Calumet Specialty Products Partners (CLMT) 8-K Other Events

Exhibit 99.1

REVISED PORTIONS OF CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2008

Explanatory Note

     The financial information contained in Item 6 has been derived from our revised earnings per unit calculation and reflects the retrospective application of Emerging Issues Task Force 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“EITF 07-4”). This information should be read in conjunction with our consolidated financial statements and accompanying notes thereto included in Item 8 of this Exhibit 99.1.

PART II

Item 6.Selected Financial Data

     The following table shows selected historical consolidated financial and operating data of Calumet Specialty Products Partners, L.P. and its consolidated subsidiaries (“Calumet”) and Calumet Lubricants Co., Limited Partnership (“Predecessor”). The selected historical financial data as of December 31, 2008 includes the operations acquired as part of the Penreco acquisition from the date of acquisition, January 3, 2008. The selected historical financial data as of December 31, 2005 and 2004 and for the years ended December 31, 2005 and 2004, are derived from the consolidated financial statements of the Predecessor. The results of operations for the years ended December 31, 2006 for Calumet include the results of operations of the Predecessor for the period of January 1, 2006 through January 31, 2006.

     The following table 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 (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated in accordance with GAAP, please read “Non-GAAP Financial Measures.”

     We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K except for operating data such as sales volume, feedstock runs and production. The table also should be read together with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Calumet									Predecessor
	Year Ended December 31,
	2008			2007			2006			2005			2004
	(Dollars in thousands, except per unit data)
Summary of Operations Data:
Sales	$	2,488,994		$	1,637,848		$	1,641,048		$	1,289,072		$	539,616
Cost of sales		2,235,111			1,456,492			1,436,108			1,147,117			501,973
Gross profit		253,883			181,356			204,940			141,955			37,643
Operating costs and expenses:
Selling, general and administrative		34,267			19,614			20,430			22,126			13,133
Transportation		84,702			54,026			56,922			46,849			33,923
Taxes other than income taxes		4,598			3,662			3,592			2,493			2,309
Other		1,576			2,854			863			871			839
Restructuring, decommissioning and asset impairments (1)		—			—			—			2,333			317
Operating income (loss)		128,740			101,200			123,133			67,283			(12,878	)
Other income (expense):
Equity in loss of unconsolidated affiliates		—			—			—			—			(427	)
Interest expense		(33,938	)		(4,717	)		(9,030	)		(22,961	)		(9,869	)
Interest income		388			1,944			2,951			204			17
Debt extinguishment costs		(898	)		(352	)		(2,967	)		(6,882	)		—
Realized gain (loss) on derivative instruments		(58,833	)		(12,484	)		(30,309	)		2,830			39,160
Unrealized gain (loss) on derivative instruments		3,454			(1,297	)		12,264			(27,586	)		(7,788	)

	Calumet									Predecessor
	Year Ended December 31,
	2008			2007			2006			2005			2004
	(Dollars in thousands, except per unit data)
Gain on sale of mineral rights		5,770			—			—			—			—
Other		11			(919	)		(274	)		38			66
Total other income (expense)		(84,046	)		(17,825	)		(27,365	)		(54,357	)		21,159
Net income before income taxes		44,694			83,375			95,768			12,926			8,281
Income tax expense		257			501			190			—			—
Net income	$	44,437		$	82,874		$	95,578		$	12,926		$	8,281
Basic and diluted net income per limited partner unit:
Common and subordinated	$	1.35		$	2.61		$	3.19
Weighted average units:
Limited partners — basic		32,232			29,744			27,708
Limited partners — diluted		32,232			29,746			27,708
Cash distribution declared per common and subordinated unit	$	1.98		$	2.46		$	1.90
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	659,684		$	442,882		$	191,732		$	127,846		$	126,585
Total assets		1,081,062			678,857			531,651			401,924			319,396
Accounts payable		93,855			167,977			78,752			44,759			58,027
Long-term debt		465,091			39,891			49,500			267,985			214,069
Total partners’ capital		473,212			399,644			385,267			43,940			37,802
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	130,341		$	167,546		$	166,768		$	(34,001	)	$	(612	)
Investing activities		(480,461	)		(260,875	)		(75,803	)		(12,903	)		(42,930	)
Financing activities		350,133			12,409			(22,183	)		40,990			61,561
Other Financial Data:
EBITDA	$	135,575		$	102,719		$	119,586		$	53,155		$	25,077
Adjusted EBITDA		128,075			104,272			104,458			85,821			34,711
Operating Data (bpd):
Total sales volume (2)		56,232			47,663			50,345			46,953			24,658
Total feedstock runs (3)		56,243			48,354			51,598			50,213			26,205
Total production (4)		55,330			47,736			50,213			48,331			26,297

(1)	Incurred in connection with the decommissioning of the Rouseville, Pennsylvania facility, the termination of the Bareco joint venture and the closing of the Reno, Pennsylvania facility, none of which were contributed to Calumet Specialty Products Partners, L.P. in connection with the closing of our initial public offering on January 31, 2006.
(2)	Total sales volume includes sales from the production of our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements, and sales of inventories.
(3)	Feedstock runs represents the barrels per day of crude oil and other feedstocks processed at our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements.
(4)	Total production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and, beginning in 2008, certain third-party facilities pursuant to supply and/or processing agreements. The difference between total production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of finished products and volume loss.

2

Non-GAAP Financial Measures

     We include in this Annual Report on Form 10-K 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 (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP.

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

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

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

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

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

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

     We are required to report Adjusted EBITDA to our lenders under our credit facilities and it is used to determine our compliance with the consolidated leverage and consolidated interest coverage tests thereunder. On January 3, 2008, we entered into a new senior secured term loan credit facility and amended our existing senior secured revolving credit facility. Please refer to Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” within this item for additional details regarding our credit agreements.

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

	Calumet									Predecessor
	Year Ended December 31,
	2008			2007			2006			2005		2004
	(In thousands)
Reconciliation of net income to EBITDA and Adjusted EBITDA:
Net income	$	44,437		$	82,874		$	95,578		$	12,926	$	8,281
Add:
Interest expense and debt extinguishment costs		34,836			5,069			11,997			29,843		9,869
Depreciation and amortization		56,045			14,275			11,821			10,386		6,927
Income tax expense		257			501			190			—		—
EBITDA	$	135,575		$	102,719		$	119,586		$	53,155	$	25,077
Add:
Unrealized losses (gains) from mark to market accounting for hedging activities	$	(11,509	)	$	3,487		$	(13,145	)	$	27,586	$	7,788
Non-cash impact of restructuring, decommissioning and asset impairments		—			—			—			1,766		(1,276	)
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		4,009			(1,934	)		(1,983	)		3,314		3,122
Adjusted EBITDA	$	128,075		$	104,272		$	104,458		$	85,821	$	34,711

3

	Calumet									Predecessor
	Year Ended December 31,
	2008			2007			2006			2005			2004
	(In thousands)
Reconciliation of Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities:
Adjusted EBITDA	$	128,075		$	104,272		$	104,458		$	85,821		$	34,711
Add:
Unrealized (losses) gains from mark to market accounting for hedging activities		11,509			(3,487	)		13,145			(27,586	)		(7,788	)
Non-cash impact of restructuring, decommissioning and asset impairments		—			—			—			(1,766	)		1,276
Prepaid non-recurring expenses and accrued non-recurring expenses, net of cash outlays		(4,009	)		1,934			1,983			(3,314	)		(3,122	)
EBITDA	$	135,575		$	102,719		$	119,586		$	53,155		$	25,077
Add:
Cash interest expense and debt extinguishment costs		(31,440	)		(4,638	)		(11,997	)		(29,843	)		(9,869	)
Unrealized (gains) losses on derivative instruments		(3,454	)		1,297			(12,264	)		27,586			7,788
Income taxes		(257	)		(501	)		(190	)		—			—
Restructuring charge		—			—			—			1,693			—
Provision for doubtful accounts		1,448			41			172			294			216
Equity in loss of unconsolidated affiliates		—			—			—			—			427
Dividends received from unconsolidated affiliates		—			—			—			—			3,470
Debt extinguishment costs		898			352			2,967			4,173			—
Changes in assets and liabilities:
Accounts receivable		45,042			(15,038	)		16,031			(56,878	)		(19,399	)
Inventory		55,532			3,321			(2,554	)		(25,441	)		(20,304	)
Other current assets		1,834			(4,121	)		16,183			569			(11,596	)
Derivative activity		41,757			2,121			(879	)		4,012			(2,742	)
Accounts payable		(103,136	)		89,225			33,993			(13,268	)		25,764
Accrued liabilities		(1,284	)		(4,150	)		657			5,293			957
Other, including changes in noncurrent assets and liabilities		(12,174	)		(3,082	)		5,063			(5,346	)		(401	)
Net cash provided by (used in) operating activities	$	130,341		$	167,546		$	166,768		$	(34,001	)	$	(612	)

4

Item 8.Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors of Calumet GP, LLC
General Partner of Calumet Specialty Products Partners, L.P.

     We have audited the accompanying consolidated balance sheets of Calumet Specialty Products Partners, L.P. as of December 31, 2008 and 2007, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Calumet Specialty Products Partners, L.P. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

   As discussed in Notes 2 and 18 to the consolidated financial statements, the Company adopted Emerging Issues Task Force 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnershipsand applied the change in its method of accounting for earnings per unit retrospectively to previously reported financial statements.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Calumet Specialty Products Partners L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Indianapolis, Indiana
February 27, 2009,
except for Notes 2 and 18, as to which the dates are December 2, 2009

5

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

	Year Ended December 31,
	2008		2007
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	48	$	35
Accounts receivable:
Trade, less allowance for doubtful accounts of $2,121 and $786, respectively		103,962		109,501
Other		5,594		4,496
		109,556		113,997
Inventories		118,524		107,664
Derivative assets		71,199		—
Prepaid expenses and other current assets		1,803		7,567
Deposits		4,021		21
Total current assets		305,151		229,284
Property, plant and equipment, net		659,684		442,882
Goodwill		48,335		—
Other intangible assets, net		49,502		2,460
Other noncurrent assets, net		18,390		4,231
Total assets	$	1,081,062	$	678,857
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	87,460	$	167,977
Accounts payable — related party		6,395		—
Accrued salaries, wages and benefits		6,865		2,745
Taxes payable		6,833		6,215
Other current liabilities		9,662		4,882
Current portion of long-term debt		4,811		943
Derivative liabilities		15,827		57,503
Total current liabilities		137,853		240,265
Pension and postretirement benefit obligations		9,717		—
Long-term debt, less current portion		460,280		38,948
Total liabilities		607,850		279,213
Commitments and contingencies
Partners’ capital:
Common unitholders (19,166,000 units authorized, issued and outstanding)		363,935		375,925
Subordinated unitholders (13,066,000 units authorized, issued and outstanding)		35,778		43,996
General partner’s interest		17,933		19,364
Accumulated other comprehensive income (loss)		55,566		(39,641	)
Total partners’ capital		473,212		399,644
Total liabilities and partners’ capital	$	1,081,062	$	678,857

See accompanying notes to consolidated financial statements.

6

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2008			2007			2006
	(In thousands, except per unit data)
Sales	$	2,488,994		$	1,637,848		$	1,641,048
Cost of sales		2,235,111			1,456,492			1,436,108
Gross profit		253,883			181,356			204,940
Operating costs and expenses:
Selling, general and administrative		34,267			19,614			20,430
Transportation		84,702			54,026			56,922
Taxes other than income taxes		4,598			3,662			3,592
Other		1,576			2,854			863
Operating income		128,740			101,200			123,133
Other income (expense):
Interest expense		(33,938	)		(4,717	)		(9,030	)
Interest income		388			1,944			2,951
Debt extinguishment costs		(898	)		(352	)		(2,967	)
Realized loss on derivative instruments		(58,833	)		(12,484	)		(30,309	)
Unrealized gain (loss) on derivative instruments		3,454			(1,297	)		12,264
Gain on sale of mineral rights		5,770			—			—
Other		11			(919	)		(274	)
Total other expense		(84,046	)		(17,825	)		(27,365	)
Net income before income taxes		44,694			83,375			95,768
Income tax expense		257			501			190
Net income	$	44,437		$	82,874		$	95,578
Allocation of net income:
Net income applicable to Predecessor for the period through January 31, 2006		—			—			4,408
Net income applicable to Calumet		44,437			82,874			91,170
Less:
General partner’s interest in net income		889			1,657			1,823
Holders of incentive distribution rights		—			3,460			887
Net income available to limited partners		43,548			77,757			88,460
Weighted average limited partner units outstanding — basic		32,232			29,744			27,708
Weighted average limited partner units outstanding — diluted		32,232			29,746			27,708
Common and subordinated unitholders’ basic net income per unit	$	1.35		$	2.61		$	3.19
Common and subordinated unitholders’ diluted net income per unit	$	1.35		$	2.61		$	3.19
Cash distributions declared per common and subordinated unit	$	1.98		$	2.43		$	1.30

See accompanying notes to consolidated financial statements.

7

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

				Accumulated Other			Partners’ Capital
	Predecessor			Comprehensive			General			Limited Partners
	Partners’ Capital			Income (Loss)			Partner			Common			Subordinated			Total
	(In thousands)
Balance at January 1, 2006	$	43,443		$	497		$	—		$	—		$	—		$	43,940
Comprehensive income through January 31, 2006 for the Predecessor:
Net income through January 31, 2006		4,408															4,408
Cash flow hedge (gain)/loss reclassified to net income					(497	)											(497	)
Change in fair value of cash flow hedges through January 31, 2006					1,578												1,578
Comprehensive income through January 31, 2006 for the Predecessor																	5,489
Distributions to Predecessor partners		(6,900	)														(6,900	)
Assets and liabilities not contributed to Calumet		(5,626	)														(5,626	)
Allocation of Predecessor’s capital		(35,325	)					3,053			10,423			21,849			—
Proceeds from initial public offering, net											138,743						138,743
Contribution from Calumet GP, LLC								375									375
Comprehensive income from February 1, 2006 through December 31, 2006 for Calumet:
Net income from February 1, 2006 through December 31, 2006								11,317			42,368			37,485			91,170
Change in fair value of cash flow hedges from February 1, 2006 through December 31, 2006		—			50,673			—			—			—			50,673
Comprehensive income from February 1, 2006 through December 31, 2006 for Calumet																	141,843
Proceeds from follow-on public offering, net											103,479						103,479
Contribution from Calumet GP, LLC								2,218									2,218
Units repurchased for phantom unit grants											(69	)					(69	)
Amortization of vested phantom units											61						61
Distributions to partners								(1,013	)		(20,286	)		(16,987	)		(38,286	)
Balance at December 31, 2006		—			52,251			15,950			274,719			42,347			385,267
Comprehensive loss:
Net income								5,944			43,139			33,791			82,874
Cash flow hedge gain reclassified to net income					(13,880	)											(13,880	)
Change in fair value of cash flow hedges					(78,012	)											(78,012	)
Comprehensive loss																	(9,018	)
Proceeds from follow-on public offering, net											98,206						98,206
Contribution from Calumet GP, LLC								2,113									2,113
Amortization of vested phantom units											121						121
Distributions to partners								(4,643	)		(40,260	)		(32,142	)		(77,045	)
Balance at December 31, 2007		—			(39,641	)		19,364			375,925			43,996			399,644
Comprehensive income:
Net income								889			25,895			17,653			44,437
Cash flow hedge loss reclassified to net income					17,472												17,472
Change in fair value of cash flow hedges					83,959												83,959
Minimum pension liability adjustment					(6,224	)											(6,224	)
Comprehensive income																	139,644
Units repurchased for phantom unit grants											(115	)					(115	)
Amortization of vested phantom units											179						179
Distributions to partners								(2,320	)		(37,949	)		(25,871	)		(66,140	)
Balance at December 31, 2008	$	—		$	55,566		$	17,933		$	363,935		$	35,778		$	473,212

See accompanying notes to consolidated financial statements.

8

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Operating activities
Net income	$	44,437		$	82,874		$	95,578
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		59,261			14,585			11,760
Amortization of turnaround costs		2,468			3,190			3,267
Provision for doubtful accounts		1,448			41			172
Non-cash debt extinguishment costs		898			352			2,967
Unrealized (gain)/loss on derivative instruments		(3,454	)		1,297			(12,264	)
Gain on sale of mineral rights		(5,770	)		—			—
Other non-cash activities		1,712			358			152
Changes in assets and liabilities:
Accounts receivable		45,042			(15,038	)		16,031
Inventories		55,532			3,321			(2,554	)
Prepaid expenses and other current assets		5,834			(6,061	)		9,293
Derivative activity		41,757			2,121			(879	)
Deposits		(4,000	)		1,940			6,890
Other assets		(10,211	)		(6,510	)		1,705
Accounts payable		(103,136	)		89,225			33,993
Accrued salaries, wages and benefits		(1,657	)		(2,930	)		(2,489	)
Taxes payable		618			(823	)		2,962
Other current liabilities		(245	)		(396	)		184
Pension and postretirement benefit obligations		(193	)		—			—
Net cash provided by operating activities		130,341			167,546			166,768
Investing activities
Additions to property, plant and equipment		(167,702	)		(261,015	)		(76,064	)
Acquisition of Penreco, net of cash acquired		(269,118	)		—			—
Settlement of derivative instruments		(49,746	)		—			—
Proceeds from sale of mineral rights		6,065			—			—
Proceeds from disposal of property, plant and equipment		40			140			261
Net cash used in investing activities		(480,461	)		(260,875	)		(75,803	)
Financing activities
Proceeds from borrowings — revolving credit facility		1,424,732			303,380			335,069
Repayments of borrowings — revolving credit facility		(1,329,150	)		(296,423	)		(428,054	)
Repayments of borrowings — prior term loan credit facilities		(30,099	)		(19,401	)		(125,500	)
Proceeds from borrowings — new term loan credit facility		385,000			—			—
Discount on new term loan		(17,400	)		—			—
Debt issuance costs		(9,633	)		(369	)		—
Repayments of borrowings — new term loan credit facility		(9,915	)		—			—
Payments on capital lease obligation		(618	)		(906	)		—
Proceeds from public equity offerings, net		—			98,206			242,222
Contributions from Calumet GP, LLC		—			2,113			2,593
Cash distribution to Calumet Holding, LLC		—			—			(3,258	)
Change in bank overdraft		3,471			2,854			—
Purchase of common units for unit grants		(115	)		—			(69	)
Distributions to Predecessor partners		—		��	—			(6,900	)
Distributions to partners		(66,140	)		(77,045	)		(38,286	)
Net cash provided by (used in) financing activities		350,133			12,409			(22,183	)
Net increase (decrease) in cash and cash equivalents		13			(80,920	)		68,782
Cash and cash equivalents at beginning of year		35			80,955			12,173
Cash and cash equivalents at end of year	$	48		$	35		$	80,955
Supplemental disclosure of cash flow information
Interest paid, net of capitalized interest	$	33,667		$	4,080		$	11,986
Income taxes paid	$	30		$	150		$	175
Supplemental disclosure of noncash financing and investing activities
Equipment acquired under capital lease	$	171		$	3,565		$	—

See accompanying notes to consolidated financial statements.

9

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

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

1. Description of the Business

     Calumet Specialty Products Partners, L.P. (Calumet, Partnership, or the Company) is a Delaware limited partnership. The general partner 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 or liabilities of Calumet Lubricants Co., Limited Partnership and its subsidiaries (Predecessor) were contributed to Calumet. References to the Predecessor in these consolidated financial statements refer to Calumet Lubricants Co., Limited Partnership and its subsidiaries. On July 5, 2006 and November 20, 2007, the Partnership completed follow-on public offerings of its common units. As of December 31, 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. 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.

2. Summary of Significant Accounting Policies

Accounting Change

     In September 2006, the FASB issued Emerging Issues Task Force 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships(“EITF 07-4”), which 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 also 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. See Note 18 for details regarding the effects of the adoption of EITF 07-4 on the consolidated financial statements.

     On January 1, 2009, we adopted Financial Accounting Standards Board (“FASB”) Staff Position No. EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities(“FSP EITF 03-6-1”). Under FSP EITF 03-6-1, unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of both basic and diluted earnings per unit pursuant to the two-class method. The two-class method determines earnings per unit for each class of common units and participating securities according to distributions or distribution equivalents and their respective participation rights in undistributed earnings. The adoption of FSP EITF 03-6-1 did not have an effect on our financial statements issued prior to that date.

Consolidation

     The consolidated financial statements of Calumet include the accounts of Calumet Specialty Products Partners, L.P. and its wholly-owned operating subsidiaries, Calumet Lubricants Co., Limited Partnership, Calumet Sales Company Incorporated, Calumet Penreco, LLC and Calumet Shreveport, LLC. Calumet Shreveport, LLC’s wholly-owned operating subsidiaries are Calumet Shreveport Fuels, LLC and Calumet Shreveport Lubricants & Waxes, LLC. All intercompany transactions and accounts have been eliminated. Hereafter, the consolidated companies are referred to as the Company.

Use of Estimates

     The Company’s financial statements are prepared in conformity with U.S. generally accepted accounting principles which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

     Cash and cash equivalents includes all highly liquid investments with a maturity of three months or less at the time of purchase.

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Inventories

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

     Inventories consist of the following:

	December 31,
	2008		2007
Raw materials	$	24,955	$	20,887
Work in process		43,735		21,325
Finished goods		49,834		65,452
	$	118,524	$	107,664

     The replacement cost of these inventories, based on current market values, would have been $27,517 and $107,885 higher as of December 31, 2008 and 2007, respectively. During the years ended December 31, 2008, 2007 and 2006, the Company recorded $5,446, $19,834 and $2,127, respectively, of gains in cost of sales in the consolidated statements of operations due to the liquidation of lower cost inventory layers.

Accounts Receivable

     The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are generally due within 30 days for the specialty products segment and 10 days for the fuel products segment. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical credit experience and expected future trends. The activity in the allowance for doubtful accounts was as follows:

	December 31,
	2008			2007			2006
Beginning balance	$	786		$	782		$	750
Provision		1,448			41			172
Write-offs, net		(113	)		(37	)		(140	)
Ending balance	$	2,121		$	786		$	782

Property, Plant and Equipment

     Property, plant and equipment are stated on the basis of cost. Depreciation is calculated generally on composite groups, using the straight-line method over the estimated useful lives of the respective groups.

     Property, plant and equipment, including depreciable lives, consists of the following:

	December 31,
	2008			2007
Land	$	3,249		$	1,169
Buildings and improvements (10 to 40 years)		6,626			2,050
Machinery and equipment (10 to 20 years)		711,122			225,096
Furniture and fixtures (5 to 10 years)		2,682			1,261
Assets under capital leases (4 years)		4,015			3,565
Construction-in-progress		25,065			264,052
		752,759			497,193
Less accumulated depreciation		(93,075	)		(54,311	)
	$	659,684		$	442,882

     Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related accumulated depreciation are retired, and any gain or loss is reflected in earnings.

     During the years ended December 31, 2008, 2007, and 2006, the Company incurred $41,159, $9,328, and $10,998, respectively, of interest expense of which $7,221, $4,611, and $1,968, respectively, was capitalized as a component of property, plant and equipment.

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     The Company has not recorded an asset retirement obligation as of December 31, 2008 or 2007 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.

     Accumulated depreciation above includes $669 of depreciation expense related to the Company’s capitalized lease assets.

Goodwill

     Goodwill represents the excess of purchase price over fair value of the net assets acquired in the Penreco acquisition. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142,Goodwill and Other Intangible Assets, goodwill and other intangible assets are not amortized, but are tested for impairment at least annually and when indicators dictate, such as adverse changes in business climate, market value of long-lived assets or a change in the structure of the Company. The Company performs its annual impairment review in the fourth quarter of each fiscal year, unless circumstances dictate more frequent assessments. The 2008 annual impairment review resulted in no impairment charge. For more information, refer to Note 6.

Other Intangible Assets

     Other intangible assets primarily consist of supply agreements, customer relationships, non-compete agreements and patents acquired in the Penreco acquisition. These assets are being amortized using the discounted estimated future cash flows method 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 method based upon an assumed rate of annual customer attrition. For more information, refer to Note 6.

Impairment of Long-Lived Assets

     The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In such an event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair market value of the long-lived asset. Fair market value is determined primarily using anticipated cash flows discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.

Revenue Recognition

     The Company recognizes revenue on orders received from its customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under the Company’s normal billing and credit terms, all of the Company’s obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.

Concentrations of Credit Risk

     The Company performs periodic credit evaluations of its customers’ financial condition and generally does not require collateral. The Company maintains allowances for doubtful customer accounts for estimated losses resulting from the inability of its customers to make required payments. The allowance for doubtful accounts is developed based on several factors including customers’ credit quality, historical write-off experience, age of accounts receivable, default percentages provided by a third party and any known specific issues or disputes which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, the Company has significant derivative assets with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s SFAS No. 157,Fair Value Measurements, valuations to determine the impact of counterparty credit risk on the valuation of its derivative instruments.

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Income Taxes

     The Company, as a partnership, is not liable for income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries Calumet Lubricants Co., Limited Partnership and Calumet Shreveport, LLC. However, Calumet Sales Company Incorporated (“Calumet Sales Company”), a wholly-owned subsidiary of the Company, is a corporation and as a result, is liable for income taxes on its earnings. Income taxes on the earnings of the Company, with the exception of Calumet Sales Company, are the responsibility of the partners, with earnings of the Company included in partners’ earnings.

     In the event that the Company’s taxable income did not meet certain qualification requirements, the Company would be taxed as a corporation. Related to these qualifications, the Company requested a ruling from the Internal Revenue Service (“IRS”) with respect to the qualifying nature of income generated from the Penreco assets and business operations. In the fourth quarter of 2008, the IRS provided a favorable ruling. Interest and penalties related to income taxes, if any, would be recorded in income tax expense. The Company had no unrecognized tax benefits as of December 31, 2008 and 2007. The Company’s income taxes generally remain subject to examination by major tax jurisdictions for a period of three years.

     Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the Company’s partnership agreement. Individual partners have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each partner’s tax accounting, which is partially dependent upon the partner’s tax position, differs from the accounting followed in the consolidated financial statements. Accordingly, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in the partnership is not readily available.

     Effective January 1, 2007, the Company adopted the provisions of Financial Interpretation No. 48,Accounting for Uncertainty in Income Taxes(the “Interpretation”), an interpretation of SFAS Statement No. 109,Accounting for Income Taxes. The Interpretation clarifies the accounting for uncertainty in income taxes by prescribing a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position to be taken or expected to be taken in a tax return. The implementation of the Interpretation did not have a material effect on the Company’s financial position, results of operations or cash flows.

Excise and Sales Taxes

     The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of jet fuel. Excise taxes and sales taxes assessed and collected from customers are recorded on a net basis within sales in the Company’s consolidated statements of operations.

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 SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, which was amended in June 2000 by SFAS No. 138,Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133, and in May 2003 by SFAS No. 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities, (collectively referred to as “SFAS 133”), the Company recognizes all derivative instruments as either assets or liabilities at fair value on the balance sheets. The Company utilizes third party valuations and published market data to determine the fair value of these derivative instruments. 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 instrument is deferred in accumulated other comprehensive income (loss), a component of partners’ capital. 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 derivative instruments designated as hedging purchases and sales are recorded to cost of sales and sales, respectively, in the consolidated statements of operations, upon recording the related hedged transaction in sales or cost of sales. The derivative instruments designated as hedging payments of interest are recorded in interest expense in the consolidated statements of operations. For the years ended December 31, 2008, 2007 and 2006, the Company has recorded derivative losses of $297,319 and $33,576 and a gain of $6, respectively, to sales and derivative gains of $306,079 and $21,653 and a loss of $11,070, respectively, to cost of sales in the consolidated statements of operations. During the years ended December 31, 2008, 2007 and 2006, the Company recorded a loss of $49,746, a gain of $29 and $0, respectively, on crude oil collar, interest rate swap and natural gas swap derivative settlements in realized gain (loss) on derivative instruments in the consolidated statements of operations due to the derivative transactions not being designated as cash flow hedges. An interest rate swap loss of $554, a gain of $3 and a loss of $7 for the years ended December 31, 2008, 2007 and 2006, respectively, was recorded to

13

interest expense in the consolidated 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 or loss on derivative instruments in the consolidated statements of operations. Upon the settlement of a derivative not designated as a cash flow hedge, the gain or loss at settlement is recorded to realized loss on derivative instruments in the consolidated statements of operations.

     The Company assesses, both at inception of the hedge and on an ongoing basis, whether the derivative instruments 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 years ended December 31, 2008, 2007 and 2006, were gains of $3,730, losses of $5,979 and gains of $4,071, respectively, which were recorded to unrealized gain (loss) on derivative instruments and realized loss on derivative instruments in the 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, a gain of $709 and a loss of $444, respectively, to unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the years ended December 31, 2008, 2007 and 2006.

     The effective portion of the hedges classified in accumulated other comprehensive income (loss) is $61,790 as of December 31, 2008 and, absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2011 with balances being recognized as follows:

	Accumulated Other
	Comprehensive
Year	Income (Loss)
2009	$	24,878
2010		27,102
2011		9,810
2012		—
Total	$	61,790

     The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative instruments. The Company executes all 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 a derivative instrument’s mark-to-market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed upon thresholds in its contracts with these counterparties. The Company’s contracts with these counterparties allow for netting of derivative instrument positions executed under each contract. The Company does not expect nonperformance on any derivative instrument.

Other Noncurrent Assets

     Other noncurrent assets consist of deferred debt issuance costs, turnaround costs and deferred transaction costs. Deferred debt issuance costs were $8,899 and $1,358 as of December 31, 2008 and 2007, respectively, and are being amortized on a straight-line basis over the lives of the related debt instruments. These amounts are net of accumulated amortization of $2,160 and $990 at December 31, 2008 and 2007, respectively.

     Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $9,491 and $682 as of December 31, 2008 and 2007, respectively. The Company capitalizes these costs and amortizes the cost on a straight-line basis over the life of the turnaround assets. These amounts are net of accumulated amortization of $2,586 and $2,930 at December 31, 2008 and 2007, respectively.

     Deferred transaction costs primarily represent costs incurred by the Company as a result of its acquisition of Penreco and were $0 and $2,191 at December 31, 2008 and 2007, respectively.

Shipping and Handling Costs

     The Company adheres to EITF 00-10,Accounting for Shipping and Handling Fees and Costs.This EITF requires the classification of shipping and handling costs billed to customers in sales and the classification of shipping and handling costs incurred in cost of sales, or to be disclosed if classified elsewhere. The Company has reflected $84,702, $54,026, and $56,922, respectively, for the years

14

ended December 31, 2008, 2007, and 2006, in transportation expense in the consolidated statements of operations, of which a significant portion is billed to customers.

New Accounting Pronouncements

     In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements(the “Statement”). The Statement applies to assets and liabilities required or permitted to be measured at fair value under other accounting pronouncements. The Statement defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements about fair value, but does not provide guidance whether assets and liabilities are required or permitted to be measured at fair value. The Statement is effective for fiscal years beginning after November 15, 2007. The Company adopted the Statement on January 1, 2008 and applied the various disclosures as required by the Statement. The adoption of this Statement did not have a material affect on the Company’s financial position or results of operations. In February 2008, the FASB agreed to defer for one year the effective date of the Statement for certain nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.

     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. The Company’s accounting policy is to not 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 the same master netting arrangement. As of December 31, 2008, the Company has provided cash margin of $4.0 million in credit support to certain of its hedging counterparties.

     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 SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133(“SFAS 161”). SFAS 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS 133 have been applied, and the impact that hedges have on an entity’s financial position, results of operations, and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, 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 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 will have a material impact on its consolidated results of operations or financial condition.

3. Acquisition of Penreco

     On January 3, 2008 the Company acquired Penreco, a Texas general partnership, for $269,118, net of the cash acquired. Penreco was owned by ConocoPhillips Company and M.E. Zukerman Specialty Oil Corporation. Penreco manufactures and markets highly-refined products and specialty solvents, including white mineral oils, petrolatums, natural petroleum sulfonates, cable-filling

15

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 logistics 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 operations of these assets have been included in the Company’s consolidated balance sheets and consolidated statements of operations since the date of acquisition. The unaudited pro forma summary results of operations for the year ended December 31, 2007 below combine the results of operations of Calumet and Penreco as if the acquisition had occurred on January 1, 2007.

	For the Year Ended
	December 31, 2007
	(Unaudited)
Sales	$	2,069,832
Net income	$	100,915
Basic and diluted net income per limited partner unit	$	2.85

     The Company recorded $48,335 of goodwill as a result of this acquisition, all of which was recorded within the Company’s specialty products segment. The allocation of the aggregate purchase price is as follows:

	Allocation of
	Purchase Price
Accounts receivable	$	42,049
Inventories		66,392
Prepaid expenses and other current assets		70
Property, plant and equipment		91,790
Other noncurrent assets		288
Intangibles		59,325
Goodwill		48,335
Accounts payable		(29,014	)
Other current liabilities		(7,331	)
Other noncurrent liabilities		(2,786	)
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 non-union Penreco employees and accrued $1,829 for such costs, which are included in the acquisition liabilities. All affected employees have been terminated and substantially all liabilities have been paid as of December 31, 2008.

4. Sale of Mineral Rights

     In June 2008, the Company received $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 consolidated statements of operations. Under the term loan agreement, cash proceeds resulting from this disposition of property, plant and equipment were used as a mandatory prepayment of the term loan.

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5. Shreveport Refinery Expansion

     As of December 31, 2007, the Company had invested $254,414 in its Shreveport refinery expansion project. Through December 31, 2008, the Company has invested an additional $119,630 for a total of $374,044 in its Shreveport refinery expansion project. The project was completed and operational in May 2008. Additionally, for the years ended December 31, 2007 and 2008, the Company had invested $65,633 and $40,753, respectively, in the Shreveport refinery for other capital expenditures including projects to improve efficiency, de-bottleneck certain operating units and for new product development.

6. Goodwill and Other Intangible Assets

     The Company has recorded $48,335 of goodwill as a result of the Penreco acquisition, all of which is recorded within the Company’s specialty products segment.

     Other intangible assets consist of the following:

			December 31, 2008					December 31, 2007
	Weighted		Gross		Accumulated			Gross		Accumulated
	Average Life		Amount		Amortization			Amount		Amortization
Customer relationships		20	$	28,482	$	(4,071	)	$	2,276	$	(2,165	)
Supplier agreements		4		21,519		(7,539	)		—		—
Patents		12		1,573		(313	)		—		—
Non-competition agreements		5		5,732		(768	)		—		—
Distributor agreements		3		2,019		(758	)		—		—
Royalty agreements		19		4,116		(490	)		2,679		(330	)
		12	$	63,441	$	(13,939	)	$	4,955	$	(2,495	)

     Intangible assets associated with supplier agreements, non-competition agreements, patents and distributor agreements are being amortized on an accelerated basis in order to properly match expense with the 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 year ended December 31, 2008, the Company recorded amortization expense of intangible assets of $13,721, as compared to $719 and $521 for the years ended December 31, 2007 and 2006, respectively. The Company estimates that amortization of intangible assets will be $11,409, $8,808, $6,972, and $5,728 for the years ended December 31, 2009, 2010, 2011, and 2012, respectively.

7. Commitments and Contingencies

Operating Leases

     The Company has various operating leases for the use of land, storage tanks, compressor stations, railcars, equipment, precious metals, operating unit catalyst and office facilities that extend through August 2015. Renewal options are available on certain of these leases in which the Company is the lessee. Rent expense for the years ended December 31, 2008, 2007, and 2006 was $16,003, $10,277 and $10,894, respectively.

     As of December 31, 2008, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows:

	Operating
Year	Leases
2009	$	12,665
2010		10,154
2011		8,133
2012		6,223
2013		4,438
Thereafter		4,075
Total	$	45,688

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     Historically, the Company has purchased a portion of its crude oil under a contract that contained minimum purchase requirements. This contract expired during 2008 and the Company has fulfilled all commitments under the contract. Total purchases under this contract were $690,359, $515,268 and $470,538 for the years ended December 31, 2008, 2007 and 2006, respectively. The Company is currently purchasing all of its crude oil under evergreen contracts or on a spot basis. As of December 31, 2008, the estimated minimum purchase requirements under our crude oil contracts were as follows:

Year	Commitment
2009	$	149,613
2010		—
2011		—
2012		—
2013		—
Thereafter		—
Total	$	149,613

     In connection with the closing of the Penreco acquisition on January 3, 2008, the Company entered into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, ConocoPhillips is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, the Company is obligated to purchase $37,365 of feedstock for the LVT unit in each of the next four years based on pricing estimates as of December 31, 2008. If the Base Volume is not supplied at any point during the first five years of the ten year term, a penalty for each gallon of shortfall must be paid to the Company as liquidated damages.

Labor Matters

     The Company has approximately 360 employees out of a total of approximately 630 covered by various collective bargaining agreements. These agreements have expiration dates of March 31, 2010, April 30, 2010, October 31, 2011 and January 31, 2012.

Contingencies

     From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxing and regulatory authorities, such as the Louisiana Department of Environmental Quality (“LDEQ”), Environmental Protection Agency (“EPA”), IRS and Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. Management is of the opinion that the ultimate resolution of any known claims, either individually or in the aggregate, will not have a material adverse impact on the Company’s financial position, results of operations or cash 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 approximately $400 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

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violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency; and (iv) an August 2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations, as identified by the LDEQ following performance of a compliance review, due to excess emissions and failures to continuously monitor and record air emissions levels. The Company anticipates that any penalties that may be assessed due to the alleged violations will be consolidated in a settlement agreement that the Company anticipates executing with the LDEQ in connection with the agency’s “Small Refinery and Single Site Refinery Initiative” described below. The Company has recorded a liability for the proposed penalty within other current liabilities on the consolidated balance sheets. Environmental expenses are recorded within other expenses in the consolidated statements of operations.

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

     Voluntary remediation of subsurface contamination is in process at each of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. During 2008, the Company determined that it will incur approximately $700 of costs during 2009 at its Cotton Valley refinery in connection with continued remediation of groundwater impacts at that site.

     The Company also is in separate discussions with the EPA to resolve alleged deficiencies in risk management planning in connection with a fire-related incident arising out of tank cleaning and vacuum truck operations at its Shreveport refinery on October 30, 2008. The incident involved a third-party contractor and resulted in damage to an on-site aboveground storage tank. Following an investigation of the matter, EPA issued five violations against the Company, alleging, among other things, inadequate contractor training and oversight, and has proposed a penalty of $230. The Company is currently evaluating its response to the EPA with respect to the matter.

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

     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 is subject to various laws and regulations relating to occupational health and safety including OSHA, and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company maintains safety, training, and maintenance programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company’s compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. The Company has commissioned studies to assess the adequacy of its

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process safety management practices at its Shreveport refinery. Depending on the findings made in these studies, the Company may incur capital expenditures over the next several years to enhance these practices so that it may maintain its compliance with applicable OSHA regulations at the refinery. While the Company does not expect these expenditures to be material at this time, it has not yet received the reports from the engineering firms conducting the studies to reach final resolution. The Company believes that its operations are in substantial compliance with OSHA and similar state laws.

Standby Letters of Credit

     The Company has agreements with various financial institutions for standby letters of credit which have been issued to domestic vendors. As of December 31, 2008 and 2007, the Company had outstanding standby letters of credit of $21,355 and $96,676, respectively, under its senior secured revolving credit facility. The maximum amount of letters of credit the Company can issue is limited to its borrowing capacity under its revolving credit facility or $300,000, whichever is lower. As of December 31, 2008 and 2007, the Company had availability to issue letters of credit of $51,865 and $103,324, respectively, under its revolving credit facility. As discussed in Note 8, as of December 31, 2008 the Company also had a $50,000 letter of credit outstanding under its senior secured first lien letter of credit facility for its fuels hedging program, which bears interest at 4.0%.

8. Long-Term Debt

     Long-term debt consisted of the following:

	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% (6.15% at December 31, 2008), interest and principal payments quarterly with borrowings due January 2015, effective interest rate of 7.84%	$	375,085		$	—
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% (3.75% and 7.25% at December 31, 2008 and 2007, respectively), interest payments monthly, borrowings due January 2013		102,539			6,958
Capital lease obligations, interest at 8.25%, interest and principal payments quarterly with borrowings due January 2012		2,640			2,834
Less unamortized discount on new senior secured first lien term loan with third-party lenders		(15,173	)		—
Total long-term debt		465,091			39,891
Less current portion of long-term debt		4,811			943
	$	460,280		$	38,948

     The borrowing capacity at December 31, 2008 under the revolving credit facility was $175,759 with $51,865 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. 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 new term loan bears interest at a rate equal (i) with respect to a Eurodollar Loan, the Eurodollar Rate plus 400 basis points and (ii) with respect to a Base Rate Loan, the Base Rate plus 300 basis points (as defined in the term loan credit agreement). The letter of credit facility to support crack spread hedging bears interest at 4.0%.

     Lenders under the term loan facility have a first priority lien on the Company’s fixed assets and a second priority lien on its cash, accounts receivable, inventory and other personal property. The term loan facility matures in January 2015. The term loan facility requires quarterly principal payments of $963 until maturity on September 30, 2014, with the remaining balance due at maturity on January 3, 2015.

     On January 3, 2008, the Partnership amended its existing senior secured revolving credit facility dated as of December 9, 2005, Pursuant to this amendment, the revolving credit facility lenders agreed to, among other things, (i) increase the total availability under the revolving credit facility up to $375,000 and (ii) conformed certain of the financial covenants and other terms in the revolving

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credit facility to those contained in the term loan credit agreement. The existing senior secured revolving credit facility matures on January 3, 2013.

     During 2008, the Company has experienced adverse financial conditions primarily attributable with historically high crude oil costs and the impact of the Shreveport refinery expansion project cost overruns and the delay in the startup of the expansion project. Compliance with the financial covenants pursuant to the Company’s credit agreements is tested quarterly based upon performance over the most recent four fiscal quarters, and as of December 31, 2008, it was in compliance with all financial covenants under its credit agreements. The Company’s ability to maintain compliance with these financial covenants in the quarter ended December 31, 2008 was substantially enhanced by the significant increase in specialty products segment gross profit during the third and fourth quarters resulting from increased selling prices for specialty products in the third quarter and reductions in the cost of crude oil throughout the third and fourth quarters. The Company is continuing to take steps to ensure that it meets the requirements of its credit agreements and currently forecasts that it will be in compliance on future measurement dates. These steps have included increasing specialty products sales prices, increasing crude oil price hedging for the specialty products segment and reducing 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 strategic initiatives listed above 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 our 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 December 31, 2008, maturities of the Company’s long-term debt is as follows:

Year	Maturity
2009	$	4,811
2010		4,594
2011		4,460
2012		4,175
2013		106,389
Thereafter		355,835
Total	$	480,264

     In 2007, the Company entered into a capital lease for catalyst which will expire in 2012. Assets recorded under this capital lease obligation are included in property, plant and equipment consists of $3,736 and $3,565 as of December 31, 2008 and 2007, respectively. As of December 31, 2008 and 2007, the Company had recorded $669 and $0, respectively, in amortization for capital lease assets. The assets were placed in service in 2008.

     As of December 31, 2008, the Company had estimated minimum commitments for the payment of rentals under capital leases as follows:

	Capital
Year	Leases
2009	$	1,133
2010		845
2011		660
2012		330
2013		—
Total minimum lease payments		2,968
Less amount representing interest		328
Capital lease obligation		2,640
Less obligations due within one year		961
Long-term capital lease obligation	$	1,679

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9. Derivatives

     The Company had the following derivative instruments outstanding as of December 31, 2008 and 2007.

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. The Company’s policy is generally to enter into crude oil derivative contracts that match its expected future cash out flows for up to 70% of its anticipated crude oil purchases related to its specialty products production. At December 31, 2008, the Company had approximately 7,700 barrels per day of crude oil hedges expiring in January 2009 through March 2009 and is at the lower end of its targeted volume range of hedges for the specialty products segment. These positions generally 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 its expected future cash flows support lengthening its position.

     At December 31, 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 $2,067 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.

					Average		Average		Average		Average
					Lower Put		Upper Put		Lower Call		Upper Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)		($/Bbl)		($/Bbl)
January 2009		217,000		7,000	$	50.32	$	60.32	$	70.32	$	80.32
February 2009		84,000		3,000		38.33		48.33		58.33		68.33
Totals		301,000
Average price					$	46.98	$	56.98	$	66.98	$	76.98

     At December 31, 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 $10,277 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.

					Average		Average
					Sold Put		Bought Call
Crude Oil Put/Call Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
January 2009		186,000		6,000	$	68.57	$	90.83
February 2009		112,000		4,000		74.85		96.25
March 2009		93,000		3,000		79.37		101.67
Totals		391,000
Average price					$	72.94	$	94.96

     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
					Lower Put		Upper Put		Lower Call		Upper Call
Crude Oil Put/Call SpreadContracts 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

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

	Barrels
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 2009		2,025,000		22,500	$	66.26
Second Quarter 2009		2,047,500		22,500		66.26
Third Quarter 2009		2,070,000		22,500		66.26
Fourth Quarter 2009		2,070,000		22,500		66.26
Calendar Year 2010		7,300,000		20,000		67.29
Calendar Year 2011		3,009,000		8,244		76.98
Totals		18,521,500
Average price					$	68.41

     At December 31, 2008, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $14,278 of unrealized gains in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.

Crude Oil Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2009		450,000		5,000	$	62.66
Second Quarter 2009		455,000		5,000		62.66
Third Quarter 2009		460,000		5,000		62.66
Fourth Quarter 2009		460,000		5,000		62.66
Totals		1,825,000
Average price					$	62.66

     At December 31, 2007, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which were designated as hedges.

	Barrels
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 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

Fuels Product 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 fuels sales.

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Diesel Swap Contracts

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

Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2009		1,170,000		13,000	$	80.51
Second Quarter 2009		1,183,000		13,000		80.51
Third Quarter 2009		1,196,000		13,000		80.51
Fourth Quarter 2009		1,196,000		13,000		80.51
Calendar Year 2010		4,745,000		13,000		80.41
Calendar Year 2011		2,371,000		6,496		90.58
Totals		11,861,000
Average price					$	82.48

     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 certain of these barrels not being designated as hedges, the Company recognized $941 of losses in unrealized (loss) gain on derivative instruments in the consolidated statements of operations.

Diesel Swap Contracts by Expiration Dates	Barrels Sold		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 December 31, 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 Sold		BPD		($/Bbl)
First Quarter 2009		855,000		9,500	$	73.83
Second Quarter 2009		864,500		9,500		73.83
Third Quarter 2009		874,000		9,500		73.83
Fourth Quarter 2009		874,000		9,500		73.83
Calendar Year 2010		2,555,000		7,000		75.28
Calendar Year 2011		638,000		1,748		83.42
Totals		6,660,500
Average price					$	75.30

     At December 31, 2008, the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges. As a result of these derivatives not being designated as hedges, the Company recognized $15,851 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations in 2008.

	Barrels
Gasoline Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 2009		450,000		5,000	$	60.53
Second Quarter 2009		455,000		5,000		60.53
Third Quarter 2009		460,000		5,000		60.53
Fourth Quarter 2009		460,000		5,000		60.53
Totals		1,825,000
Average price					$	60.53

     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.

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Gasoline Swap Contracts by Expiration Dates	Barrels Sold		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 December 31, 2008, the Company had the following derivatives related to natural gas purchases, of which 90,000 MMBtus are designated as hedges. As a result of a portion of these derivative instruments not being designated as hedges, the Company recognized $1,223 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008.

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

     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	MMBtu		$/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 its current variable rate senior secured first lien term loan which closed January 3, 2008. The Company has hedged the future interest payments related to $150,000 and $50,000 of the total outstanding term loan indebtedness in 2009 and 2010, respectively, pursuant to this forward swap contract.

     This swap contract is designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at 3.09% and 3.66% per annum in 2009 and 2010, respectively.

     In 2006, the Company entered into a forward swap contract to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan. Due to the repayment of $19,000 of the outstanding balance of the Company’s then existing term loan facility in August 2007 and the subsequent refinancing of the remaining term loan balance, this swap contract was not designated as a cash flow hedge of the future payment of interest. The entire change in the fair value of this interest rate swap is recorded to unrealized gain (loss) on derivative instruments in the consolidated statements of operations as of December 31, 2008. For the year ended December 31, 2008, the Company recorded $2,188 of losses in unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2008. 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.

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10. Fair Value of Financial Instruments

     The Company’s financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and indebtedness. The carrying value of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying consolidated financial statements at fair value in accordance with SFAS No. 157,Fair Value Measurements. The fair value of our long-term debt was $305,084 at December 31, 2008. The fair value of long-term debt materially approximated the carrying value at December 31, 2007. In addition, based upon fees charged for similar agreements, the face values of outstanding standby letters of credit approximated their fair value at December 31, 2008 and 2007.

11. Fair Value Measurements

     In September 2006, the FASB issued Statement No. 157,Fair Value Measurements(“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. The Company 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 December 31, 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 the Company’s derivative instruments are with counterparties that have long-term credit ratings of single A or better. The fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, natural gas and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the company obtains this data through surveying its counterparties and performing various analytical tests to validate the data. The Company determines the fair value of its crude oil option contracts utilizing a standard option pricing model based on inputs that can be derived from information available in publicly quoted markets, or are quoted by counterparties to these contracts. In situations where the Company obtains inputs via quotes from its counterparties, it verifies the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. The Company also includes an adjustment for non-performance risk in the recognized measure of fair value of all of the Company’s derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When the Company is in a net asset position, it uses its counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. The Company uses its own peer group’s estimated CDS when it is in a net liability position. As a result of applying the applicable CDS, at December 31, 2008, the Company’s asset was reduced by approximately $6,186 and its liability was reduced by $564. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for gasoline and diesel, the Company has categorized these derivative instruments as Level 3. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds.

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

     The Company’s assets measured at fair value on a recurring basis subject to the disclosure requirements of SFAS 157 at December 31, 2008 were as follows:

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	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		103,780			103,780
Diesel swaps		—		—		90,337			90,337
Natural gas swaps		—		—		—			—
Crude oil options		—		—		—			—
Pension plan investments		12,018		—		—			12,018
Total assets at fair value	$	12,018	$	—	$	194,117		$	206,135
Liabilities:
Crude oil swaps	$	—	$	—	$	(119,202	)	$	(119,202	)
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Natural gas swaps		—		—		(1,429	)		(1,429	)
Crude oil options		—		—		(12,345	)		(12,345	)
Interest rate swaps		—		—		(5,769	)		(5,769	)
Pension plan investments		—		—		—			—
Total liabilities at fair value	$	—	$	—	$	(138,745	)	$	(138,745	)

     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 year ended December 31, 2008:

	Derivative
	Instruments, Net
Fair value at January 1, 2008	$	(600,051	)
Realized losses		58,833
Unrealized gains (losses)		17,141
Comprehensive income (loss)		58,610
Purchases, issuances and settlements		(21,709	)
Transfers in (out) of Level 3		542,548
Fair value at December 31, 2008	$	55,372
Total gains or losses included in net income attributable to changes in unrealized gains (losses) relating to financial assets and liabilities held as of December 31, 2008	$	3,454

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

12. Partners’ Capital

     On November 20, 2007, the Partnership completed an offering of its common units in which it sold 2,800,000 common units to the underwriters of the offering at a price to the public of $36.98 per common unit. This issuance was made pursuant to the Partnership’s Registration Statement on Form S-3 (File No. 333-145657) declared effective by the Securities and Exchange Commission on November 9, 2007. The proceeds received by the Partnership (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) from this offering were $98,206. The use of proceeds from the offering was to: (i) repay all its borrowings under its revolving credit facility, which were approximately $59,300 on November 20, 2007, (ii) fund approximately $25,100 of the purchase price for the Penreco acquisition and (iii) to the extent available, for general partnership purposes. Underwriting discounts totaled $4,401. The general partner contributed $2,113 to retain its 2% general partner interest.

     Of the 19,166,000 common units outstanding at December 31, 2008, 13,085,985 are held by the public, with the remaining 6,080,015 held by the Company’s affiliates. All of the 13,066,000 subordinated units are held by the Company’s affiliates. The

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Company’s ability to issue new units is limited to 6,533,000 units in certain circumstances where the use of proceeds is not deemed to be accretive to existing unitholders at the time of the offering.

     Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash as defined in the Company’s partnership agreement. The subordination period will end on the first day of any quarter beginning after December 31, 2010 in which the Company meets certain financial tests provided for in its partnership agreement. Significant information regarding rights of the limited partners include the following:

• Rights to receive distributions of available cash within 45 days after the end of each quarter, to the extent the Company has sufficient cash from operations after the establishment of cash reserves.

• Limited partners have limited voting rights on matters affecting the Company’s business. The general partner may consider only the interests and factors that it desires, and has no duty or obligation to give any consideration of any interests of, the Company’s limited partners. Limited partners have no right to elect the board of directors of the Company’s general partner.

• The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Any holder, other than the general partner or the general partner’s affiliates, that owns 20% or more of any class of units outstanding, cannot vote on any matter.

• During the subordination period, the general partner, without approval of the limited partners, may cause the Company to issue up to 6,533,000 of additional common units. After the subordination period, the Company may issue an unlimited number of limited partner interests without the approval of the limited partners.

• Limited partners may be required to sell their units to the general partner if at any time the general partner owns more than 80% of the issued and outstanding common units.

     The Company’s general partner is entitled to incentive distributions if the amount it distribute to unitholders with respect to any quarter exceeds specified target levels shown below:

		Marginal Percentage
	Total Quarterly	Interest in
	Distribution	Distributions
	Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.45		98	%		2	%
First Target Distribution	up to $0.495		98	%		2	%
Second Target Distribution	above $0.495 up to $0.563		85	%		15	%
Third Target Distribution	above $0.563 up to $0.675		75	%		25	%
Thereafter	above $0.675		50	%		50	%

     The Company’s ability to make distributions is limited by its credit agreements. The credit agreements permit the Company to make distributions to its unitholders as long as it is not in default and would not be in default following the distribution. Under the credit facilities, the Company is obligated to comply with certain financial covenants requiring it 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.

     Calumet’s distribution policy is as defined in its partnership agreement. For the years ended December 31, 2008 and 2007, Calumet made distributions of $66,140 and $77,045, respectively, to its partners.

13. Unit-Based Compensation

     The Company’s general partner originally adopted a Long-Term Incentive Plan (the “Plan”) on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with

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respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Plan is administered by the compensation committee of the Company’s general partner’s board of directors.

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

     A summary of the Company’s nonvested units as of December 31, 2008, and the changes during the years ended December 31, 2008, 2007 and 2006, are presented below:

				Weighted-Average
				Grant Date
Nonvested Phantom Units	Grant			Fair Value
Nonvested at January 1, 2006		—		$	—
Granted		7,296			33.63
Vested		(1,824	)		33.63
Forfeited		—			—
Nonvested at December 31, 2006		5,472		$	33.63
Granted		6,480			37.00
Vested		(3,444	)		35.22
Forfeited		—			—
Nonvested at December 31, 2007		8,508		$	35.56
Granted		30,192			7.79
Vested		(10,992	)		16.38
Forfeited		—			—
Nonvested at December 31, 2008		27,708		$	12.91

     For the years ended December 31, 2008, 2007 and 2006, compensation expense of $179, $121 and $61, respectively, was recognized in the consolidated statements of operations related to vested unit grants. As of December 31, 2008 and 2007, there was a total of $358 and $303 of unrecognized compensation costs related to nonvested unit grants. These costs are expected to be recognized over a weighted-average period of three years. The total fair value of phantom units vested during the years ended December 31, 2008 and 2007, was $86 and $128.

14. Employee Benefit Plans

     The Company has a defined contribution plan administered by its general partner. All full-time employees who have completed at least one hour of service are eligible to participate in the plan. Participants are allowed to contribute 0% to 100% of their pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% contribution by the participant up to 4% and 50% of each additional 1% contribution up to 6% for a maximum contribution by the Company of 5% per participant. The Company’s matching contribution was $1,782, $950, and $1,109 for the years ended December 31, 2008, 2007 and 2006, respectively. The plan also includes a profit-sharing component. Contributions under the profit-sharing component are determined by the board of directors of the Company’s general partner and are discretionary. The Company’s profit sharing contribution was $1,123, $689, and $870 for the years ended December 31, 2008, 2007 and 2006, respectively.

     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

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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. Effective January 31, 2009, the Company has amended the Pension Plan. The amendment removes the salaried employee from accumulating additional benefits subsequent to January 31, 2009. All information presented below has been adjusted for this curtailment, which resulted in a reduction in the Company’s benefit obligation of $2,311.

     The components of net periodic pension and other post retirement benefits cost for the year ended December 31, 2008 were as follows:

	Year Ended December 31, 2008
				Other Post
	Pension			Retirement
	Benefits			Employee Benefits
Service cost	$	945		$	9
Interest cost		1,298			51
Expected return on assets		(1,341	)		—
Net periodic pension cost	$	902		$	60

     During the year ended December 31, 2008, the Company made contributions of $193 and $63 to its Pension Plan and Other Plans, respectively, and expects to make no contributions in 2009.

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

				Other Post
	Pension			Retirement
	Benefits			Employee Benefits
Change in projected benefit obligation (“PBO”):
Benefit obligation at January 3, 2008	$	20,097		$	872
Service cost		945			9
Interest cost		1,298			51
Curtailment		(2,311	)		—
Benefits paid		(630	)		(141	)
Actuarial (gain) loss		1,613			(30	)
Administrative expense		(116	)		—
Employee contributions		—			78
Benefit obligation at December 31, 2008	$	20,896		$	839
Change in plan assets:
Fair value of plan assets at January 3, 2008	$	18,183		$	—
Benefit payments		(630	)		(141	)
Actual return on assets		(5,612	)		—
Administrative expense		(116	)		—
Employee contributions		—			78
Employer contribution		193			63
Fair value of plan assets at December 31, 2008	$	12,018		$	—
Funded status — benefit obligation in excess of plan assets	$	(8,878	)	$	(839	)
Curtailment		(2,311	)		—
Unrecognized net actuarial loss		1,613			(30	)
Unexpected loss on plan assets		6,952			—
Net amount recognized at December 31, 2008	$	(2,624	)	$	(869	)
Amounts recognized in the consolidated balance sheets consisted of:
Accrued benefit obligation	$	(8,878	)	$	(839	)
Accumulated other comprehensive loss		6,254			(30	)
Net amount recognized at December 31, 2008	$	(2,624	)	$	(869	)

     The accumulated benefit obligation for the Pension Plan was $20,896 as of December 31, 2008. The accumulated benefit obligation is equal to the projected benefit obligation due to the curtailment that occurred in 2008. The accumulated benefit obligation for the Pension Plan was less than plan assets by $8,878 as of December 31, 2008. As of December 31, 2008, the Company had no prior

30

service costs or transition gains (losses) but recorded actuarial losses of $6,224 in accumulated other comprehensive income (loss) in the consolidated balance sheets.

     The effective portion of the minimum pension liability classified in accumulated other comprehensive loss is $6,224 as of December 31, 2008. In 2009, the Company expects to recognize $419 and $0, respectively, of losses from accumulated other comprehensive loss for the Company’s Pension Plan and Other Postretirement Benefits Plan.

     The significant weighted average assumptions used for the year ended December 31, 2008 were as follows:

	Pension			Other Post Retirement
	Benefits			Employee Benefits
Discount rate for benefit obligations		6.18	%		6.20	%
Discount rate for net periodic benefit costs		6.58	%		6.20	%
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	%

     For measurement purposes, a 8.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2009. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.5% for 2029 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 December 31, 2008 by asset category, are as follows:

				Other Post
				Retirement
	Pension			Employee
	Benefits			Benefits
Cash		2	%		0	%
U.S. equities		77	%		0	%
Foreign equities		4	%		0	%
Fixed income		17	%		0	%
		100	%		0	%

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 7.50% 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	%

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     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 semiannually, 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 December 31, 2008:

	Pension		Other Post Retirement
	Benefits		Employee Benefits
2009	$	773	$	98
2010		820		75
2011		870		82
2012		949		101
2013		1,041		79
2014 to 2018		6,527		342
Total	$	10,980	$	777

15. Transactions with Related Parties

     During the years ended December 31, 2008, 2007 and 2006, the Company had sales to related parties owned by a limited partner of $7,973, $4,726 and $904, respectively. Trade accounts and other receivables from related parties at December 31, 2008 and 2007 were $1,828 and $497, respectively. The Company also had purchases from related parties owned by a limited partner, excluding crude purchases related to the Legacy agreement discussed below, during the years ended December 31, 2008, 2007 and 2006 of $615, $1,730 and $1,228, respectively. Accounts payable to related parties, excluding accounts payable related to Legacy agreement discussed below, at December 31, 2008 and 2007 were $774 and $907, respectively.

     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”). Legacy is owned in part by one of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and president, F. William Grube, and Jennifer G. Straumins, the Company’s senior vice president. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company is approximately 6,000 barrels per day. During the year ended December 31, 2008, the Company had crude oil purchases of $140,180 from Legacy. Accounts payable to Legacy at December 31, 2008 related to this agreement were $6,395.

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     A limited partner has provided certain administrative and accounting services to the Company for an annual fee. Such services included, but were not necessarily limited to, advice and assistance concerning aspects of the operation, planning, and human resources of the Company. Payments for the years ended December 31, 2008, 2007 and 2006 were $0, $227 and $549, respectively. The Company terminated these services during the year ended December 31, 2007.

     The Company previously participated in a self-insurance program for medical benefits with a limited partner and several other related companies. In connection with this program, contributions were made to a voluntary employees’ benefit association (VEBA) trust. Contributions made by the Company to the VEBA for the years ended December 31, 2008, 2007 and 2006 totaled $0, $876 and $3,093, respectively. The Company terminated participation in this related party VEBA during the year ended December 31, 2007 and established a new VEBA of which it is the sole participant and administered by its general partner.

     During 2006 and prior, the Company had placed a portion of its insurance underwriting requirements, including general liability, automobile liability, excess liability, workers’ compensation as well as directors’ and officers’ liability with a commercial insurance brokerage business. A member of the board of directors of our general partner serves as an executive of this commercial insurance brokerage company. The total premiums paid to this company by Calumet for the years ended December 31, 2008, 2007 and 2006 were $634, $889 and $1,647 respectively. With the exception of its directors’ and officers’ liability insurance which were placed with this commercial insurance brokerage company, the Company placed its insurance requirements with third parties during the years ended December 31, 2008 and 2007.

     The Company previously participated in a self-insurance program for workers’ compensation with a limited partner and several other related companies. In connection with this program, contributions were made to the limited partner. Contributions made by the Company to the limited partner for the years ended December 31, 2008, 2007 and 2006 totaled $0, $254 and $213, respectively. The Company terminated participation in this plan during the year ended December 31, 2007 and established a self-insurance program on a standalone basis.

     The Company previously participated in a self-insurance program for general liability with a limited partner and several related companies. In connection with this program, contributions were made to the limited partner. Contributions made by the Company to the limited partner for the years ended December 31, 2008, 2007 and 2006 totaled $0, $998 and $563, respectively. The Company terminated participation in this plan during the year ended December 31, 2007 and established a self-insurance program on a standalone basis.

16. 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 its 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 the 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:

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	Specialty		Fuel		Combined					Consolidated
Year Ended December 31, 2008	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	1,578,035	$	910,959	$	2,488,994	$	—		$	2,488,994
Intersegment sales		1,113,342		27,925		1,141,267		(1,141,267	)		—
Total sales	$	2,691,377	$	938,884	$	3,630,261	$	(1,141,267	)	$	2,488,994
Depreciation and amortization		61,729				61,729					61,729
Income from operations		72,709		56,031		128,740					128,740
Reconciling items to net income:
Interest expense											(33,938	)
Interest income											388
Debt extinguishment costs											(898	)
Loss on derivative instruments											(55,379	)
Gain on sale of mineral rights											5,770
Other											11
Income tax expense											(257	)
Net income											44,437
Capital expenditures	$	167,702	$	—	$	167,702	$	—		$	167,702

	Specialty		Fuel		Combined					Consolidated
Year Ended December 31, 2007	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	866,716	$	771,132	$	1,637,848	$	—		$	1,637,848
Intersegment sales		691,592		32,651		724,243		(724,243	)		—
Total sales	$	1,558,308	$	803,783	$	2,362,091	$	(724,243	)	$	1,637,848
Depreciation and amortization		17,775		—		17,775		—			17,775
Income from operations		42,282		58,918		101,200		—			101,200
Reconciling items to net income:
Interest expense											(4,717	)
Interest income											1,944
Debt extinguishment costs											(352	)
Gain (loss) on derivative instruments											(13,781	)
Other											(919	)
Income tax expense											(501	)
Net income											82,874
Capital expenditures	$	261,015	$	—	$	261,015	$	—		$	261,015

	Specialty		Fuel		Combined					Consolidated
Year Ended December 31, 2006	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	913,143	$	727,905	$	1,641,048	$	—		$	1,641,048
Intersegment sales		653,842		34,135		687,977		(687,977	)		—
Total sales	$	1,566,985	$	762,040	$	2,329,025	$	(687,977	)	$	1,641,048
Depreciation and amortization		15,027		—		15,027		—			15,027
Income from operations		83,526		39,607		123,133		—			123,133
Reconciling items to net income:
Interest expense											(9,030	)
Interest income											2,951
Debt extinguishment costs											(2,967	)
Gain (loss) on derivative instruments											(18,045	)
Other											(274	)
Income tax expense											(190	)
Net income											95,578
Capital expenditures	$	76,064	$	—	$	76,064	$	—		$	76,064

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	December 31,
	2008			2007
Segment assets:
Specialty products	$	2,208,741		$	1,462,996
Fuel products		1,483,457			1,019,149
Combined segments		3,692,198			2,482,145
Eliminations		(2,611,136	)		(1,803,288	)
Total assets	$	1,081,062		$	678,857

b. Geographic Information

     International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2008, 2007 and 2006. All of the Company’s long-lived assets are domestically located.

c. Product Information

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

	Year Ended December 31,
	2008		2007		2006
Specialty products:
Lubricating oils	$	841,225	$	478,132	$	509,933
Solvents		419,831		199,843		201,931
Waxes		142,525		61,621		61,192
Fuels		30,389		52,449		41,268
Asphalt and other by-products		144,065		74,671		98,819
Total		1,578,035		866,716		913,143
Fuel products:
Gasoline		332,669		307,144		336,681
Diesel		379,739		203,659		207,148
Jet fuel		186,675		225,868		176,372
By-products		11,876		34,461		7,704
Total		910,959		771,132		727,905
Consolidated sales	$	2,488,994	$	1,637,848	$	1,641,048

d. Major Customers

     During the year ended December 31, 2008, the Company had one customer, Murphy Oil U.S.A., which represented approximately 10.5% of consolidated sales. No other customer represented 10% or greater of consolidated sales in each of the three years ended December 31, 2008, 2007 and 2006.

17. Quarterly Financial Data (Unaudited)

	First			Second		Third			Fourth
	Quarter			Quarter		Quarter			Quarter		Total (1)
2008
Sales	$	594,723		$	671,220	$	724,371		$	498,680	$	2,488,994
Gross profit		34,834			60,882		76,974			81,193		253,883
Net income (loss)		(3,392	)		41,808		(12,515	)		18,536		44,437
Common and subordinated basic and diluted net income (loss) per limited partner unit	$	(0.10	)	$	1.27	$	(0.38	)	$	0.56	$	1.35
Weighted average limited partner units outstanding — basic		32,232,000			32,232,000		32,232,000			32,232,000
Weighted average limited partner units outstanding — diluted		32,232,000			32,232,000		32,232,000			32,232,000

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	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total(1)
2007
Sales	$	351,113	$	421,726	$	428,084	$	436,925	$	1,637,848
Gross profit		55,034		60,471		37,875		27,976		181,356
Net income		28,210		37,418		9,456		7,790		82,874
Common and subordinated basic and diluted net income (loss) per limited partner unit	$	0.92	$	1.21	$	0.28	$	0.22	$	2.61
Weighted average limited partner units outstanding — basic		29,432,000		29,432,000		29,432,000		30,679,826
Weighted average limited partner units outstanding — diluted		29,433,000		29,434,000		29,435,000		30,681,246

(1) The sum of the four quarters may not equal the total year due to rounding.

18. Accounting Change for Earnings per Unit

     As described in Note 2, the Company adopted Emerging Issues Task Force 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships(“EITF 07-4”) on January 1, 2009. 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 also 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. The effects of these adjustments were as follows:

	Years Ended December 31,
	2008		2007		2006
	As Adjusted
Net income	$	44,437	$	82,874	$	95,578
Allocation of net income:
Net income applicable to Predecessor for the period through January 31, 2006		—		—		4,408
Net income applicable to Calumet		44,437		82,874		91,170
Less:
General partner’s interest in net income		889		1,657		1,823
Holders of incentive distribution rights		—		3,460		887
Net income available to limited partners		43,548		77,757		88,460
Weighted average limited partner units outstanding — basic		32,232		29,744		27,708
Weighted average limited partner units outstanding — diluted		32,232		29,746		27,708
Common and subordinated unitholders’ basic net income per unit	$	1.35	$	2.61	$	3.19
Common and subordinated unitholders’ diluted net income per unit	$	1.35	$	2.61	$	3.19
Cash distributions declared per common and subordinated unit	$	1.98	$	2.43	$	1.30

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	Years Ended December 31,
	2008			2007			2006
	As Reported
Net income	$	44,437		$	82,874		$	95,578
Allocation of net income:
Net income applicable to Predecessor for the period through January 31, 2006		—			—			4,408
Net income applicable to Calumet		44,437			82,874			91,170
Minimum quarterly distribution to common unitholders		(34,500	)		(30,021	)		(24,413	)
General partner’s incentive distribution rights		(10,996	)		(14,102	)		(18,912	)
General partner’s interest in net income		(334	)		(939	)		(845	)
Common unitholders’ share of income in excess of minimum quarterly distribution		(11,706	)		(13,592	)		(18,312	)
Subordinated unitholders’ interest in net income		(13,099	)		24,220			28,688
Basic net income per limited partner unit:
Common	$	2.41		$	2.63		$	2.84
Subordinated	$	(1.00	)	$	1.86		$	2.20
Diluted net income per limited partner unit:
Common	$	2.41		$	2.63		$	2.84
Subordinated	$	(1.00	)	$	1.86		$	2.20
Weighted average limited partner common units outstanding — basic		19,166			16,678			14,642
Weighted average limited partner subordinated units outstanding — basic		13,066			13,066			13,066
Weighted average limited partner common units outstanding — diluted		19,166			16,680			14,642
Weighted average limited partner subordinated units outstanding — diluted		13,066			13,066			13,066
Cash distributions declared per common and subordinated unit	$	1.98		$	2.43		$	1.30

19. Subsequent Events

     On January 22, 2009, the Company declared a quarterly cash distribution of $0.45 per unit on all outstanding units, or $14,800, for the quarter ended December 31, 2008. The distribution was paid on February 13, 2009 to unitholders of record as of the close of business on February 3, 2009. This quarterly distribution of $0.45 per unit equates to $1.80 per unit, or $59,202 on an annualized basis.

     On January 26, 2009, the Company entered into a crude oil supply agreement with Legacy Resources Co., L.P. (“Legacy”) an affiliate of the Company’s general partner. Under the agreement, it is contemplated that Legacy will supply the Company’s Shreveport refinery with a portion of its crude oil requirements that are received via common carrier pipeline. Pricing for the crude oil purchased under each confirmation will be mutually agreed to by the parties and set forth in such confirmation and will include a market-based premium as determined and agreed to by the parties. The agreement is effective as of January 26, 2009 and will continue to be in effect until terminated by either party by written notice. Based on historical usage, the estimated volume of crude oil to be sold by Legacy and purchased by the Company under this Agreement is up to 15,000 barrels per day. Legacy is owned in part by The Heritage Group, an affiliate of the Company’s general partner, in part by the Company’s general partner’s chief executive officer and president, F. William Grube, and in part by the Company’s general partner’s senior vice president, Jennifer G. Straumins.

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