced in the last several quarters. Average selling prices per barrel for specialty products increased at rates lower than the overall 70.1% increase in the cost of crude oil per barrel over the prior period.

Fuel products segment sales for the nine months ended September 30, 2008 increased $169.4 million, or 30.7%, primarily due to a 56.1% increase in the average selling price per barrel as compared to a 69.9% increase in the average cost of crude oil per barrel. The increased sales price per barrel was primarily a result of increases in price for diesel due to market conditions. Fuel products segment sales were also positively affected by a 20.5% increase in sales volumes, from approximately 6.5 million barrels in the nine months ended September 30, 2007 to 7.9 million barrels in the nine months ended September 30, 2008, primarily driven by diesel sales volume. The increase in diesel sales volume was due primarily to the startup of the Shreveport refinery expansion project in May 2008 and shifts in product mix from jet fuel to diesel. The increase due to sales volume and sales prices was offset by a $318.6 million increase in derivative losses on our fuel products cash flow hedges recorded in sales. Please see the Gross Profit discussion for the net impact of our crude oil and fuel products derivative instruments designated as cash flow hedges.

Gross Profit. Gross profit increased $19.3 million, or 12.6%, to $172.7 million for the nine months ended September 30, 2008 from $153.4 million for the nine months ended September 30, 2007. Gross profit for our specialty and fuel products segments were as follows:


	Nine Months Ended September 30,
	2008			2007			% Change
	(Dollars in millions)
Gross profit by segment:
Specialty products	$	109.9		$	103.1			6.7	%
Percentage of sales		8.7	%		15.9	%
Fuel products	$	62.8		$	50.3			24.7	%
Percentage of sales		8.7	%		9.1	%
Total gross profit	$	172.7		$	153.4			12.6	%
Percentage of sales		8.7	%		12.8	%

This $19.3 million increase in total gross profit includes an increase in gross profit of $6.9 million in our specialty product segment and a $12.4 million increase in gross profit in our fuels product segment.

The increase in the specialty products segment gross profit was primarily due to a 29.0% increase in sales volume, from approximately 6.4 million barrels in the nine months ended September 30, 2007 to 8.3 million barrels in the nine months ended September 30, 2008, primarily due to an additional 1.9 million barrels of sales volume of lubricating oils, solvents and waxes from our operations acquired in the Penreco acquisition. Excluding sales volume associated with our operations acquired for the Penreco acquisition, our specialty products sales volume decreased slightly primarily due to lower fuels and solvents sales volume. These decreases were partially offset by increased lubricating oil sales due to increased production from the Shreveport refinery expansion project. Specialty products segment gross profit was also positively affected by increased derivative gains of $22.4 million in the nine months ended September 30, 2008 as compared to the same period in the prior year. In addition, we recognized lower cost of sales of $39.1 million in the nine months ended September 30, 2008 from the same period in the prior year in our specialty products segment from the liquidation of lower cost inventory layers as a result of the Company’s working capital reduction initiative. These increases were partially offset by the impacts of the rising cost of crude oil as we were unable to increase selling prices at rates comparable to increases in crude oil costs. Excluding sales resulting from our operations acquired in the Penreco acquisition, the average selling price per barrel of our specialty products increased by 43.1%, while the average cost of crude oil increased by approximately 70.1% from the nine months ended September 30, 2007 to the nine months ended September 30, 2008. This increase was due to sales price increases for all specialty products, with lubricating oils and solvents experiencing the largest sales price increases. Specialty products segment gross profit was also negatively impacted by increased operating costs, primarily driven by increased plant fuel and electricity.

The increase in fuel products segment gross profit was primarily due to a 20.5% increase in fuel products sales volume, from approximately 6.5 million barrels in the nine months ended September 30, 2007 to approximately 7.9 million barrels in the nine months ended September 30, 2008, primarily driven by increased gasoline and diesel sales volume. The increase in gasoline and diesel sales volume was primarily due to the startup of the Shreveport refinery expansion project in May 2008 and shifts in product mix from jet fuel to diesel. In addition, we recognized lower cost of sales of $6.7 million in the nine months ended September 30, 2008 from the same period in the prior year in our fuel products segment from the liquidation of lower cost inventory layers as a result of the Company’s working capital reduction initiative. These increases were partially offset by the rising cost of crude oil outpacing increases in the selling price per barrel of our fuel products. The average cost of crude oil increased by approximately 69.9% from the nine months ended September 30, 2007 to the same period in 2008 while the average selling price per barrel of our fuel products increased by only 56.1%, primarily driven by gasoline and diesel selling prices due to market conditions. Fuel products segment gross profit was also negatively impacted by increased derivative losses of $10.8 million in the nine months ended September 30, 2008 as compared to the same period in the prior year.

Selling, general and administrative. Selling, general and administrative expenses increased $13.6 million, or 84.6%, to $29.7 million in the nine months ended September 30, 2008 from $16.1 million in the nine months ended September 30, 2007. This increase is primarily due to additional selling, general and administrative expenses associated with the Penreco acquisition, which closed on January 3, 2008, with no similar expenses in the comparable period in the prior year. Selling, general and administrative expenses also increased due to additional accrued incentive compensation costs in the nine months ended September 30, 2008 as compared to the same period in 2007.

Transportation. Transportation expenses increased $25.9 million, or 63.3%, to $66.7 million in the nine months ended September 30, 2008 from $40.8 million in the nine months ended September 30, 2007. This increase was primarily related to additional transportation expenses associated with increased sales from the Penreco acquisition, which closed on January 3, 2008, with no similar expenses in the comparable period in the prior year.

Interest expense. Interest expense increased $20.9 million, or 601.6%, to $24.4 million in the nine months ended September 30, 2008 from $3.5 million in the nine months ended September 30, 2007. This increase was primarily due to an increase in indebtedness as a result of a new senior secured term loan facility, which closed on January 3, 2008 and includes a $385.0 million term loan partially used to finance the acquisition of Penreco, as well as increased borrowings on our revolving credit facility due to higher than expected capital expenditures to complete the Shreveport refinery expansion project. This increase was partially offset by an increase in capitalized interest as a result of increased capital expenditures on the Shreveport refinery expansion project.

Interest income. Interest income decreased $1.5 million to $0.3 million in the nine months ended September 30, 2008 from $1.8 million in the nine months ended September 30, 2007. This decrease was primarily due to a larger average cash and cash equivalents balance during the nine months ended September 30, 2007 as compared to the same period in 2008 due to the utilization of cash for capital expenditures on the Shreveport refinery expansion project.

Debt extinguishment costs. Debt extinguishment costs increased $0.6 million in the nine months ended September 30, 2008 as compared to $0.3 million in the nine months ended September 30, 2007. This increase was primarily due to the repayment of our prior senior secured term loan facility with a portion of the proceeds of our new senior secured term loan facility, which closed on January 3, 2008. The increase was also the result of debt extinguishment costs recognized in conjunction with the repayment of a portion of our new senior secured term loan facility using the proceeds of the sale of mineral rights on our real property at our Shreveport and Princeton refineries.

Realized loss on derivative instruments. Realized loss on derivative instruments increased $3.3 million to $13.0 million in the nine months ended September 30, 2008 from $9.7 million in the nine months ended September 30, 2007. This increased loss was primarily the result of the unfavorable settlement of certain derivative instruments not designated as cash flow hedges in the nine months ended September 30, 2008 as compared to the same period in 2007, including certain crude oil collars and natural gas swaps related to our increased derivative activity in our specialty products segment.

Unrealized loss on derivative instruments. Unrealized loss on derivative instruments increased $9.9 million, to $13.9 million in the nine months ended September 30, 2008 from $3.9 million for the nine months ended September 30, 2007. This increased loss is primarily due to the unfavorable mark-to-market changes for certain derivative instruments in our specialty products segment not designated as cash flow hedges, including crude oil collars, natural gas swap contracts, and interest rate swap contracts, being recorded to unrealized loss on derivative instruments in the nine months ended September 30, 2008 as compared to the same period in 2007.

Gain on sale of mineral rights. Gain on sale of mineral rights was $5.8 million for the nine months ended September 30, 2008 as compared to $0 for the nine months ended September 30, 2007. This increase was due to a gain of $5.8 million resulting from the lease of mineral rights on the real property at our Shreveport and Princeton refineries to an unaffiliated third party which has been accounted for as a sale. We have retained a royalty interest in any future production associated with these mineral rights.

Liquidity and Capital Resources

Our principal sources of cash have included cash flow from operations, proceeds from public equity offerings, issuance of private debt, 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 or internal growth projects which would cause total spending to exceed approximately 5.0 million during the fourth quarter of 2008. During 2009, we anticipate any capital expenditures will be funded with current cash flow from operations. Historically, we have entered into confidentiality agreements, letters of intent and other preliminary agreements with third parties in the ordinary course of business as we evaluate potential growth opportunities for our business. Our compliance with these agreements could result in additional costs, such as engineering fees, legal fees, consulting fees, and/or termination fees that we do not anticipate to be material to our liquidity or operations.

Cash Flows

We believe that we have sufficient cash flow from operations and borrowing capacity to meet our financial commitments, 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, 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. Please refer to “— Debt and Credit Facilities” within this section for additional details.

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


	Nine Months Ended
	September 30,
	2008			2007
	(In millions)
Net cash provided by operating activities	$	75.7		$	125.8
Net cash used in investing activities	$	(430.9	)	$	(165.4	)
Net cash provided by (used in) financing activities	$	355.3		$	(41.3	)

Operating Activities. Operating activities provided $75.7 million in cash during the nine months ended September 30, 2008 compared to $125.8 million during the nine months ended September 30, 2007. The decrease in cash provided by operating activities during the nine months ended September 30, 2008 was primarily due to increased working capital of $37.8 million, combined with a reduction of net income, after adjusting for non-cash items, of $12.3 million. The increase in working capital of $37.8 million was due primarily to the decrease in accounts payable resulting from the increased payment of capital expenditures related to the completed Shreveport refinery expansion project and increased accounts receivable due to the increased sales price of specialty products prices. These reductions were offset by the significant decrease in inventory as a result of our working capital reduction initiatives. Net income, after adjustments for non-cash items, decreased by $12.3 million for the nine months ended September 30, 2008 from $93.1 million in the same period in 2007 primarily due to the rising cost of crude oil outpacing increases in selling prices of products and increased interest expense.

Investing Activities. Cash used in investing activities increased to $430.9 million during the nine months ended September 30, 2008 compared to $165.4 million during the nine months ended September 30, 2007. This increase was primarily due to the acquisition of the asset and liabilities of Penreco on January 3, 2008 for $269.1 million, net of cash received, with no similar acquisition activities in the prior year. This increase was also due to $6.0 million of settlement payments made related to certain derivative instruments not designated as cash flow hedges. Offsetting this increase was a decrease due to $3.6 million of less capital expenditures in the nine months ended September 30, 2008 over the same period in 2007. The majority of the capital expenditures were incurred at our Shreveport refinery, with $118.2 million related to the Shreveport refinery expansion project incurred in the nine months ended September 30, 2008 as compared to $126.3 million incurred during the comparable period in 2007. Offsetting this decrease was $4.5 million primarily related to more spending on various other capital projects at our Shreveport refinery compared to the prior period. Further offsetting the increased use of cash was the $6.1 million of cash proceeds received as a result of selling the mineral rights on our real property at our Shreveport and Princeton refineries to a third party during the second quarter of 2008.

Financing Activities. Financing activities provided cash of $355.3 million for the nine months ended September 30, 2008 compared to using cash of $41.3 million for the nine months ended September 30, 2007. This change is primarily due to borrowings under the new senior secured term loan credit facility, which closed on January 3, 2008, along with associated debt issuance costs. A portion of the new term loan proceeds of $385.0 million was used to finance the acquisition of Penreco. The increase was also due to a $51.9 million increase in borrowings on our revolving credit facility, primarily due to spending on the Shreveport refinery expansion project. This increase was offset by a decrease in distributions to partners of $5.9 million.

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.


	Nine Months Ended
	September 30,
	2008		2007
	(in millions)
Capital improvement	$	157.7	$	156.0
Replacement capital	$	2.6	$	8.5
Environmental capital	$	1.5	$	1.0

Total	$	161.8	$	165.5

We anticipate that future capital expenditure requirements will be funded through cash provided by operations and available borrowings under our existing revolving credit facility unless debt and equity capital markets improve in the near term. Management expects to invest up to approximately $5.0 million in expenditures at its various locations on a quarterly basis to improve our product mix or operating cost leverage. In addition, management estimates its maintenance and environmental capital expenditures to be approximately $3.7 million per quarter. Our Shreveport refinery expansion project and the Penreco acquisition have demonstrated an increase in cash flow from operations on a per unit basis which has restored our ability to issue common units in certain circumstances back to the maximum level defined in our Partnership Agreement, or 6,533,000 common units.

During 2008 and 2007, we have invested significantly in expanding and enhancing the operations of our Shreveport refinery. We have invested a total of approximately $157.7 million and $156.0 million in capital improvements primarily at Shreveport during the nine months ended September 30, 2008 and 2007, respectively. Of these investments during these periods, $118.2 million relates to our Shreveport expansion project. From December 31, 2005 through September 30, 2008, the Company has invested approximately $481.3 million in the Shreveport refinery, of which $372.6 million relates to the Shreveport refinery expansion project.

The Shreveport expansion project was completed and operational in May 2008. The Shreveport expansion project has increased this refinery’s throughput capacity from 42,000 bpd to 60,000 bpd. For the three months ended September 30, 2008, the Shreveport refinery had total feedstock runs of 39,000 bpd, which represents an increase of approximately 4,000 bpd from the first quarter of 2008, before completion of the Shreveport expansion project. The Shreveport refinery did not experience a significant increase in feedstock runs due primarily to lower crude oil supply due to hurricanes Ike and Gustav, unscheduled downtime at the Shreveport refinery due to hurricane Ike, and reduced production rates due to incremental refining economics associated with the cost of crude oil early in the third quarter of 2008. As part of this project, we have enhanced the Shreveport refinery’s ability to process sour crude oil. During the third quarter, we processed approximately 13,000 bpd of sour crude oil at the Shreveport refinery and after the completion of planned turnaround activities on certain operating units in November 2008, we anticipate running up to 19,000 bpd of sour crude oil at the Shreveport refinery. In certain operating scenarios where overall throughput is reduced, we expect we will be able to increase sour crude oil throughput rates up to approximately 25,000 bpd.

Additionally, for the year ended December 31, 2007 and the nine months ended September 30, 2008, we had invested $65.6 million and $37.5 million, respectively, in our Shreveport refinery for other capital expenditures including projects to improve efficiency, de-bottleneck certain operating units and for new product development. These expenditures are anticipated to enhance and improve our product mix and operating cost leverage, but will not significantly increase the feedstock throughput capacity of the Shreveport refinery. The remaining expenditures for 2008 related to these projects will place in service the majority of our construction in progress and are expected to be less than $5.0 million. Currently, we have $46.8 million in construction in progress. Management estimates that by March 31, 2009, we will have $39.1 million placed in service with the remaining $7.7 million to be placed in service later in 2009 when certain permits are received and as funding is obtained from cash flow from operations or other sources.

Debt and Credit Facilities

On January 3, 2008, we repaid all of our indebtedness under our previous senior secured first lien term loan credit facility, entered into a new senior secured first lien term loan facility and amended our existing senior secured revolving credit facility. As of September 30, 2008, 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 term loan credit facility consisting of a $385.0 million term loan facility and a $50.0 million prefunded letter of credit facility to support crack spread hedging. In connection with the execution of the above senior secured first lien credit facility, we incurred total debt issuance costs of $23.4 million, including $17.4 million of issuance 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 can fluctuate based on changes in selling prices of our products and our current material costs, primarily 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 ten lenders with total commitments of $375.0 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.

The revolving credit facility 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 measurement of our Consolidated Leverage Ratio discussed below. The revolving credit facility has a first priority lien on our cash, accounts receivable and inventory and a second priority lien on our fixed assets and matures in January 2013. On September 30, 2008, we had availability on our revolving credit facility of $136.5 million, based upon a $303.7 million borrowing base, $74.3 million in outstanding standby letters of credit, and outstanding borrowings of $92.9 million. The recent drop in crude oil prices has improved our profitability; however it has also caused a reduction in the market value of our inventory and resulted in a lower borrowing base. On October 31, 2008, we had availability on our revolving credit facility of $105.5 million, based upon a $266.5 million borrowing base, $40.3 million in outstanding letters of credit, and outstanding borrowings of $120.7 million. We believe that we have sufficient cash flow from operations and borrowing capacity to meet our financial commitments, 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 covenants under our credit facilities. Recent and substantial declines in crude oil prices, if sustained, may materially diminish our borrowing base which is based on the value of our crude oil inventory, which 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. Under the terms of our term loan facility, we applied a portion of the net proceeds to the acquisition of Penreco. 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. In June 2008, we received lease bonuses of $6.1 million associated with the sale of mineral rights on our real property at our Shreveport and Princeton refineries to a non-affiliated third party. As a result of these transactions, we recorded a gain of $5.8 million in other income (expense) in the unaudited condensed consolidated statements of operations. Under the term loan agreement, cash proceeds resulting from the disposition of our property, plant and equipment generally must be used as a mandatory prepayment of the term loan. As a result, we made a prepayment of $6.1 million in June 2008 on the term loan.

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 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.

The credit facilities permit us to make distributions to our unitholders as long as we are not in default and would not be in default following the distribution. Under the credit facilities, we are obligated to comply with certain financial covenants requiring us to maintain a Consolidated Leverage Ratio of no more than 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 of at least $35.0 million (after giving effect to a proposed distribution or other restricted payments as defined in the credit agreements). The Consolidated Leverage Ratio steps down from 4.0 to 1 to 3.75 to 1 and the Consolidated Interest Coverage Ratio steps up from 2.50 to 1 to 2.75 to 1 effective with the quarter ended June 30, 2009. 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. For fiscal year 2008, the credit facilities permit the inclusion of a prorated portion of Penreco’s estimated Adjusted EBITDA from 2007 in measuring compliance with this covenant. 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).

We have experienced adverse financial conditions primarily attributable with historically high crude oil costs, which have negatively affected specialty products gross profit through the period ended June 30, 2008. Also contributing to these adverse financial conditions have been the significant cost overruns and delays in the startup of the Shreveport refinery expansion project. Compliance with the financial covenants pursuant to our credit agreements is tested quarterly based upon performance over the most recent four fiscal quarters, and as of September 30, 2008, we were in compliance with all financial covenants under its credit agreements. Our ability to maintain compliance with these financial covenants in the quarter ended September 30, 2008 was substantially enhanced by the significant increase in specialty products segment gross profit during the third quarter resulting from increased selling prices for specialty products and reductions in the cost of crude oil. We are continuing to take steps to ensure that we meet the requirements of our credit agreements and currently forecast that we will be in compliance for future measurement dates. In addition to continuing to implement multiple specialty product price increases during this volatile period as conditions have warranted, these steps include the following:

Continued Integration of the Penreco Acquisition

Since the acquisition of Penreco on January 3, 2008, we have implemented multiple price increases for these various specialty product lines to attempt to keep pace with rising feedstock costs. In addition, we have implemented a pricing policy which we believe is more responsive to rising feedstock prices to limit the time between feedstock price increases and product price increases to customers. Calumet is also implementing operational strategies, including using various existing Calumet refinery products as feedstocks in the acquired Penreco plant operations and has reduced headcount by approximately 50 employees.

Increased Crude Oil Price Hedging for Specialty Products Segment

We remain committed to an active hedging program to manage commodity price risk in both our specialty products and fuel products segments. Due to the current volatility of the price of crude oil and the impact such volatility has had on our short-term cash flows while our product pricing has adjusted, we have implemented modifications to our hedging strategy to increase the overall portion of input prices for specialty products we may hedge. Specifically, we have targeted the use of derivative instruments to mitigate our exposure to changes in crude oil prices for up to 75% of our specialty products production when conditions warrant. We continue to believe that a shorter-term time horizon of hedging crude oil purchases for 3 to 9 months forward for the specialty products segment is appropriate given our general ability to increase specialty products prices. During the third quarter of 2008 and early in the fourth quarter of 2008, we have also focused on limiting our derivative losses as crude oil prices have continued to decrease. For example, we have purchased 1.2 million barrels of crude oil put options that will expire in November 2008 to limit the derivative losses as well as minimize the requirement to provide credit support to our hedging counterparties in the form of cash margin or standby letters of credit, which reduce our liquidity. We will determine if additional downside protection is needed at which time we may purchase additional crude oil put options with expiration terms beyond November 2008. As a result of our specialty products crude oil hedging activity, we recorded a gain of $3.1 million and a loss $10.7 million, respectively, to cost of goods sold and realized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the three months ended September 30, 2008. For the nine months ended September 30, 2008, we recorded gains of $20.7 million and a loss of $5.6 million, respectively, to cost of goods sold and realized loss on derivative instruments in the unaudited condensed consolidated statements of operations. As of October 31, 2008, we have provided cash margin of $15.4 million in credit support to certain of our hedging counterparties. Please read Item 3 “Quantitative and Qualitative Disclosures about Market Risk — Existing Commodity Derivative Instruments” for derivative instruments outstanding as of September 30, 2008.

Working Capital Reduction

We have implemented strategies to minimize inventory levels across all of our facilities to reduce working capital needs and are now maintaining these reduced levels to minimize borrowing needs. As an example, effective May 1, 2008, we entered into a crude oil supply agreement with an affiliate of our general partner to purchase crude oil used at our Princeton refinery on a just-in-time basis, which will significantly reduce crude oil inventory historically maintained for this facility by approximately 200,000 barrels. Excluding inventory related to the Penreco acquisition, we have reduced our inventory levels by approximately 1,000,000 barrels, or approximately 46.4%.

While assurances cannot be made regarding our future compliance with these covenants and being cognizant of the general uncertain economic environment, we anticipate that our completion of the Shreveport refinery expansion project, our continued integration of the Penreco acquisition, our forecasted capital expenditures, our marketing strategies and other strategic initiatives discussed above will allow us to maintain compliance with such financial covenants and improve our Adjusted EBITDA, liquidity and distributable cash flows.

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 of 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 September 30, 2008.

Contractual Obligations and Commercial Commitments

Certain of our contractual commitments have materially changed since December 31, 2007. Our long-term debt obligations have materially changed due to our new $385.0 million senior secured term loan credit facility as compared to total long-term debt of $39.9 million as of December 31, 2007. Our operating lease obligations have materially changed due to our acquisition of Penreco on January 3, 2008, which had a substantial amount of railcar leases. A summary of these contractual cash obligations as of September 30, 2008, 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	$	468,939	$	3,850	$	7,700	$	7,700	$	449,689
Interest on long-term debt at contractual rates		190,542		34,754		66,736		55,660		33,392
Capital lease obligations		2,891		992		1,419		480		—
Operating lease obligations (1)		47,999		12,608		18,989		11,761		4,641
Letters of credit (2)		124,331		74,331		—		50,000		—
Purchase commitments (3)		334,112		334,112		—		—		—
Employment agreements (4)		833		357		476		—		—

Total obligations	$	1,169,647	$	461,004	$	95,320	$	125,601	$	487,722


(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 September 2015.

(2)		Letters of credit supporting crude oil purchases 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 compensation under the employment agreement of F. William Grube, chief executive officer and president.

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 condensed 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 amongst our counterparties.

The Company’s derivative instruments, consisting of derivative assets and derivative liabilities of $117.8 million as of September 30, 2008, are Level 3 fair value measurement under SFAS 157. The Company’s pension plan investments were $18.1 million as of September 30,2008 and are Level 1 measurements under SFAS 157. The Company’s derivative instruments and pension plan investments are the only assets and liabilities measured at fair value as of September 30, 2008. The Company recorded unrealized losses of derivative instruments and realized losses on derivative instruments of $30.9 million and $12.6 million, respectively, on our derivative instruments for the three months ended September 30, 2008. The decrease in the fair market value of our outstanding derivative instruments from a net liability of $57.5 million as of December 31, 2007 to a net liability of $117.8 million as of September 30, 2008 was primarily due to increases 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 September 30, 2008:


	In millions
Crude oil swaps	$	20.8
Diesel swaps	$	(13.2	)
Gasoline swaps	$	(7.6	)
Crude oil collars	$	1.9
Natural gas swaps	$	0.8

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

Recent Accounting Pronouncements

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. We have adopted the provisions of SFAS 157 as of January 1, 2008, for financial instruments. Although the adoption of SFAS 157 did not materially impact our financial condition, results of operations, or cash flow, we are now required to provide additional disclosures as part of our financial statements.

Our derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of our derivative instruments are with counterparties that have long-term credit ratings of single A or better. These derivative instruments include swap contracts as well as different types of option contracts. See Note 9 to the condensed consolidated financial statements for further information on our derivative instruments and hedging activities. The fair values of swap contracts 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, we obtain this data through surveying our counterparties and performing various analytical tests to validate the data. We determine the fair value of our 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 we obtain inputs via quotes from its counterparties, we verify the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. We also include an adjustment for non- performance risk in the recognized measure of fair value of all of our derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When we are in a net asset position, we use our counterparty’s CDS, or a peer group’s estimated CDS when a CDS for our counterparty is not available. We use our own peer group’s estimated CDS when we are in a net liability position. Based on the use of various unobservable inputs, principally non-performance risk, unobservable inputs in volatility for crude collars and unobservable inputs in forward years for gasoline and diesel, we have categorized these derivative instruments as Level 3. We have 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. These option contracts are also adjusted for non- performance risk as discussed above.

The Company’s investments associated with our 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.

All settlements from derivative contracts that are deemed “effective” 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 statements of operations in the period that the underlying fuel is consumed in operations. Any “ineffectiveness” associated with these derivative contracts, as defined in SFAS 133, are recorded in earnings immediately in unrealized gain/(loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 8 to the unaudited condensed consolidated financial statements for further information on SFAS 133 and hedging.

In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (the “Position”), which amends certain aspects of FASB Interpretation Number 39, Offsetting of Amounts Related to Certain Contracts. The Position permits companies to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The Position is effective for fiscal years beginning after November 15, 2007. We adopted the Position on January 1, 2008 and the adoption did not have a material effect on our financial position, results of operations, or cash flows.

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. We anticipate that the Statement will not have a material effect on our financial position, results of operations, or cash flows.

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, financial performance, and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We currently provide an abundance of information about our hedging activities and use of derivatives in our quarterly and annual filings with the SEC, including many of the disclosures contained within SFAS 161. Thus, we currently do not anticipate the adoption of SFAS 161 will have a material impact on the disclosures already provided.

In March 2008, the 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 actual distributions and the resulting net loss be allocated to capital accounts as specified in our partnership agreement. EITF 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Company is evaluating the potential impacts of EITF 07-4.

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. Early adoption is prohibited. We do not expect the adoption of FSP No. 142-3 to have a material impact on our consolidated results of operations or financial condition.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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.

We are exposed to market risk from fluctuations in interest rates. As of September 30, 2008, we had approximately $468.9 million of variable rate debt. Holding other variables constant (such as debt levels), a one hundred basis point change in interest rates on our variable rate debt as of September 30, 2008 would be expected to have an impact on net income and cash flows for 2008 of approximately $4.7 million.

We have a $375.0 million revolving credit facility as of September 30, 2008, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. We had borrowings of $92.9 outstanding under this facility as of September 30, 2008, bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin.

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. 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 $10.9 million and our fuel product segment cost of sales by $10.9 million on an annual basis based on our results for the three months ended September 30, 2008.

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 our specialty products prices. 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 75% of our anticipated crude oil purchases related to our specialty products production. The tenor of 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. 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 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 $3.6 million on an annual basis based on our results for the three months ended September 30, 2008.

Natural Gas Hedging Policy

We enter into derivative contracts to manage our exposure to natural gas prices. Our policy is generally to enter into natural gas swap contracts during the summer months for 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 $1.00 change in the per barrel selling price of gasoline, diesel, and jet fuel would change our fuel products segment sales by $10.5 million on an annual basis based on our results for the three months ended September 30, 2008.

Fuel Products Hedging Policy

In order to manage our exposure to changes in gasoline, diesel, and jet fuel selling prices, our policy is generally 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 product 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.

The unrealized gain or loss on derivatives at a given point in time is not necessarily indicative of the results realized when such contracts mature. The decrease in the fair market value of our outstanding derivative instruments from a net liability of $57.5 million as of December 31, 2007 to a net liability of $117.8 million as of September 30, 2008 was primarily due to increases in the forward market values of fuel products margins, or cracks spreads, relative to our hedged fuel products margins. Please read Note 9 to our unaudited condensed consolidated financial statements for a discussion of the accounting treatment for the various types of derivative transactions, and a further discussion of our hedging policies.

Existing Commodity Derivative Instruments

As a result of our specialty products crude oil hedging activity, we recorded a gain of $3.1 million and a loss $10.7 million, respectively, to cost of goods sold and realized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the three months ended September 30, 2008. For the nine months ended September 30, 2008, we recorded gains of $20.7 million and a loss of $5.6 million, respectively, to cost of goods sold and realized loss on derivative instruments in the unaudited condensed consolidated statements of operations. As of October 31, 2008, we have provided cash margin of $15.4 million in credit support to certain of our hedging counterparties.

The following tables provide information about our derivative instruments related to our fuel products segment as of September 30, 2008:


Crude Oil Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Fourth Quarter 2008		2,116,000		23,000	$	66.49
Calendar Year 2009		8,212,500		22,500		66.26
Calendar Year 2010		7,482,500		20,500		67.27
Calendar Year 2011		3,009,000		8,244		76.98

Totals		20,820,000
Average price					$	68.20


Diesel Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Fourth Quarter 2008		1,334,000		14,500	$	81.42
Calendar Year 2009		4,745,000		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		13,195,000
Average price					$	82.38


Gasoline Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Fourth Quarter 2008		782,000		8,500		74.62
Calendar Year 2009		3,467,500		9,500		73.83
Calendar Year 2010		2,737,500		7,500		75.10
Calendar Year 2011		638,000		1,748		83.42

Totals		7,625,000
Average price					$	75.17

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


					Implied
					Crack
					Spread
Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Fourth Quarter 2008		2,116,000		23,000	$	12.42
Calendar Year 2009		8,212,500		22,500		11.43
Calendar Year 2010		7,482,500		20,500		11.20
Calendar Year 2011		3,009,000		8,244		11.99

Totals		20,820,000
Average price					$	11.53

The following tables provide information about our derivative instruments related to our specialty products segment as of September 30, 2008:

At September 30, 2008, the Company had the following four-way crude oil collar derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $1.2 million of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					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)
October		124,000		4,000	$	92.98	$	102.98	$	112.98	$	122.98
November		120,000		4,000		92.98		102.98		112.98		122.98
December		124,000		4,000		92.98		102.98		112.98		122.98

Totals		368,000
Average price					$	92.98	$	102.98	$	112.98	$	122.98

At September 30, 2008, the Company had the following three-way crude oil collar derivatives related to crude oil purchases in our specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $11.7 million of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					Average		Average		Average
					Sold Put		Bought Call		Sold Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)
October		341,000		11,000	$	109.28	$	127.01	$	135.92
November		300,000		10,000		109.53		127.45		136.35
December		310,000		10,000		109.53		127.45		136.35

Totals		951,000
Average price					$	109.44	$	127.29	$	136.20

At September 30, 2008, the Company had the following two-way crude oil collar derivatives related to crude oil purchases in our specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $5.1 million of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					Average		Average
					Sold Put		Bought Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
Fourth Quarter 2008		276,000		3,000	$	98.85	$	135.00
First Quarter 2009		180,000		2,000		112.05		145.00
Second Quarter 2009		91,000		1,000		111.45		145.00
Fourth Quarter 2009		276,000		3,000		86.40		120.00

Totals		823,000
Average Price					$	98.95	$	133.26

At September 30, 2008, the Company had purchased the following put option derivatives related to crude oil purchases in its specialty products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $0.1 million in unrealized gain on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


					Average
					Bought Put
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
October 2008		279,000		9,000	$	87.67

Totals		279,000
Average price					$	87.67

At September 30, 2008, the Company had the following derivatives related to natural gas purchases, of which 180,000 MMBtus are designated as hedges. As a result of a portion of these derivatives not being designated as hedges, the Company recognized $1.8 million of losses in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2008.


Natural Gas Swap Contracts by Expiration Dates	MMBtus		$/MMBtu
Fourth Quarter 2008		430,000	$	10.25
First Quarter 2009		330,000		10.38

Totals		760,000
Average price			$	10.31

As of October 31, 2008, we have had the following activity related to derivative instruments, none of which are designated as hedges, in our specialty products segment,:

1. We settled 274,000 barrels of three-way crude oil collar derivatives in the fourth quarter of 2008 for $5.2 million and entered into the following four-way crude oil collar derivatives and three-way crude oil collar derivatives to replace a portion of this volume.

Average

Bought Put

Sold Put

Bought Call

Sold Call

Crude Oil Put/Call Spread Contracts by Expiration Dates

Barrels

BPD

($/Bbl)

November 2008

90,000

3,000

74.13

84.13

94.13

104.13

Average

Sold Put

Bought Call

Sold Call

Crude Oil Put/Call Spread Contracts by Expiration Dates

Barrels

BPD

($/Bbl)

December 2008

124,000

4,000

78.61

88.36

97.36

2. We settled 90,000 bbls of two-way crude oil collar derivatives in the fourth quarter of 2008 for $1.3 million and entered into the following four-way crude oil collar derivatives to replace this volume.

Average

Bought Put

Sold Put

Bought Call

Sold Call

Crude Oil Put/Call Spread Contracts by Expiration Dates

Barrels

BPD

($/Bbl)

November 2008

90,000

3,000

72.60

82.60

92.60

102.60

3. We purchased 1.2 million barrels of put options that will settle on November 17, 2008 with an average strike price of $82.50 per barrel to offset the risk of loss on our existing two-way crude oil collar derivative instruments and three-way crude oil collar derivative instruments.

4. We entered into the following two-way crude oil collar derivative instruments and four-way crude oil collar derivative instruments to increase our number of barrels hedged.


					Average		Average
					Sold Put		Bought Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
January 2009		62,000		2,000	$	62.85	$	80.00
February 2009		56,000		2,000		62.85		80.00
March 2009		62,000		2,000		62.95		80.00

Totals		180,000
Average Price					$	62.88	$	80.00

Average

Bought Put

Sold Put

Bought Call

Sold Call

Crude Oil Put/Call Spread Contracts by Expiration Dates

Barrels

BPD

($/Bbl)

January 2009

62,000

2,000

66.88

76.88

86.88

96.88

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, except that, during the fiscal quarter covered by this report, we were still in the process of integrating the Penreco acquisition and were incorporating Penreco’s operations as part of our internal controls. For purposes of this evaluation, the impact of this acquisition on our internal controls over financial reporting was excluded. See Note 4 to the unaudited condensed consolidated financial statements included in Item 1 for a discussion of the Penreco acquisition.

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 8 “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

In addition to the other information included in this Quarterly Report on Form 10-Q and the risk factors reported in our Annual Report on Form 10-K for the period ended December 31, 2007 and our Quarterly Report on Form 10-Q for the three and six months ended June 30, 2008, you should consider the following risk factors in evaluating our business and future prospects. If any of the risks contained in our Quarterly Reports or our Annual Report occur, our business, results of operations, financial condition and ability to make cash distributions to our unitholders could be materially adversely affected.

We may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under our revolving credit facility because of deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Global financial market and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

In addition, we may be unable to obtain adequate funding under our revolving credit facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base under our revolving credit facility is redetermined weekly or monthly depending upon availability levels and may decrease as a result of changes in selling prices of our products, our current material costs (primarily crude oil), lending requirements or regulations, or for any other reason.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our business development plan, enhance our existing business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

Further decreases in the price of crude oil may lead to a reduction in the borrowing base under our revolving credit facility or the requirement that we post substantial amounts of cash collateral, either of which would adversely affect our liquidity, financial condition and our ability to distribute cash to our unitholders.

The borrowing base under our revolving credit facility is redetermined weekly or monthly depending upon availability levels. Reductions in the value of our inventories as a result of lower crude oil prices could result in a reduction in our borrowing base, which would reduce our amount of financial resources available to meet our capital requirements. Further, if at any time our borrowing capacity under our revolving credit facility falls below $35.0 million we may be required by our lenders to take steps to reduce our leverage, pay off our debts on an accelerated basis, limit or eliminate distributions to our unitholders or take other similar measures. In addition, as a result of further decreases in the price of crude oil, we may be required to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our hedging activities. If the borrowing base under our revolving credit facility decreases or we are required to post substantial amounts of cash collateral to our hedging counterparties, it would have a material adverse effect on our liquidity, financial condition and our ability to distribute cash to our unitholders.

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

None.

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

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

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

SIGNATURES

Pursuant to the requirements of 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:	CALUMET GP, LLC,
		its general partner



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

Date: November 7, 2008

Index to Exhibits


Exhibit
Number		Description
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.