CLMT 10-Q Quarterly Report Sept. 30, 2011

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

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10-Q 1 h85328e10vq.htm FORM 10-Q e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011


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

FOR THE TRANSITION PERIOD FROM TO

Commission File number 000-51734

Calumet Specialty Products Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)


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

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

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

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

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

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


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

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

At November 4, 2011, there were 51,529,778 common units outstanding.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Nine Months Ended September 30, 2011

Table of Contents


	Page
Part I
Item 1. Financial Statements
Condensed Consolidated Balance Sheets		5
Unaudited Condensed Consolidated Statements of Operations		6
Unaudited Condensed Consolidated Statements of Partners’ Capital		7
Unaudited Condensed Consolidated Statements of Cash Flows		8
Notes to Unaudited Condensed Consolidated Financial Statements		9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
Item 3. Quantitative and Qualitative Disclosures About Market Risk		55
Item 4. Controls and Procedures		57
Part II
Item 1. Legal Proceedings		58
Item 1A. Risk Factors		58
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		63
Item 3. Defaults Upon Senior Securities		63
Item 4. Removed and Reserved		63
Item 5. Other Information		63
Item 6. Exhibits		64
EX-2.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. The statements regarding (i) estimated capital expenditures as a result of the required audits or required operational changes included in our settlement with the Louisiana Department of Environmental Quality (“LDEQ”) or other environmental and regulatory liabilities, (ii) our anticipated levels of, use and effectiveness of derivatives to mitigate our exposure to crude oil price changes and fuel products price changes, (iii) the estimated purchase price, future benefits and risks and all other discussion with respect to the Superior Acquisition (as defined in this Quarterly Report) and (iv) our ability to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, credit agreement covenants, contingencies and anticipated capital expenditures, as well as other matters discussed in this Quarterly Report that are not purely historical data, are forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:

	•		our plans, objectives, expectations and intentions with respect to the future operations of the Superior refinery and associated assets;

	•		our ability to meet our expectations with respect to our future financial results after the Superior Acquisition;

	•		our ability to successfully integrate the Superior Business (as defined in this Quarterly Report);

	•		the overall demand for specialty hydrocarbon products, fuels and other refined products;

	•		our ability to produce specialty products and fuels that meet our customers’ unique and precise specifications;

	•		the impact of fluctuations and rapid increases or decreases in crude oil and crack spread prices, including the resulting impact on our liquidity;

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

	•		our ability to comply with financial covenants contained in our debt instruments;

	•		the availability of, and our ability to consummate, acquisition or combination opportunities and the impact of any completed acquisitions;

	•		labor relations;

	•		our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;

	•		successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships;

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

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

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

	•		fluctuations in refinery capacity;

	•		the effects of competition;

	•		continued creditworthiness of, and performance by, counterparties;

	•		the impact of current and future laws, rulings and governmental regulations, including guidance related to the Dodd-Frank Wall Street Reform and Consumer Protection Act;

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

	•		hurricane or other weather interference with business operations;

	•		fluctuations in the debt and equity markets;

	•		accidents or other unscheduled shutdowns; and

	•		general economic, market or business conditions.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part II, “Item 1A. Risk Factors” elsewhere in this report and (2) Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (“2010 Annual Report”).

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

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

PART I


Item 1.		*Financial Statements*

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2011			December 31, 2010
	(Unaudited)
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	66		$	37
Accounts receivable:
Trade		198,888			157,185
Other		34,106			776

		232,994			157,961
Inventories		446,506			147,110
Prepaid expenses and other current assets		4,547			1,909
Deposits		2,520			2,094

Total current assets		686,633			309,111
Property, plant and equipment, net		843,111			612,433
Goodwill		48,335			48,335
Other intangible assets, net		24,423			29,666
Other noncurrent assets, net		39,094			17,127

Total assets	$	1,641,596		$	1,016,672

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	232,589		$	146,730
Accounts payable — related party		1,488			27,985
Accrued salaries, wages and benefits		11,888			7,559
Taxes payable		8,850			7,174
Other current liabilities		7,544			16,605
Current portion of long-term debt		749			4,844
Derivative liabilities		160,861			32,814

Total current liabilities		423,969			243,711
Pension and postretirement benefit obligations		25,349			9,168
Other long-term liabilities		1,062			1,083
Long-term debt, less current portion		642,293			364,431

Total liabilities		1,092,673			618,393
Commitments and contingencies (Note 5)
Partners’ capital:
Limited partners’ interest (50,779,778 units and 35,279,778 units issued and outstanding at September 30, 2011 and December 31, 2010, respectively)		652,229			407,773
General partner’s interest		23,373			18,125
Accumulated other comprehensive loss		(126,679	)		(27,619	)

Total partners’ capital		548,923			398,279

Total liabilities and partners’ capital	$	1,641,596		$	1,016,672

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
				(In thousands, except per unit data)
Sales	$	777,780		$	595,273		$	2,116,790		$	1,594,542
Cost of sales		681,179			533,167			1,922,760			1,451,141

Gross profit		96,601			62,106			194,030			143,401

Operating costs and expenses:
Selling, general and administrative		14,148			7,403			35,143			22,894
Transportation		23,696			23,258			69,462			63,460
Taxes other than income taxes		1,683			1,308			4,246			3,431
Insurance recoveries		—			—			(8,698	)		—
Other		543			565			1,781			1,373

Operating income		56,531			29,572			92,096			52,243

Other income (expense):
Interest expense		(12,577	)		(7,794	)		(30,602	)		(22,505	)
Debt extinguishment costs		—			—			(15,130	)		—
Realized loss on derivative instruments		(3,814	)		(2,288	)		(5,798	)		(8,147	)
Unrealized gain (loss) on derivative instruments		(20,335	)		1,931			(23,876	)		(13,835	)
Other		45			(121	)		148			(170	)

Total other expense		(36,681	)		(8,272	)		(75,258	)		(44,657	)

Net income before income taxes		19,850			21,300			16,838			7,586
Income tax expense		236			79			674			339

Net income	$	19,614		$	21,221		$	16,164		$	7,247

Allocation of net income:
Net income	$	19,614		$	21,221		$	16,164		$	7,247
Less:
General partner’s interest in net income		392			424			323			145
General partner’s incentive distribution rights		40			—			40			—

Net income attributable to limited partners	$	19,182		$	20,797		$	15,801		$	7,102

Weighted average limited partner units outstanding — basic		41,828			35,337			39,352			35,332

Weighted average limited partner units outstanding —diluted		41,837			35,352			39,368			35,351

Limited partners’ interest basic and diluted net income per unit	$	0.46		$	0.59		$	0.40		$	0.20

Cash distributions declared per limited partner unit	$	0.50		$	0.46		$	1.47		$	1.37

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Accumulated Other			Partners’ Capital
	Comprehensive			General			Limited Partners
	Loss			Partner			Common			Subordinated			Total
				(In thousands)
Balance at December 31, 2010	$	(27,619	)	$	18,125		$	390,843		$	16,930		$	398,279
Distributions to partners		—			(1,126	)		(49,115	)		(6,141	)		(56,382	)
Subordinated unit conversion		—			—			10,789			(10,789	)		—
Comprehensive loss:
Net income		—			363			15,801			—			16,164
Cash flow hedge loss reclassified to net income		81,294			—			—			—			81,294
Change in fair value of cash flow hedges		(180,537	)		—			—			—			(180,537	)
Defined benefit pension and retiree health benefit plans		183			—			—			—			183

Comprehensive loss														(82,896	)
Issuances of common units, net		—			—			281,870			—			281,870
Contributions from Calumet GP, LLC		—			6,011			—			—			6,011
Units repurchased for phantom unit grants		—			—			(620	)		—			(620	)
Issuance of phantom units		—			—			717			—			717
Amortization of vested phantom units		—			—			1,944			—			1,944

Balance at September 30, 2011	$	(126,679	)	$	23,373		$	652,229		$	—		$	548,923

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Operating activities
Net income	$	16,164		$	7,247
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		43,644			44,410
Amortization of turnaround costs		8,288			6,639
Non-cash interest expense		2,363			2,879
Non-cash debt extinguishment costs		14,401			—
Provision for doubtful accounts		255			74
Unrealized loss on derivative instruments		23,876			13,835
Other non-cash activities		1,830			1,467
Changes in assets and liabilities:
Accounts receivable		(44,714	)		(42,004	)
Inventories		(109,787	)		(12,964	)
Prepaid expenses and other current assets		(1,926	)		(1,103	)
Derivative activity		4,928			849
Turnaround costs		(8,849	)		(9,041	)
Other assets		(197	)		—
Deposits		(426	)		4,767
Accounts payable		54,916			68,995
Accrued salaries, wages and benefits		2,917			(419	)
Taxes payable		1,676			769
Other liabilities		(9,082	)		1,492
Pension and postretirement benefit obligations		(836	)		(190	)

Net cash provided by (used in) operating activities		(559	)		87,702
Investing activities
Additions to property, plant and equipment		(30,667	)		(27,310	)
Proceeds from insurance recoveries — equipment		1,942			—
Superior Acquisition, including a $30,574 receivable from seller		(441,626	)		—
Proceeds from sale of equipment		219			201

Net cash used in investing activities		(470,132	)		(27,109	)
Financing activities
Proceeds from borrowings — revolving credit facility		1,152,898			745,722
Repayments of borrowings — revolving credit facility		(1,107,730	)		(753,749	)
Repayments of borrowings — term loan credit facility		(367,385	)		(2,888	)
Payments on capital lease obligations		(802	)		(1,023	)
Proceeds from issuances of common units, net		281,870			793
Proceeds from 2019 senior notes offerings		586,000			—
Debt issuance costs		(23,140	)		—
Contributions from Calumet GP, LLC		6,011			18
Common units repurchased for vested phantom unit grants		(620	)		(248	)
Distributions to partners		(56,382	)		(49,179	)

Net cash provided by (used in) financing activities		470,720			(60,554	)

Net increase in cash and cash equivalents		29			39
Cash and cash equivalents at beginning of period		37			49

Cash and cash equivalents at end of period	$	66		$	88

Supplemental disclosure of cash flow information
Interest paid	$	13,381		$	19,635

Income taxes paid	$	548		$	138

See accompanying notes to unaudited condensed consolidated financial statements.

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)

1. Description of the Business

Calumet Specialty Products Partners, L.P. (the “Company”) is a Delaware limited partnership. The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of September 30, 2011, the Company had 50,779,778 common units and 1,036,322 general partner units outstanding. The number of common units outstanding includes 13,066,000 common units that converted from subordinated units on February 16, 2011. There are no longer any subordinated units outstanding. Refer to Note 10 for additional information. The general partner owns 2% of the Company while the remaining 98% is owned by limited partners. The Company is engaged in the production and marketing of crude oil-based specialty lubricating oils, white mineral oils, solvents, petrolatums, waxes and fuels. The Company owns facilities located in Shreveport, Louisiana (“Shreveport”); Superior, Wisconsin (“Superior”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”) and Dickinson, Texas (“Dickinson”) and terminals located in Burnham, Illinois (“Burnham”); Rhinelander, Wisconsin (“Rhinelander”); Crookston, Minnesota (“Crookston”) and Proctor, Minnesota (“Duluth”).

The unaudited condensed consolidated financial statements of the Company as of September 30, 2011 and for the three and nine months ended September 30, 2011 and 2010 included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States of America (the “U.S.”) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2010 Annual Report. The Company issued these unaudited condensed consolidated financial statements by filing them with the SEC and has evaluated subsequent events up to the time of filing. Refer to Note 16 for additional information on these subsequent events.

2. New Accounting Pronouncements

In January 2010, the FASB issued ASU No. 2010-06, “ Improving Disclosures About Fair Value Measurements ” (“ASU 2010-06”), which amends ASC No. 820, “Fair Value Measurements and Disclosures” to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. ASU 2010-06 also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. ASU 2010-06 is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for the requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a gross basis, which is effective for fiscal years (including interim periods) beginning after December 15, 2010. Effective January 1, 2010, the Company adopted ASU 2010-06 standard relating to disclosures about transfers in and out of Level 1 and 2 and the inputs and valuation techniques used to measure fair value. Effective January 1, 2011, the Company adopted ASU 2010-06 standard relating to the requirement to provide the Level 3 activity of purchases, sales, issuances and settlements on a gross basis. The adoption of ASU 2010-06 did not have a material impact on the Company’s financial position, results of operations or cash flows.

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. ASU 2011-04 is effective for the first reporting period (including interim periods) beginning after December 15, 2011. The Company is in process of evaluating the impact of the adoption of ASU 2011-04 on the Company’s financial statements.

In June 2011, the FASB issued ASU No. 2011-05, “ Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income ,” (“ASU 2011-05”) which amends current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income as part of the statement of partners’ capital. Instead, the Company must report comprehensive

income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for public companies during the interim and annual periods beginning after December 15, 2011 with early adoption permitted. The adoption of ASU 2011-05 will not have an impact on the Company’s consolidated financial position, results of operations or cash flows as it only requires a change in the format of the current presentation.

In September 2011, the FASB issued ASU No. 2011-09, “Intangibles — Goodwill and Other (Topic 360): Testing Goodwill for Impairment,” (“ASU 2011-09”). ASU 2011-09 allows companies to have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If after considering the totality of events and circumstances an entity determines it is not more likely than not that the fair value of a reporting unit less than its carrying amount, then performing the two-step impairment test is unnecessary. ASU 2011-09 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, however, early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011. The Company will early adopt the new authoritative guidance in the fourth quarter of 2011 in connection with its annual impairment test.

3. Superior Acquisition

On September 30, 2011, the Company completed the acquisition of the Superior, Wisconsin refinery and associated operating assets and inventories and related business of Murphy Oil Corporation (“Murphy Oil”) for aggregate consideration of approximately $411,052 excluding certain customary post-closing purchase price adjustments (“Superior Acquisition”). The Superior Acquisition was financed by a combination of (i) net proceeds of $193,621 from the Company’s September 2011 public offering of common units, (ii) net proceeds of $180,348 from the Company’s September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings under the revolving credit facility. The Company acquired the following (collectively, the “Superior Business”):

	•		Murphy Oil’s refinery located in Superior, Wisconsin and associated inventories;

	•		Superior’s wholesale marketing business and related assets, including certain owned or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin, Duluth and Crookston and Proctor, Minnesota and Toole, Utah and associated inventories and logistics assets located at each of the foregoing facilities; and

	•		Murphy Oil’s “SPUR” branded gasoline wholesale business and related assets.

The Superior refinery produces gasoline, diesel, asphalt and specialty petroleum products that are marketed in the Midwest region of the U.S., including the surrounding border states, and Canada. The Superior wholesale business transports products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota and through its own leased and owned product terminals located in Superior and Rhinelander, Wisconsin, Duluth, Crookston and Proctor, Minnesota and Toole, Utah. The Superior wholesale business also sells gasoline wholesale to SPUR branded gas stations, which are owned and operated by independent franchisees.

The Company believes the Superior Acquisition provides greater scale, geographic diversity and development potential to the Company’s refining business, as the Company’s current total refining throughput capacity has increased by 50% to 135,000 barrels per day.

As a result of the Superior Acquisition on September 30, 2011, the assets and liabilities previously held by Murphy Oil have been included in the Company’s condensed consolidated balance sheet, while the unaudited condensed consolidated statements of operations for the Company do not contain the results of the Superior Acquisition, as there were no related sales in the quarter ended September 30, 2011. In connection with the Superior Acquisition, the Company incurred acquisition costs during the third quarter of 2011 of approximately $2,072 which are reflected in selling, general and administrative expenses in the unaudited condensed consolidated statements of operations.

The Superior Acquisition purchase price allocation has not yet been finalized due to the timing of the closing of the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. The preliminary allocation of the aggregate purchase price is as follows:


	Allocation of
	Purchase Price
Inventories	$	189,609
Prepaid expenses and other current assets		713
Property, plant and equipment		238,705
Accrued salaries, wages and benefits		(775	)
Pension and postretirement benefit obligations		(17,200	)

Total purchase price	$	411,052

The following unaudited pro forma financial information reflects the consolidated results of operations of the Company as if the Superior Acquisition had taken place on January 1, 2010.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Sales	$	1,225,692	$	944,856	$	3,233,347	$	2,414,460
Net income	$	70,418	$	32,490	$	79,556	$	2,094
Limited partners’ interest net income per unit — basic and diluted	$	1.38	$	0.64	$	1.56	$	0.04

The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Superior Acquisition. This unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.

The unaudited pro forma financial information reflects interest expense as a result of the issuance of the 2019 Notes, amending and restating the revolving credit facility, additional borrowings under the revolving credit facility to fund a portion of the Superior Acquisition and the repayment of borrowings under the senior secured first lien term loan from the net proceeds of the 2019 Notes issued in April 2011. Additionally, the unaudited pro forma financial information reflects adjustments to depreciation expense as a result of the addition of fixed assets related to the Superior Acquisition at their estimated fair value, as well as adjustments to eliminate Superior’s income tax expense.

4. 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, including estimated inventories of approximately $189,609 as of September 30, 2011, related to the Superior Acquisition:


	September 30,		December 31,
	2011		2010
Raw materials	$	120,150	$	12,885
Work in process		89,494		49,006
Finished goods		236,862		85,219

	$	446,506	$	147,110

The replacement cost of these inventories, based on current market values, would have been $75,712 and $55,855 higher as of September 30, 2011 and December 31, 2010, respectively. For the three and nine months ended September 30, 2010, the Company recorded $3,488 and $4,371, respectively, of gains in cost of sales in the unaudited condensed consolidated statements of operations due to the liquidation of lower cost inventory layers. No gains from the liquidation of lower cost inventory layers have been recorded in 2011.

5. Commitments and Contingencies

From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxation and regulatory authorities, such as the LDEQ, the U.S. Environmental Protection Agency (“EPA”), the Internal Revenue Service and the Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.

Insurance Recoveries

During the second quarter of 2011, the Company reached a final settlement of its insurance claim related to the failure of an environmental operating unit at its Shreveport refinery in 2010, resulting in a gain (insurance recoveries) of $8,698 recorded for the nine months ended September 30, 2011 in the unaudited condensed consolidated statements of operations. This claim related to both property damage and business interruption. Recoveries of $1,942 related to property damage have been reflected within investing activities (with the remainder in operating activities) in the unaudited condensed consolidated statements of cash flows

Environmental

The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, regional, 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 may 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.

The Superior refinery is the subject of a consent decree (the “Consent Decree”) with the U.S. Environmental Protection Agency (“EPA”) and the Wisconsin Department of Natural Resources (“WDNR”), which requires, among other things, reductions in air emissions and the reporting of certain emissions to EPA and WDNR. In connection with the Superior Acquisition, the Company became a party to this consent decree. Equipment upgrades, other discrete tasks and annual penalties to comply with the Consent Decree are expected to cost about $4,470, but compliance with other aspects of the Consent Decree could result in additional, substantial expenditures. Any failure to comply with the Consent Decree, as well as certain emissions from the facility, will also subject the Company to stipulated penalties, which could be substantial. The Company may incur substantial costs for performance of additional environmental and safety-related projects at the Superior refinery including, but not limited to:

	•		the installation of additional process equipment to comply with EPA fuel content regulations at a cost to the Company of $2,910;

	•		the purchase of “credits” to comply with EPA fuel content regulations until such time as the additional process equipment is installed and brought online;

	•		the monitoring and remediation of historical contamination at costs of about $200 per year;

	•		the upgrade of treatment equipment or pursuit of other remedies as necessary to comply with new effluent discharge limits in a Clean Water Act permit renewal that is currently pending; and

	•		the implementation of various voluntary programs at the Superior refinery, such as removal of asbestos-containing materials or enhancement of process safety or other maintenance practices.

On December 23, 2010, the Company entered into a settlement agreement with the LDEQ regarding (i) the Company’s voluntary participation in the LDEQ’s “Small Refinery and Single Site Refinery Initiative,” and (ii) certain alleged past violations for which the LDEQ had previously initiated enforcement including (A) May 2001, December 2002 and December 2004 notifications received by the Cotton Valley refinery from the LDEQ regarding several alleged violations of various air emission regulations as well as alleged violations for the construction of a multi-tower pad and associated pump pads without a permit issued by the agency, and (B) an August 2005 notification received by the Princeton refinery from the LDEQ regarding alleged violations of air emissions regulations. The LDEQ’s “Small Refinery and Single Site Refinery 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 agreement, voluntarily entered into by the Company, requires the Company to make a $1,000 payment to the LDEQ and complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries.

The Company estimates implementation of these requirements will result in approximately $11,000 to $15,000 of capital expenditures, expenditures related to additional personnel and environmental studies over the next five years. This agreement also fully settles the aforementioned alleged environmental and permit violations at the Company’s Cotton Valley and Princeton refineries and stipulates that no further civil penalties over alleged past violations at those refineries will be pursued by the LDEQ. The required investments are expected to include projects resulting in (i) nitrogen oxide and sulfur dioxide emission reductions from heaters and boilers and the application of New Source Performance Standards for sulfur recovery plants and flaring devices, (ii) control of incidents related to acid gas flaring, tail gas and hydrocarbon flaring, (iii) electrical reliability improvements to reduce flaring, (iv) flare refurbishment at the Shreveport refinery, (v) enhancement of the Benzene Waste National Emissions Standards for Hazardous Air Pollutants programs and the Leak Detection and Repair programs at the Company’s three Louisiana refineries and (vi) Title V audits and targeted audits of certain regulatory compliance programs. During negotiations with the LDEQ, the Company voluntarily initiated projects for certain of these requirements prior to the settlement with the LDEQ, and currently anticipates completion of these projects over the next five years. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the settlement to have a material adverse effect on the Company’s financial results or operations. Before the terms of this settlement agreement are deemed final, they will require the concurrence of the Louisiana Attorney General, such concurrence anticipated to be granted during the fourth quarter of 2011.

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. The Company incurred approximately $266 of such capital expenditures at its Cotton Valley refinery during the first nine months of 2011 and completed such capital expenditures planned for 2011 at its Cotton Valley refinery. The Company incurred approximately $541 of such capital expenditures at its Cotton Valley refinery during 2010.

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

In addition, the Company is indemnified by Murphy Oil for specified environmental liabilities including: (i) certain obligations arising out of the Consent Decree (including payment of a civil penalty required under the Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or discharged by Murphy Oil. The Company is also indemnified by Murphy Oil for two years following the Superior Acquisition for liabilities arising from breaches of certain environmental representations and warranties made by Murphy Oil, subject to a maximum liability of $22,000, for which the Company is required to contribute up to the first $6,600.

Health, Safety and Maintenance

The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety, training and maintenance programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. The Company has implemented an internal program of inspection designed to monitor and enforce compliance with worker safety requirements as well as a quality system that meets the requirements of the ISO-9001-2008 Standard. The integrity of the Company’s ISO-9001-2008 Standard certification is maintained through surveillance audits by its registrar at regular intervals designed to ensure adherence to the standards.

The Company has completed studies to assess the adequacy of its process safety management practices at its Shreveport refinery with respect to certain consensus codes and standards. The Company expects to incur between $5,000 and $8,000 of capital expenditures in total

during 2011, 2012 and 2013 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards. The Company believes that its operations are in substantial compliance with OSHA and similar state laws.

Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program, which is targeting all U.S. refineries for review. On August 19, 2010, OSHA issued a Citation and Notification of Penalty (the “Shreveport Citation”) to the Company as a result of the Shreveport inspection, which included a proposed civil penalty amount of $173. The Company contested the Shreveport Citation and associated penalty amount and agreed to a final penalty amount of $119 that was paid in January 2011. Similarly, OSHA conducted an inspection of the Cotton Valley refinery’s process safety management program under OSHA’s National Emphasis Program in the first quarter of 2011. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $208. The Company has contested the Cotton Valley Citation and associated penalties and is currently in negotiations with OSHA to reach a settlement allowing an extended abatement period for a new refinery flare system study and for completion of facility site modifications, including relocation and hardening of structures.

Standby Letters of Credit

The Company has agreements with various financial institutions for standby letters of credit which have been issued to domestic vendors. As of September 30, 2011 and December 31, 2010, the Company had outstanding standby letters of credit of $207,960 and $90,725, respectively, under its senior secured revolving credit facility, which was amended and restated on June 24, 2011 (the “revolving credit facility”). Refer to Note 6 for additional information. The maximum amount of letters of credit the Company can issue at September 30, 2011 is subject to borrowing base restrictions, with a maximum letter of credit sublimit equal to $680,000, which is the greater of (i) $400,000 and (ii) 80% of revolver commitments ($850,000 at September 30, 2011) then in effect. At December 31, 2010, the maximum amount of letters of credit the Company could issue was subject to borrowing base restrictions, with a letter of credit sublimit of $300,000.

As of September 30, 2011 and December 31, 2010, the Company had availability to issue letters of credit of $271,490 and $145,454, respectively, under its revolving credit facility. As discussed in Note 6, as of September 30, 2011 the outstanding standby letters of credit issued under the revolving credit facility included a $25,000 letter of credit to support a portion of its fuel products hedging program.

6. Long-Term Debt

Long-term debt consisted of the following:


	September 30,			December 31,
	2011			2010
Borrowings under senior secured first lien term loan with third-party lenders, extinguished in 2011	$	—		$	367,385
Borrowings under senior secured revolving credit agreement with third-party lenders, amended and restated in June 2011		—			10,832
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest at prime plus 1.25% (4.50% at September 30, 2011), interest payments monthly, borrowings due June 2016		56,000			—
Borrowings under 2019 Notes, interest at a fixed rate of 9.375% at September 30, 2011, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.74% for the three months ended September 30, 2011		600,000			—
Capital lease obligations, at various interest rates, interest and principal payments quarterly through November 2013		1,042			1,781
Less unamortized discount on senior secured first lien term loan with third-party lenders, extinguished in 2011		—			(10,723	)
Less unamortized discount on 2019 Notes issued in September 2011		(14,000	)		—

Total long-term debt		643,042			369,275
Less current portion of long-term debt		749			4,844

	$	642,293		$	364,431

During the three months ended June 30, 2011, the Company restructured the majority of its outstanding long-term debt. The Company issued and sold $400,000 in aggregate principal amount 9 3/8% senior notes due May 1, 2019 (the “2019 Notes issued in April 2011”), amended its then current senior secured revolving credit agreement to allow for the issuance of the 2019 Notes, and used the majority of the proceeds from the 2019 Notes to repay borrowings under, and subsequently extinguish, the senior secured first lien term loan. The Company also amended certain of its master derivative contracts and entered into a collateral sharing agreement with its hedging counterparties. Further, the Company amended and restated its revolving credit agreement to increase the credit facility from $375,000 to $550,000, as well as amend covenants and contractual terms. Each of these activities is discussed in further detail in the following paragraphs.

During the three months ended September 30, 2011, in connection with the Superior Acquisition, the Company issued and sold $200,000 in aggregate principal amount 9 3/8% senior notes due May 1, 2019 (the “2019 Notes issued in September 2011” and, together with the 2019 Notes issued in April 2011, the “2019 Notes”), amended the collateral sharing agreement with its hedging counterparties to limit the extent to which forward purchase contracts for physical commodities would be covered by, and secured under, such agreement and increased the revolving credit facility from $550,000 to $850,000, subject to borrowing base limitations. A portion of the purchase price of the Superior Acquisition was financed with the issuance and sale of the 2019 Notes issued in September 2011 together with borrowings under the Company’s revolving credit facility. Each of these activities is discussed in further detail in the following paragraphs.

9 3/8% Senior Notes

On April 21, 2011, in connection with the restructuring of the majority of its outstanding long-term debt, the Company issued and sold $400,000 aggregate principal amount of the 2019 Notes issued in April 2011 in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at par. The 2019 Notes issued in April 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $389,037 net of underwriters’ fees and expenses, which the Company used to repay in full borrowings outstanding under its existing senior secured first lien term loan facility, as well as all accrued interest and fees, and for general partnership purposes.

On September 19, 2011, in connection with the Superior Acquisition, the Company issued and sold $200,000 in aggregate principal amount of 2019 Notes issued in September 2011 in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at a discounted price of 93 percent of par. The 2019 Notes issued in September 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received proceeds of $180,348 net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Superior Acquisition. Because the terms of the 2019 Notes issued in September 2011 are substantially identical to the terms of the 2019 Notes issued in April 2011, in this Quarterly Report, the Company collectively refers to the 2019 Notes issued in April 2011 and the 2019 Notes issued in September 2011 as the “2019 Notes.”

Interest on the 2019 Notes will be paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are guaranteed on a senior unsecured basis by all of the Company’s operating subsidiaries and certain of the Company’s future operating subsidiaries.

At any time prior to May 1, 2014, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.

On and after May 1, 2015, the Company may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:


Year	Percentage
2015		104.688	%
2016		102.344	%
2017 and at any time thereafter		100.000	%

Prior to May 1, 2015, the Company may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indentures governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

The indentures governing the 2019 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indentures governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.

Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.

In connection with the 2019 Notes offering on April 21, 2011, the Company’s then current senior secured revolving credit facility was amended on April 15, 2011, to among other things, (i) permit the issuance of the 2019 Notes issued in April 2011; (ii) upon consummation of the issuance of the 2019 Notes issued in April 2011 and the termination of the senior secured first lien credit facility, release the revolving credit facility lenders’ second priority lien on the collateral securing the senior secured first lien credit facility and (iii) change the interest rate pricing on the revolving credit facility.

Registration Rights Agreements

On April 21, 2011 and September 19, 2011, in connection with the issuances and sales of the 2019 Notes, the Company entered into registration rights agreements with the initial purchasers of the 2019 Notes obligating the Company to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2019 Notes can offer to exchange the 2019 Notes for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. The Company must use reasonable best efforts to cause the exchange offer registration statement to become effective by April 20, 2012 and remain effective until 180 days after the closing of the exchange. Additionally, the Company has agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2019 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

Senior Secured First Lien Credit Facility

The Company’s $435,000 senior secured first lien credit facility (the “term loan facility”) included a $385,000 term loan and a $50,000 prefunded letter of credit facility to support crack spread hedging. The Company extinguished this facility on April 21, 2011 in connection with the issuance and sale of the 2019 Notes, as further discussed above. The term loan bore interest at a rate equal to (i) with respect to a LIBOR Loan, the LIBOR Rate (as defined in the senior secured first lien credit agreement) plus 400 basis points and (ii) with respect to a Base Rate Loan, the Base Rate (as defined in the senior secured first lien credit agreement) plus 300 basis points. At December 31, 2010, the term loan bore interest at 4.29%. Please refer to “Amendments to Master Derivative Contracts” below for information on termination of the $50,000 prefunded letter of credit to support crack spread hedging.

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

On April 21, 2011, the Company used approximately $369,486 of the net proceeds from the issuance and sale of the 2019 Notes issued in April 2011 to repay in full its term loan, as well as accrued interest and fees, and terminated the entire senior secured first lien credit facility, including the term loan and a $50,000 prefunded letter of credit to support crack spread hedging. The Company did not incur any material early

termination penalties in connection with its termination of the senior secured first lien credit facility. Further, in the second quarter of 2011 the Company recorded approximately $15,130 of extinguishment charges related to the write off of the unamortized debt issuance costs and the unamortized discount associated with the term loan.

Amendments to Master Derivative Contracts

In connection with the termination of the term loan facility and the amendment of the senior secured revolving credit facility, on April 21, 2011, the Company entered into amendments to certain of the Company’s master derivatives contracts (“Amendments”) to provide new credit support arrangements to secure the Company’s payment obligations under these contracts following the termination of the term loan facility and the amendment and restatement of the senior secured revolving credit facility. Under the new credit support arrangements, the Company’s payment obligations under all of the Company’s master derivatives contracts for commodity hedging generally are secured by a first priority lien on the Company’s real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). The Company also issued to one counterparty a $25,000 standby letter of credit under the revolving credit facility to replace a prefunded $50,000 letter of credit previously issued under the senior secured first lien credit facility. In the event that such counterparty’s exposure to the Company exceeds $200,000, the Company will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges. The Company had no additional letters of credit or cash margin posted with any hedging party as of September 30, 2011. The Company’s master derivatives contracts and Collateral Trust Agreement continue to impose a number of covenant limitations on the Company’s operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.

Collateral Trust Agreement

In connection with the Amendments, on April 21, 2011, the Company entered into a collateral sharing agreement (the “Collateral Trust Agreement”) with each of its secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties, which governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by the Company to the secured hedging counterparties under their respective master derivatives contracts. Subject to certain conditions set forth in the Collateral Trust Agreement, the Company has the ability to add secured hedging counterparties thereto.

In connection with the closing of the Superior Acquisition, on September 30, 2011, the Company entered into an amendment (the “CTA Amendment”) to the Collateral Trust Agreement with each of its secured hedging counterparties and the administrative agent. The CTA Amendment modified the Collateral Trust Agreement so as to limit to $100,000 the extent to which forward purchase contracts for physical commodities would be covered by, and secured under, the Collateral Trust Agreement. The CTA Amendment also eliminated the credit rating requirement with respect to forward purchase contract counterparties on physical commodities.

Amended and Restated Senior Secured Revolving Credit Facility

On June 24, 2011, the Company entered into an amended and restated senior secured revolving credit facility (the “revolving credit facility”), which increased the maximum availability of credit under the revolving credit facility from $375,000 to $550,000, subject to borrowing base limitations, and included a $300,000 incremental uncommitted expansion option. On September 30, 2011, in conjunction with the Superior Acquisition, the Company fully exercised the $300,000 expansion option to increase the maximum availability of credit under the revolving credit facility from $550,000 to $850,000, subject to borrowing base limitations. The revolving credit facility, which is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations, matures in June 2016 and currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at the Company’s option. As of September 30, 2011, the margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin fluctuates quarterly based on the Company’s average availability for additional borrowings under the revolving credit agreement in the preceding calendar quarter as follows:


Quarterly Average	Margin on Base Rate			Margin on LIBOR
Availability Percentage	Revolving Loans			Revolving Loans
≥ 66%		1.00	%		2.25	%
≥ 33% and < 66%		1.25	%		2.50	%
< 33%		1.50	%		2.75	%

The borrowing capacity at September 30, 2011 under the revolving credit facility was $535,450. As of September 30, 2011, the Company had outstanding borrowings under the revolving credit facility of $56,000, leaving $271,490 available for additional borrowings based on collateral and specified availability limitations. The lenders under the revolving credit facility have a first priority lien on the Company’s cash, accounts receivable, inventory and certain other personal property.

The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $46,364, (as increased, upon the effectiveness of the increase in the maximum availability under the revolving credit facility, by the same percentage as the percentage increase in the revolving credit agreement commitments), then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0.

As of September 30, 2011, maturities of the Company’s long-term debt are as follows:


Year	Maturity
2011	$	255
2012		551
2013		236
2014		—
2015		—
Thereafter		656,000

Total	$	657,042

7. Derivatives

The Company utilizes derivative instruments to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas, the sale of fuel products and interest payments. The Company employs various hedging strategies, which are further discussed below. The Company does not hold or issue derivative instruments for trading purposes.

The Company recognizes all derivative instruments at their fair values (see Note 9) as either assets or liabilities on the condensed consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The Company’s financial results are subject to the possibility that changes in the derivative’s fair value could result in significant ineffectiveness and potentially no longer qualify for hedge accounting. The Company recorded the following derivative assets and liabilities at their fair values as of September 30, 2011 and December 31, 2010:


	Derivative Assets				Derivative Liabilities
	September 30, 2011		December 31, 2010		September 30, 2011			December 31, 2010
Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	—	$	—	$	(87,573	)	$	134,916
Gasoline swaps		—		—		(2,150	)		(14,149	)
Diesel swaps		—		—		(14,131	)		(53,744	)
Jet fuel swaps		—		—		(55,322	)		(96,556	)
Interest rate swaps:		—		—		—			(2,681	)

Total derivative instruments designated as hedges		—		—		(159,176	)		(32,214	)

Derivative instruments not designated as hedges:
Fuel products segment:
Jet fuel crack spread collars (1)		—		—		—			20
Specialty products segment: (2)
Crude oil collars		—		—		—			—
Natural gas swaps		—		—		—			—
Crude oil swaps		—		—		—			662
Interest rate swaps: (3)		—		—		(1,685	)		(1,282	)

Total derivative instruments not designated as hedges		—		—		(1,685	)		(600	)

Total derivative instruments	$	—	$	—	$	(160,861	)	$	(32,814	)


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

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

(3)		The Company refinanced its long-term debt in April 2011 and, as a result, all of its interest rate swaps that were designated as cash flow hedges for the interest payments under the previous debt agreement are no longer designated as cash flow hedges.

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

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

settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Ineffectiveness is inherent in the hedging of crude oil and fuel products. Due to the volatility in the markets for crude oil and fuel products, the Company is unable to predict the amount of ineffectiveness each period, which has the potential for the future loss of hedge accounting, determined on a derivative by derivative basis or in the aggregate for a specific commodity. Ineffectiveness has resulted, and the loss of hedge accounting would result, in increased volatility in the Company’s financial results. However, even though derivatives may not qualify for hedge accounting, the Company intends to continue to hold the instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize fuel products margins.

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital as of, and for the three months ended, September 30, 2011 and 2010 related to its derivative instruments that were designated as cash flow hedges:


							Amount of (Gain)
	Amount of Gain (Loss)						Loss Reclassified
	Recognized in						from Accumulated
	Accumulated Other						Other Comprehensive							Amount of Loss
	Comprehensive Income (Loss)						Income (Loss) into							Recognized in Net
	on Derivatives						Net Income							Income on Derivatives
	(Effective Portion)						(Effective Portion)							(Ineffective Portion)
	Three Months Ended						Location of	Three Months Ended							Three Months Ended
	September 30,						(Gain)	September 30,						Location of	September 30,
Type of Derivative	2011			2010			Loss	2011			2010			Loss	2011			2010
Fuel products segment:
Crude oil swaps	$	(171,581	)	$	59,678		Cost of sales	$	(26,775	)	$	(16,163	)	Unrealized/ Realized	$	(22,072	)	$	(221	)
Gasoline swaps		5,883			(7,342	)	Sales		4,493			3,836		Unrealized/ Realized		(19	)		(9	)
Diesel swaps		46,413			(28,924	)	Sales		18,887			7,736		Unrealized/ Realized		(252	)		(404	)
Jet fuel swaps		81,523			(31,444	)	Sales		37,745			—		Unrealized/ Realized		(1,793	)		(50	)
Specialty products segment:
Crude oil collars		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Crude oil swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Natural gas swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Interest rate swaps:					(1,124	)	Interest expense		—			639		Unrealized/ Realized		—			—

Total	$	(37,762	)	$	(9,156	)		$	34,350		$	(3,952	)		$	(24,136	)	$	(684	)

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital for the three months ended September 30, 2011 and 2010 related to its derivative instruments not designated as cash flow hedges:


	Amount of Gain (Loss)						Amount of Gain (Loss)
	Recognized in						Recognized
	Realized Loss on						in Unrealized Gain (Loss) on
	Derivatives						Derivatives
	Three Months Ended						Three Months Ended
	September 30,						September 30,
Type of Derivative	2011			2010			2011			2010
Fuel products segment:
Crude oil swaps	$	—		$	(1,939	)	$	—		$	1,357
Gasoline swaps		—			3,071			—			(2,284	)
Diesel swaps		—			(326	)		—			326
Jet fuel swaps		—			—			—			—
Jet fuel collars		—			—			(1	)		(33	)
Specialty products segment:
Crude oil collars		—			(1,396	)		—			1,759
Crude oil swaps		—			(56	)		—			275
Natural gas swaps		—			(136	)		—			(187	)
Interest rate swaps:		(655	)		(205	)		643			101

Total	$	(655	)	$	(987	)	$	642		$	1,314

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital as of, and for the nine months ended, September 30, 2011 and 2010 related to its derivative instruments that were designated as cash flow hedges:


							Amount of (Gain)
	Amount of Gain (Loss)						Loss Reclassified
	Recognized in						from Accumulated
	Accumulated Other						Other Comprehensive							Amount of Gain (Loss)
	Comprehensive Loss						Loss into							Recognized in Net
	on Derivatives						Net Income							Income on Derivatives
	(Effective Portion)						(Effective Portion)							(Ineffective Portion)
	Nine Months Ended						Location of	Nine Months Ended							Nine Months Ended
	September 30,						(Gain)	September 30,						Location of Gain	September 30,
Type of Derivative	2011			2010			Loss	2011			2010			(Loss)	2011			2010
Fuel products segment:
Crude oil swaps	$	(110,393	)	$	(19,677	)	Cost of sales	$	(85,209	)	$	(51,849	)	Unrealized/ Realized	$	(22,569	)	$	(10,194	)
Gasoline swaps		(11,853	)		12,307		Sales		23,308			14,894		Unrealized/ Realized		(1,358	)		(4,560	)
Diesel swaps		(22,379	)		3,633		Sales		62,074			23,546		Unrealized/ Realized		(790	)		(1,628	)
Jet fuel swaps		(37,891	)		(13,821	)	Sales		80,419			—		Unrealized/ Realized		(3,397	)		116
Specialty products segment:
Crude oil collars		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Crude oil swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Natural gas swaps		—			—		Cost of sales		—			—		Unrealized/ Realized		—			—
Interest rate swaps:		1,979			(2,522	)	Interest expense		702			1,936		Unrealized/ Realized		—			—

Total	$	(180,537	)	$	(20,080	)		$	81,294		$	(11,473	)		$	(28,114	)	$	(16,266	)

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations and its unaudited condensed consolidated statements of partners’ capital for the nine months ended September 30, 2011 and 2010 related to its derivative instruments not designated as cash flow hedges:


	Amount of Gain (Loss)						Amount of Gain (Loss)
	Recognized in						Recognized
	Realized Loss on						in Unrealized Loss
	Derivatives						on Derivatives
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
Type of Derivative	2011			2010			2011			2010
Fuel products segment:
Crude oil swaps	$	—		$	(6,329	)	$	—		$	8,295
Gasoline swaps		—			10,174			—			(11,487	)
Diesel swaps		—			(976	)		—			976
Jet fuel swaps		—			—			—			—
Jet fuel collars		(562	)		—			542			(321	)
Specialty products segment:
Crude oil collars		—			(4,355	)		—			491
Crude oil swaps		932			(1,718	)		(662	)		28
Natural gas swaps		—			(171	)		—			(263	)
Interest rate swaps:		(1,407	)		(611	)		(403	)		551

Total	$	(1,037	)	$	(3,986	)	$	(523	)	$	(1,730	)

The cash flow impact of the Company’s derivative activities is classified as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows.

The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company executes all of its derivative instruments with large financial institutions that have ratings of at least Baa1 and A by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark to market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed upon thresholds in its contracts with these counterparties. No such collateral was held by the Company as of September 30, 2011 or December 31, 2010. The Company’s contracts with these counterparties allow for netting of derivative instrument positions executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits, on the Company’s condensed consolidated balance sheets and not netted against derivative assets or liabilities. As of September 30, 2011, the Company had provided its counterparties with no collateral above the

$25,000 letter of credit provided to one counterparty to support crack spread hedging. As of December 31, 2010, the Company had provided its counterparties with no cash collateral or letters of credit above the $50,000 prefunded letter of credit then in effect and provided to one counterparty to support crack spread hedging. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.

Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating was lowered below its current level by either Moody’s or S&P, such counterparties would have the right to reduce the applicable threshold to zero and demand full collateralization of the Company’s net liability position on outstanding derivative instruments. As of September 30, 2011 and December 31, 2010, there was a net liability of $1,892 and $388, respectively, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.

The effective portion of the hedges classified in accumulated other comprehensive loss is $122,009 as of September 30, 2011, and absent a change in the fair market value of the underlying transactions, will be reclassified to earnings by December 31, 2014 with balances being recognized as follows:


	Accumulated Other
	Comprehensive
Year	Loss
2011	$	(20,955	)
2012		(92,780	)
2013		(7,415	)
2014		(859	)

Total	$	(122,009	)

Based on fair values as of September 30, 2011, the Company expects to reclassify $97,292 of net losses on derivative instruments from accumulated other comprehensive loss to earnings during the next twelve months due to actual crude oil purchases and gasoline, diesel and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the date of settlements.

Crude Oil Swap and Collar Contracts — Specialty Products Segment

The Company is exposed to fluctuations in the price of crude oil, its principal raw material. The Company utilizes combinations of options and swaps to manage crude oil price risk and volatility of cash flows in its specialty products segment. These derivatives may be designated as cash flow hedges of the future purchase of crude oil if they meet the hedge criteria. The Company’s general policy is to enter into crude oil derivative contracts that mitigate the Company’s exposure to price risk associated with crude oil purchases related to specialty products production (for up to 70% of expected purchases). While the Company’s policy generally requires that these positions be short term in nature and expire within three to nine months from execution, the Company may execute derivative contracts for up to two years forward, if a change in the risks supports lengthening the Company’s position. As of September 30, 2011, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.

At December 31, 2010, the Company had the following crude oil derivatives related to crude oil purchases in its specialty products segment, none of which were designated as cash flow hedges.


					Average
	Barrels				Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
February 2011		33,600		1,200	$	83.10
March 2011		37,200		1,200		83.55

Totals		70,800
Average price					$	83.34

Crude Oil Swap Contracts — Fuel Products Segment

The Company is exposed to fluctuations in the price of crude oil, its principal raw material. The Company utilizes swap contracts to manage crude oil price risk and volatility of cash flows in its fuel products segment. The Company’s policy is generally to enter into crude oil swap contracts for a period no greater than five years forward and for no more than 75% of crude oil purchases used in fuels production. At September 30, 2011, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.


					Average
	Barrels				Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Fourth Quarter 2011		1,334,000		14,500	$	77.71
Calendar Year 2012		5,626,000		15,372		87.43
Calendar Year 2013		3,690,000		10,110		98.81
Calendar Year 2014		1,000,000		2,740		90.55

Totals		11,650,000
Average price					$	90.19

At December 31, 2010, the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges.


					Average
	Barrels				Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
First Quarter 2011		1,215,000		13,500	$	75.32
Second Quarter 2011		1,729,000		19,000		76.62
Third Quarter 2011		1,610,000		17,500		77.38
Fourth Quarter 2011		1,334,000		14,500		77.71
Calendar Year 2012		5,535,000		15,123		86.30

Totals		11,423,000
Average price					$	81.41

Fuel Products Swap Contracts

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

Diesel Swap Contracts

At September 30, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


					Average
					Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Fourth Quarter 2011		552,000		6,000	$	91.74
Calendar Year 2012		1,651,000		4,511		103.79
Calendar Year 2013		1,466,000		4,016		123.49

Totals		3,669,000
Average price					$	109.85

At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


					Average
					Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2011		630,000		7,000	$	89.57
Second Quarter 2011		637,000		7,000		89.57
Third Quarter 2011		552,000		6,000		91.74
Fourth Quarter 2011		552,000		6,000		91.74
Calendar Year 2012		1,560,000		4,262		99.27

Totals		3,931,000
Average price					$	94.03

Jet Fuel Swap Contracts

At September 30, 2011, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


					Average
					Swap
Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Fourth Quarter 2011		644,000		7,000	$	89.21
Calendar Year 2012		3,838,500		10,488		99.78
Calendar Year 2013		2,044,000		5,600		125.13
Calendar Year 2014		1,000,000		2,740		115.56

Totals		7,526,500
Average price					$	107.86

At December 31, 2010, the Company had the following derivatives related to diesel and jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


					Average
					Swap
Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2011		405,000		4,500	$	86.12
Second Quarter 2011		819,000		9,000		89.58
Third Quarter 2011		920,000		10,000		89.86
Fourth Quarter 2011		644,000		7,000		89.21
Calendar Year 2012		3,838,500		10,488		99.78

Totals		6,626,500
Average price					$	95.28

Gasoline Swap Contracts

At September 30, 2011, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


					Average
					Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
Fourth Quarter 2011		138,000		1,500	$	85.50
Calendar Year 2012		136,500		373		89.04
Calendar Year 2013		180,000		493		110.38

Totals		454,500
Average price					$	96.41

At December 31, 2010, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


					Average
					Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold		BPD		($/Bbl)
First Quarter 2011		180,000		2,000	$	81.84
Second Quarter 2011		273,000		3,000		82.66
Third Quarter 2011		138,000		1,500		85.50
Fourth Quarter 2011		138,000		1,500		85.50
Calendar Year 2012		136,500		373		89.04

Totals		865,500
Average price					$	84.40

Jet Fuel Put Spread Contracts

At September 30, 2011, the Company had the following jet fuel put options related to jet fuel crack spreads in its fuel products segment, none of which are designated as cash flow hedges.


					Average		Average
					Sold Put		Bought Put
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
Fourth Quarter 2011		184,000		2,000	$	4.75	$	7.00

Totals		184,000
Average price					$	4.75	$	7.00

At December 31, 2010, the Company had the following jet fuel put options related to jet fuel crack spreads in its fuel products segment, none of which are designated as cash flow hedges.


					Average		Average
					Sold Put		Bought Put
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
First Quarter 2011		630,000		7,000	$	4.00	$	6.00
Fourth Quarter 2011		184,000		2,000		4.75		7.00

Totals		814,000
Average price					$	4.17	$	6.23

Natural Gas Swap Contracts

Natural gas purchases comprise a significant component of the Company’s cost of sales; therefore, changes in the price of natural gas also significantly affect its profitability and cash flows. The Company utilizes swap contracts to manage natural gas price risk and volatility of cash flows. The Company’s policy is generally to enter into natural gas derivative contracts to hedge no more than 75% of its upcoming fall and winter months’ anticipated natural gas requirement for a period no greater than three years forward. At September 30, 2011 and December 31, 2010, the Company had no derivatives outstanding related to natural gas purchases.

Interest Rate Swap Contracts

The Company’s profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of the Company’s interest rate risk management activities is to hedge its exposure to changes in interest rates. Historically, the Company’s policy has been to enter into interest rate swap agreements to hedge up to 75% of its interest rate risk related to variable rate debt. With the issuances of the 2019 Notes, which constitute fixed rate debt, the Company does not expect to enter into additional hedges to fix its interest rates.

During 2010, the Company entered into forward swap contracts to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan. The Company hedged the future interest payments related to $100,000 of the total outstanding term loan indebtedness for the period from February 15, 2011 to February 15, 2012 pursuant to these forward swap contracts. These swap contracts were designated as cash flow hedges of the future payments of interest with three-month LIBOR fixed at an average rate during the hedge period of 2.03%. Due to the repayment of the variable rate senior secured first lien term loan in April 2011 with proceeds from the issuance of the 2019 Notes, the interest rate swap contract was discontinued as a cash flow hedge for the future payment of interest.

In 2009, the Company hedged the future interest payments related to $200,000 of its total outstanding term loan indebtedness for the period from February 15, 2010 to February 15, 2011. This swap contract was designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at an average rate during the hedge period of 0.94%. The cash flow hedge settled during the first quarter of 2011.

In 2008, 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 which closed January 3, 2008. The Company hedged the future interest payments related to $50,000 of the total outstanding term loan indebtedness in 2010, pursuant to this forward swap contract. This swap contract was designated as a cash flow hedge of the future payment of interest with three-month LIBOR fixed at 3.66% per annum in 2010 and the first quarter of 2011. The cash flow hedge settled during the first quarter of 2011.

In 2006, the Company entered into a forward swap contract to manage interest rate risk related to a portion of its then existing variable rate senior secured first lien term loan. Due to the repayment of $19,000 of the outstanding balance of the Company’s then existing term loan facility in August 2007 and subsequent refinancing of the remaining term loan balance, this swap contract was not designated as a cash flow hedge of the future payment of interest. The entire change in the fair value of this interest rate swap is recorded to unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations. In the first quarter of 2008, the Company fixed its unrealized loss on this interest rate swap derivative instrument by entering into an offsetting interest rate swap expiring December 2012, which is not designated as a cash flow hedge.

8. Fair Value of Financial Instruments

The Company’s financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and indebtedness. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The fair value of the Company’s 2019 Notes issued in April 2011 and the 2019 Notes issued in September 2011 were $384,000 and $192,000, respectively at September 30, 2011, using quoted market prices. The fair value of the Company’s term loan was $355,445 at December 31, 2010, using quoted market prices. The carrying values of borrowings under the Company’s revolving credit facility were $56,000 and $10,832 at September, 2011 and December 31, 2010, respectively, and approximate their fair values.

9. Fair Value Measurements

The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded, and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.

As of September 30, 2011, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to crude oil, gasoline, diesel, jet fuel and interest rates and investments associated with the Company’s non-contributory defined benefit plan (“Pension Plan”).

The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least Baa1 and A by Moody’s and S&P, respectively. To estimate the fair values of the Company’s derivative instruments, the Company uses the market approach. Under this approach, the fair values of the Company’s derivative instruments for crude oil, gasoline, diesel, jet fuel and interest rates are determined primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Generally, the Company obtains this data through surveying its counterparties and performing various analytical tests to validate the data. The Company determines the fair value of its crude oil option contracts utilizing a standard option pricing model based on inputs that can be derived from information available in publicly quoted markets, or are quoted by counterparties to these contracts. In situations where the Company obtains inputs via quotes from its counterparties, it verifies the reasonableness of these quotes via similar quotes from another counterparty as of each date for which financial statements are prepared. The Company also includes an adjustment for non-performance risk in the recognized measure of fair value of all of the Company’s derivative instruments. The adjustment reflects the full credit default spread (“CDS”) applied to a net exposure by counterparty. When the Company is in a net asset position, it uses its counterparty’s CDS, or a peer group’s estimated CDS when a CDS for the counterparty is not available. The Company uses its own peer group’s estimated CDS when it is in a net liability position. As a result of applying the applicable CDS, at September 30, 2011 and December 31, 2010, the Company’s liability was reduced by approximately $7,159 and $687, respectively. Based on the use of various unobservable inputs, principally non-performance risk and unobservable inputs in forward years for gasoline, jet fuel and diesel, the Company has categorized these derivative instruments as Level 3. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds.

The Company’s investments associated with its Pension Plan primarily consist of (i) mutual funds that are publicly traded and (ii) a commingled fund. The mutual funds are publicly traded and market prices are readily available; thus, these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of shares held by the Pension Plan at quarter end.

The Company’s assets and liabilities measured at fair value at September 30, 2011 were as follows:


	Fair Value Measurements - (b)
	Level 1		Level 2 (a)		Level 3			Total
Assets:
Cash and cash equivalents	$	66	$	—	$	—		$	66
Crude oil swaps		—		—		—			—
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Pension plan investments		14,598		2,391		—			16,989

Total assets at fair value	$	14,664	$	2,391	$	—		$	17,055

Liabilities:
Crude oil swaps	$	—	$	—	$	(87,573	)	$	(87,573	)
Gasoline swaps		—		—		(2,150	)		(2,150	)
Diesel swaps		—		—		(14,131	)		(14,131	)
Jet fuel swaps		—		—		(55,322	)		(55,322	)
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(1,685	)		(1,685	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(160,861	)	$	(160,861	)


(a)		Transferred from Level 1 to Level 2 in the first quarter of 2011 because of lack of observable market data in the underlying investments.

(b)		The table excludes the pension plan assets from the Superior Acquisition of $17,718. The final determination of the fair value for these assets will be completed as soon as the information necessary to complete the analysis is obtained.

The Company’s financial assets and liabilities measured at fair value at December 31, 2010 were as follows:


	Fair Value Measurements
	Level 1		Level 2		Level 3			Total
Assets:
Cash and cash equivalents	$	37	$	—	$	—		$	37
Crude oil swaps		—		—		135,578			135,578
Gasoline swaps		—		—		—			—
Diesel swaps		—		—		—			—
Jet fuel swaps		—		—		—			—
Crude oil options		—		—		—			—
Jet fuel options		—		—		20			20
Pension plan investments		16,039		—		—			16,039

Total assets at fair value	$	16,076	$	—	$	135,598		$	151,674

Liabilities:
Crude oil swaps	$	—	$	—	$	—		$	—
Gasoline swaps		—		—		(14,149	)		(14,149	)
Diesel swaps		—		—		(53,744	)		(53,744	)
Jet fuel swaps		—		—		(96,556	)		(96,556	)
Crude oil options		—		—		—			—
Jet fuel options		—		—		—			—
Interest rate swaps		—		—		(3,963	)		(3,963	)
Pension plan investments		—		—		—			—

Total liabilities at fair value	$	—	$	—	$	(168,412	)	$	(168,412	)

The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the nine months ended September 30, 2011 and 2010:


	Nine Months Ended
	September 30,
	2011			2010
Fair value at January 1,	$	(32,814	)	$	26,138
Realized losses		5,798			8,147
Unrealized losses		(23,876	)		(13,835	)
Change in fair value of cash flow hedges		(180,537	)		(20,080	)
Settlements		70,568			(20,469	)
Transfers in (out) of Level 3		—			—

Fair value at September 30,	$	(160,861	)	$	(20,099	)

Total losses included in net loss attributable to changes in unrealized losses relating to financial assets and liabilities held as of September 30,	$	(23,876	)	$	(13,835	)

All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives, cost of sales for crude oil and natural gas derivatives, and interest expense for interest rate derivatives in the unaudited condensed consolidated financial statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments are recorded in earnings immediately in unrealized loss on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized loss on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 7 for further information on derivative instruments.

10. Partners’ Capital

In February 2011, the Company satisfied the last of the earnings and distributions tests contained in its partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution paid on February 14, 2011. Two days following this quarterly distribution to unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.

On February 24, 2011, the Company completed an equity offering of its common units in which it sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $92,290 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $3,915. The Company’s general partner contributed $1,970 to retain its 2% general partner interest.

On September 8, 2011, the Company completed an equity offering of its common units in which it sold 11,000,000 common units to the underwriters of the offering at a price of $18.00 per common unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $189,580 and were used to fund a portion of the purchase price of the Superior Acquisition. Underwriting discounts totaled $7,866. The Company’s general partner contributed $4,041 to retain its 2% general partner interest. See Note 3 for further information on the Superior Acquisition.

For the three and nine months ended September 30, 2011 and 2010 the general partner was allocated $40 and $0, respectively, in incentive distribution rights.

11. Comprehensive Income (Loss)

Comprehensive income (loss) for the Company includes the change in fair value of cash flow hedges and the minimum pension liability adjustment that have not been recognized in net income. Comprehensive income (loss) for the three and nine months ended September 30, 2011 and 2010 was as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Net income	$	19,614		$	21,221		$	16,164		$	7,247
Cash flow hedge (gain) loss reclassified to net income		34,350			(3,952	)		81,294			(11,473	)
Change in fair value of cash flow hedges		(37,762	)		(9,156	)		(180,537	)		(20,080	)
Defined benefit pension and retiree health benefit plans		61			59			183			523

Total comprehensive income (loss)	$	16,263		$	8,172		$	(82,896	)	$	(23,783	)

12. Unit-Based Compensation and Distributions

A summary of the Company’s nonvested phantom units as of September 30, 2011 and the changes during the nine months ended September 30, 2011 is presented below:


				Weighted Average
				Grant Date
Nonvested Phantom Units	Grant			Fair Value
Nonvested at December 31, 2010		105,492		$	17.68
Granted		55,355			21.31
Vested		(57,482	)		19.78
Forfeited		—			—

Nonvested at September 30, 2011		103,365		$	18.45

For the three months ended September 30, 2011 and 2010, compensation expense of $662 and $151, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. For the nine months ended September 30, 2011 and 2010, compensation expense of $1,944 and $443, respectively, was recognized in the unaudited condensed consolidated statements of operations related to vested phantom unit grants. As of September 30, 2011 and 2010, there was a total of $1,907 and $928, respectively, of unrecognized compensation costs related to nonvested phantom unit grants. These costs are expected to be recognized over a weighted-average period of approximately three years.

The Company’s distribution policy is as defined in its partnership agreement. For the three months ended September 30, 2011 and 2010, the Company made distributions of $20,124 and $16,391, respectively, to its partners. For the nine months ended September 30, 2011 and 2010, the Company made distributions of $56,382 and $49,179, respectively, to its partners.

13. Employee Benefit Plans

The components of net periodic pension and other post retirement benefits cost for the three months ended September 30, 2011 and 2010 were as follows:


	For the Three Months Ended September 30,
	2011						2010
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	24		$	—		$	21		$	—
Interest cost		332			5			334			6
Expected return on assets		(264	)		—			(259	)		—
Amortization of net (gain) loss		71			(1	)		69			(1	)
Prior service cost		—			(8	)		—			(9	)

Net periodic benefit cost	$	163		$	(4	)	$	165		$	(4	)

The components of net periodic pension and other post retirement benefits cost for the nine months ended September 30, 2011 and 2010 were as follows:


	For the Nine Months Ended September 30,
	2011						2010
				Other Post						Other Post
	Pension			Retirement			Pension			Retirement
	Benefits			Employee Benefits			Benefits			Employee Benefits
Service cost	$	73		$	—		$	63		$	—
Interest cost		998			14			1,002			18
Expected return on assets		(793	)		—			(776	)		—
Amortization of net (gain) loss		211			(2	)		206			(2	)
Prior service cost		—			(26	)		—			(27	)

Net periodic benefit cost	$	489		$	(14	)	$	495		$	(11	)

During the three months ended September 30, 2011 and 2010, the Company made contributions of $374 and $337, respectively, to its non-contributory defined benefit plan (the “Pension Plan”). During the nine months ended September 30, 2011 and 2010, the Company made contributions of $1,310 and $337, respectively, and expects to make total contributions to its Pension Plan in 2011 of $1,918.

At September 30, 2011, the Company’s investments associated with its Pension Plan primarily consist of (i) mutual funds that are publicly traded and (ii) a commingled fund. The mutual funds are publicly traded and market prices of the mutual funds are readily available; thus, these investments are categorized as Level 1. The commingled fund is categorized as Level 2 because inputs used in its valuation are not quoted prices in active markets that are indirectly observable and is valued at the net asset value of the shares held by the Pension Plan at quarter end. The Company’s Pension Plan assets measured at fair value at September 30, 2011 and December 31, 2010 were as follows:


	September 30, 2011				December 31, 2010
	Pension Benefits (a)				Pension Benefits
	Level 1		Level 2		Level 1		Level 2
Cash	$	3,903	$	—	$	347	$	—
Equity		3,567		—		7,784		—
Foreign equities		664		—		1,890		—
Commingled fund		—		2,391		—		—
Fixed income		6,464		—		6,018		—

	$	14,598	$	2,391	$	16,039	$	—


(a)		The table excludes the pension plan assets from the Superior Acquisition of $17,718, for which the Company is awaiting final information.

14. Transactions with Related Parties

On March 24, 2011, Calumet Lubricants Co., Limited Partnership (“Calumet Lubricants”), a wholly owned subsidiary of the Company, entered into Amendment No. 5 (the “Princeton Amendment”) to that certain Crude Oil Supply Agreement, effective as of April 30, 2008 (as amended since such date, the “Princeton Crude Oil Supply Agreement”), by and between Calumet Lubricants and Legacy Resources Co., L.P. (“Legacy”), under which Legacy supplied the Company’s Princeton refinery with all of the refinery’s crude oil requirements on a just-in-time basis. The Princeton Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Princeton Crude Oil Supply Agreement and shortened the termination notice period set forth in the Princeton Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Princeton Amendment, on March 24, 2011, Calumet Lubricants provided notice to Legacy that it was exercising its contractual rights under the Princeton Crude Oil Supply Agreement, as amended by the Princeton Amendment, to terminate the Princeton Crude Oil Supply Agreement on May 31, 2011. The Company did not incur any material early termination penalties in connection with its termination of the Princeton Crude Oil Supply Agreement.

On March 24, 2011, Calumet Shreveport Fuels, LLC (“Calumet Shreveport Fuels”), a wholly owned subsidiary of the Company, entered into Amendment No. 5 (the “Shreveport Amendment”) to that certain Crude Oil Supply Agreement, effective as of September 1, 2009 (as amended since such date, the “Shreveport Crude Oil Supply Agreement”), by and between Calumet Shreveport Fuels and Legacy, under which Legacy supplies the Company’s Shreveport refinery with a portion of the refinery’s crude oil requirements on a just-in-time basis. The Shreveport Amendment, effective as of March 1, 2011, modified the market-based pricing mechanism established in the Shreveport Crude Oil

Supply Agreement and shortened the termination notice period set forth in the Shreveport Crude Oil Supply Agreement from approximately 90 days to approximately 60 days. Concurrent with entering into the Shreveport Amendment, on March 24, 2011, Calumet Shreveport Fuels provided notice to Legacy that it was exercising its contractual rights under the Shreveport Crude Oil Supply Agreement, as amended by the Shreveport Amendment, to terminate the Shreveport Crude Oil Supply Agreement on May 31, 2011. The Company did not incur any material early termination penalties in connection with its termination of the Shreveport Crude Oil Supply Agreement.

With the termination of the agreements, the Company has one remaining crude oil supply agreement with Legacy, the Master Crude Oil Purchase and Sale Agreement, that was entered into on January 26, 2009. No crude oil is currently being purchased by the Company under this agreement.

Legacy is owned in part by three of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and vice chairman, F. William Grube, and the Company’s president and chief operating officer, Jennifer G. Straumins. During the three and nine months ended September 30, 2011, the Company had crude oil purchases of $285 and $241,572, respectively, from Legacy. Accounts payable to Legacy at September 30, 2011 were $97.

15. Segments and Related Information

a. Segment Reporting

The Company has two reportable segments: Specialty Products and Fuel Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes and asphalt and other by-products. These products are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. The Fuel Products segment produces a variety of fuel and fuel-related products including gasoline, diesel and jet fuel. Because of their similar economic characteristics, certain operations have been aggregated for segment reporting purposes. As a result of the Superior Acquisition on September 30, 2011, the assets and liabilities from the Superior Acquisition have been included in the Company’s condensed consolidated balance sheets, while the unaudited condensed consolidated statements of operations for the Company do not contain the results of the Superior Acquisition, as there was no related revenue in the current period.

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 operating income (loss). The Company accounts for intersegment sales and transfers at cost plus a specified mark-up. Reportable segment information is as follows:


	Specialty		Fuel		Combined					Consolidated
Three Months Ended September 30, 2011	Products		Products		Segments		Eliminations			Total
Sales:
External customers	$	477,489	$	300,291	$	777,780	$	—		$	777,780
Intersegment sales		285,559		13,271		298,830		(298,830	)		—

Total sales	$	763,048	$	313,562	$	1,076,610	$	(298,830	)	$	777,780

Depreciation and amortization		17,930		—		17,930		—			17,930
Operating income		54,404		2,127		56,531		—			56,531
Reconciling items to net income:
Interest expense											(12,577	)
Loss on derivative instruments											(24,149	)
Other											45
Income tax expense											(236	)

Net income										$	19,614

Capital expenditures	$	10,032	$	—	$	10,032	$	—		$	10,032


	Specialty		Fuel			Combined					Consolidated
Three Months Ended September 30, 2010	Products		Products			Segments		Eliminations			Total
Sales:
External customers	$	386,051	$	209,222		$	595,273	$	—		$	595,273
Intersegment sales		200,728		7,286			208,014		(208,014	)		—

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

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

Net income											$	21,221

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


	Specialty		Fuel			Combined					Consolidated
Nine Months Ended September 30, 2011	Products		Products			Segments		Eliminations			Total
Sales:
External customers	$	1,341,005	$	775,785		$	2,116,790	$	—		$	2,116,790
Intersegment sales		792,987		32,178			825,165		(825,165	)		—

Total sales	$	2,133,992	$	807,963		$	2,941,955	$	(825,165	)	$	2,116,790

Depreciation and amortization		54,295		—			54,295		—			54,295
Operating income (loss)		106,359		(14,263	)		92,096		—			92,096
Reconciling items to net income:
Interest expense												(30,602	)
Debt extinguishment costs												(15,130	)
Loss on derivative instruments												(29,674	)
Other												148
Income tax expense												(674	)

Net income											$	16,164

Capital expenditures	$	30,667	$	—		$	30,667	$	—		$	30,667


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

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

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

Net income										$	7,247

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


	September 30, 2011		December 31, 2010
Segment assets:
Specialty products	$	1,121,912	$	962,850
Fuel products		519,684		53,822

Total assets	$	1,641,596	$	1,016,672

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three months and nine months ended September 30, 2011 and 2010. 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, jet fuel and by-products. The following table sets forth the major product category sales:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Specialty products:
Lubricating oils	$	262,175	$	214,926	$	717,674	$	555,328
Solvents		126,709		102,276		380,687		285,907
Waxes		38,908		34,089		107,089		88,698
Fuels		1,047		298		2,470		4,268
Asphalt and other by-products		48,650		34,462		133,085		86,749

Total	$	477,489	$	386,051	$	1,341,005	$	1,020,950

Fuel products:
Gasoline		132,286		73,550		355,519		225,720
Diesel		116,914		97,405		290,678		239,031
Jet fuel		47,190		34,998		114,650		100,378
By-products		3,901		3,269		14,938		8,463

Total	$	300,291	$	209,222	$	775,785	$	573,592

Consolidated sales	$	777,780	$	595,273	$	2,116,790	$	1,594,542

d. Major Customers

During the three and nine months ended September 30, 2011 and 2010, the Company had no customer that represented 10% or greater of consolidated sales.

16. Subsequent Events

On October 5, 2011, Calumet Superior, LLC (“Calumet Superior”), a wholly-owned subsidiary of the Company, entered into a Crude Oil Purchase Agreement (the “BP Purchase Agreement”) with BP Products North America Inc. (“BP”), pursuant to which BP will supply the Superior refinery with approximately 75% of its daily crude oil requirements, with such requirements estimated to be between 35,000 and 45,000 barrels per day, utilizing a market-based pricing mechanism, plus transportation and handling costs. The BP Purchase Agreement is effective as of October 1, 2011, with deliveries commencing November 1, 2011. The BP Purchase Agreement has an initial term of seven months, will automatically renew for successive one-year terms and may be terminated by either party on written notice delivered at least 90 days prior to the end of the then-current term. To secure a portion of Calumet Superior’s payment obligations under the BP Purchase Agreement, the Company and its affiliates have granted a limited interest in the collateral pledged as security under the Collateral Trust Agreement to BP as a “Forward Purchase Secured Hedge Counterparty” under the Collateral Trust Agreement, as such term is defined therein.

On October 11, 2011, the Company declared a quarterly cash distribution of $0.50 per unit on all outstanding units, or approximately $26,362 in aggregate, for the quarter ended September 30, 2011. The distribution will be paid on November 14, 2011 to unitholders of record as of the close of business on November 4, 2011. This quarterly distribution of $0.50 per unit equates to $2.00 per unit, or approximately $105,448 in aggregate on an annualized basis.

On October 13, 2011, the underwriters of the Company’s September 8, 2011 public equity offering elected to exercise a portion of their overallotment option. As a result, the Company sold an additional 750,000 common units to the underwriters at the offering price of $18.00 per unit, less the underwriting discount. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $12,910 and were used to repay borrowings under its revolving credit facility. Underwriting discounts totaled $540. The Company’s general partner contributed $276 to retain its 2% general partner interest.

The fair value of the Company’s derivatives increased by approximately $32,000 subsequent to September 30, 2011 to a liability of approximately $129,000. The fair value of the Company’s long-term debt, excluding capital leases, has not changed materially subsequent to September 30, 2011.

In addition, subsequent to the closing of the Superior Acquisition on September 30, 2011, the Company entered into additional derivative positions to hedge the increased exposure to crack spreads resulting from the Superior Acquisition. The following tables provide a summary of such derivatives entered into as of November 4, 2011, all of which are designated as cash flow hedges.


					Average
	Barrels				Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Fourth Quarter 2011		552,000		6,000	$	78.50
Calendar Year 2012		5,490,000		15,000		83.35

Totals		6,042,000
Average price					$	82.90

Average

Barrels

Swap

Diesel Swap Contracts by Expiration Dates

Sold

BPD

($/Bbl)

Calendar Year 2012

1,830,000

5,000

115.27

Totals

1,830,000

Average price

115.27


					Average
	Barrels				Swap
Gasoline Swap Contracts by Expiration Dates	Sold		BPD		($/Bbl)
Fourth Quarter 2011		552,000		6,000	$	102.22
Calendar Year 2012		3,660,000		10,000		102.48

Totals		4,212,000
Average price					$	102.44


					Implied
					Crack
					Spread
Crude Oil and Fuel Products Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Fourth Quarter 2011		552,000		6,000	$	23.72
Calendar Year 2012		5,490,000		15,000		23.39

Totals		6,042,000
Average price					$	23.42

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

The historical consolidated financial statements included in this Quarterly Report reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet,” the “Company,” “we,” “our,” “us”). The following discussion analyzes the financial condition and results of operations of Calumet for the three and nine months ended September 30, 2011 and 2010. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Calumet in conjunction with our 2010 Annual Report and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.

Overview

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We own plants located in Princeton, Louisiana; Cotton Valley, Louisiana; Shreveport, Louisiana; Superior, Wisconsin; Karns City, Pennsylvania and Dickinson, Texas and terminals located in Burnham, Illinois; Rhinelander, Wisconsin; Crookston, Minnesota and Proctor, Minnesota. Our business is organized into two segments: specialty products and fuel products. In our specialty products segment, we process crude oil and other feedstocks into a wide variety of customized lubricating oils, white mineral oils, solvents, petrolatums and waxes. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for basic industrial, consumer and automotive goods. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products, including gasoline, diesel and jet fuel. In connection with our production of specialty products and fuel products, we also produce asphalt and a limited number of other by-products.

Third Quarter 2011 Update

For the three months ended September 30, 2011 and 2010, 48.9% and 53.4%, respectively, of our sales volume and 90.9% and 98.0%, respectively, of our gross profit was generated from our specialty products segment while, for the same periods, 51.1% and 46.6%, respectively, of our sales volume and 9.1% and 2.0%, respectively, of our gross profit was generated from our fuel products segment.

Despite a slight decline in specialty product segment sales volume specialty products refining margins significantly strengthened quarter over quarter. Specialty products segment generated a gross profit margin of 18.4% in the third quarter of 2011, as compared to a gross profit margin of 15.8% for the same period in the prior year as specialty products pricing continued to improve throughout the first three quarters of 2011.

We noted significant improvement in both sales and production volume in our fuel products segment during the third quarter which allowed us to take advantage of higher market crack spreads. Fuel products sales volumes increased 13.8% for the three months ended September 30, 2011 compared to the same period in 2010, while generating a gross profit margin of 2.9% during the quarter compared to 0.6% in same period in 2010. We recorded realized derivative losses of $34.4 million during the third quarter in our fuel products segment. During the third quarter we entered into additional crack spread hedges due to the strength in forward markets, hedging crack spreads on an average of 6,425 barrels per day in 2013 and 2014 at an average of $24.97 per barrel, a $12.81 per barrel increase over our average hedged crack spreads in 2011.

Our third quarter 2011 total production increased by 5.2% quarter over quarter, due primarily to our decision to increase production run rates at our Shreveport refinery to take advantage of strengthened fuel products crack spreads. Production levels at our other facilities, which focus primarily on the production of specialty products, also increased quarter over quarter to take advantage of higher specialty products demand.

We improved our cash flow from operations during the third quarter by generating $70.0 million in the three months ended September 30, 2011 due primarily to our improved operating income before depreciation. In the first and second quarters of 2011, we used cash in response to increasing crude inventory levels as a result of terminating certain just-in-time inventory supply arrangements with a related party, Legacy, effective May 31, 2011, increased working capital requirements resulting from increased run rates at our Shreveport refinery and higher commodity prices in general. We plan to continue focusing our efforts on generating positive cash flows from operations which we expect will be used to (i) improve our liquidity position, (ii) pay quarterly distributions to our unitholders, (iii) service our debt obligations and (iv) provide funding for general partnership purposes.

Superior Acquisition

On September 30, 2011, we completed the acquisition of the Superior, Wisconsin refinery and associated operating assets and inventories and related business of Murphy Oil Corporation (“Murphy Oil”) for aggregate consideration of approximately $411.1 million, excluding customary post-closing purchase price adjustments (“Superior Acquisition”). Pursuant to the Superior Acquisition, we acquired the following (collectively the “Superior Business”):

	•		Murphy Oil’s refinery located in Superior, Wisconsin and associated inventories;

	•		Superior’s wholesale marketing business and related assets, including certain owned or leased Murphy Oil product terminals located in Superior and Rhinelander, Wisconsin, Duluth and Crookston and Proctor, Minnesota and Toole, Utah and associated inventories and logistics assets located at each of the foregoing facilities; and

	•		Murphy Oil’s “SPUR” branded gasoline wholesale business and related assets.

We believe the Superior Acquisition provides greater scale, geographic diversity and development potential to our refining business, as our current total refining throughput capacity has increased by 50% to 135,000 barrels per day.

The Superior Acquisition was financed by a combination of (i) net proceeds of $193.6 million from our September 2011 public offering of common units, (ii) net proceeds of $180.3 million from the September 2011 private placement of 9 3/8% senior notes due May 1, 2019 and (iii) borrowings under our revolving credit facility.

In addition, subsequent to September 30, 2011, we have entered into additional derivative contracts to hedge our increased exposure to crack spreads resulting from the Superior Acquisition. We plan to hedge a portion of the Superior refinery’s estimated fuels production in 2013 and 2014 consistent with our existing hedging policy.

Key Performance Measures

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

Our primary raw materials are crude oil and other specialty feedstocks and our primary outputs are specialty petroleum and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of additional factors beyond our control. We monitor these risks and enter into financial derivatives designed to mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our cash distribution, debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.” As of September 30, 2011, we have hedged approximately 11.7 million barrels of fuel products through December 2014 at an average refining margin of $17.85 per barrel with average refining margins ranging from a low of $12.16 per barrel in 2011 to a high of $25.01 per barrel in 2014. In addition, subsequent to the closing of the Superior Acquisition, we have entered into approximately 6.0 million barrels of fuel products crack spread hedges at an average crack spread of $23.42 per barrel. Please refer to Note 7 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” and Part I Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Existing Commodity Derivative Instruments” for detailed information regarding our derivative instruments.

Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:

	•		sales volumes;

	•		production yields; and

	•		specialty products and fuel products gross profit.

Sales volumes. We view the volumes of specialty products and fuel products sold as an important measure of our ability to effectively utilize our refining assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.

Production yields. In order to maximize our gross profit and minimize lower margin by-products, we seek the optimal product mix for each barrel of crude oil we refine, which we refer to as production yield.

Specialty products and fuel products gross profit. Specialty products and fuel products gross profit are important measures of our ability to maximize the profitability of our specialty products and fuel products segments. We define specialty products and fuel products gross profit as sales less the cost of crude oil and other feedstocks and other production-related expenses, the most significant portion of which includes labor, plant fuel, utilities, contract services, maintenance, depreciation and processing materials. We use specialty products and fuel products gross profit as indicators of our ability to manage our business during periods of crude oil and natural gas price fluctuations, as the prices of our specialty products and fuel products generally do not change immediately with changes in the price of crude oil and natural gas. The increase in selling prices typically lags behind the rising costs of crude oil feedstocks for specialty products. Other than plant fuel, production-related expenses generally remain stable across broad ranges of throughput volumes, but can fluctuate depending on maintenance activities performed during a specific period.

Our fuel products segment gross profit may differ from a standard U.S. Gulf Coast 2/1/1 or 3/2/1 market crack spread due to many factors, including our fuel products mix as shown in our production table being different than the ratios used to calculate such market crack spreads, the allocation of by-product (primarily asphalt) losses at the Shreveport refinery to the fuel products segment, operating costs including fixed costs, derivative activity to hedge our fuel products segment revenues and cost of crude oil reflected in gross profit and our local market pricing differential in Shreveport, Louisiana as compared to U.S. Gulf Coast postings.

In addition to the foregoing measures, we also monitor our selling, general and administrative expenditures, substantially all of which are incurred through our general partner.

Results of Operations for the Three and Nine Months Ended September 30, 2011 and 2010

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


	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		% Change			2011		2010		% Change
			(In bpd)							(In bpd)
Total sales volume (1)		62,337		60,163		3.6	%		58,546		54,861		6.7	%
Total feedstock runs (2)		63,567		61,678		3.1	%		60,529		55,774		8.5	%
Facility production: (3)
Specialty products:
Lubricating oils		15,017		14,707		2.1	%		14,316		13,268		7.9	%
Solvents		10,963		10,715		2.3	%		10,717		9,240		16.0	%
Waxes		1,434		1,307		9.7	%		1,234		1,157		6.7	%
Fuels		491		942		(47.9	)%		519		1,023		(49.3	)%
Asphalt and other by-products		8,984		8,079		11.2	%		8,660		6,649		30.2	%

Total		36,889		35,750		3.2	%		35,446		31,337		13.1	%

Fuel products:
Gasoline		9,741		8,538		14.1	%		9,660		8,674		11.4	%
Diesel		13,470		11,883		13.4	%		11,896		10,592		12.3	%
Jet fuel		4,872		5,336		(8.7	)%		4,495		5,306		(15.3	)%
By-products		492		735		(33.1	)%		704		586		20.1	%

Total		28,575		26,492		7.9	%		26,755		25,158		6.3	%

Total facility production (3)		65,464		62,242		5.2	%		62,201		56,495		10.1	%


(1)		Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements and sales of inventories.

(2)		Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. The increase in the total feedstock runs for the three months ended September 30, 2011 compared to the same quarter in 2010 is due primarily to the decision to increase feedstock run rates at our facilities because of the favorable economics of running additional barrels. The increase in feedstock runs for the nine months ended September 30, 2011 compared to the same period in 2010 is due primarily to the decision to increase crude oil run rates at our facilities because of favorable economics of running additional barrels and the failure of an environmental operating unit at our Shreveport refinery which impacted run rates in the 2010 period. This increase is partially offset by the impact of the approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period.

(3)		Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities, pursuant to supply and/or processing agreements, including such agreements with LyondellBasell. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstock and production of finished products and volume loss. The increase in production in the three and nine months ended September 30, 2011 compared to the same periods in 2010 is due primarily to higher throughput rates at our Shreveport refinery period over period as discussed above in footnote 2 of this table.

The following table reflects our consolidated results of operations and includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) 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.”


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Sales	$	777,780		$	595,273		$	2,116,790		$	1,594,542
Cost of sales		681,179			533,167			1,922,760			1,451,141

Gross profit		96,601			62,106			194,030			143,401

Operating costs and expenses:
Selling, general and administrative		14,148			7,403			35,143			22,894
Transportation		23,696			23,258			69,462			63,460
Taxes other than income taxes		1,683			1,308			4,246			3,431
Insurance recoveries		—			—			(8,698	)		—
Other		543			565			1,781			1,373

Operating income		56,531			29,572			92,096			52,243

Other income (expense):
Interest expense		(12,577	)		(7,794	)		(30,602	)		(22,505	)
Debt extinguishment costs		—			—			(15,130	)		—
Realized loss on derivative instruments		(3,814	)		(2,288	)		(5,798	)		(8,147	)
Unrealized gain (loss) on derivative instruments		(20,335	)		1,931			(23,876	)		(13,835	)
Other		45			(121	)		148			(170	)

Total other expense		(36,681	)		(8,272	)		(75,258	)		(44,657	)

Net income before income taxes		19,850			21,300			16,838			7,586
Income tax expense		236			79			674			339

Net income	$	19,614		$	21,221		$	16,164		$	7,247

Adjusted EBITDA	$	70,548		$	44,006		$	146,042		$	96,265

Distributable Cash Flow	$	50,487		$	30,862		$	94,076		$	45,166

Non-GAAP Financial Measures

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

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

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

	•		the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

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

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

We believe that these non-GAAP measures are useful to analysts and investors as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully trend and analyze the performance of our core cash operations.

We define EBITDA for any period as net income plus interest expense (including debt issuance and extinguishment costs), income taxes and depreciation and amortization.

We define Adjusted EBITDA for any period as: (1) net income plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income; (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income; (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) 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 define Distributable Cash Flow for any period as Adjusted EBITDA less replacement capital expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash interest expense) and income tax expense. Distributable Cash Flow is used by us and our investors to analyze our ability to pay distributions.

The definitions of Adjusted EBITDA and Distributable Cash that are presented in this Quarterly Report have been updated to reflect the calculation of “Consolidated Cash Flow” contained in the indentures governing our 2019 Notes. We are required to report Consolidated Cash Flow to the holders of our 2019 Notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these measures are used by them to determine our compliance with certain covenants governing those debt instruments. Adjusted EBITDA and Distributable Cash Flow that are presented in this Quarterly Report for prior periods have been updated to reflect the use of the new calculations. Please refer to “Liquidity and Capital Resources — Debt and Credit Facilities” within this item for additional details regarding the covenants governing our debt instruments.

EBITDA, Adjusted EBITDA and Distributable Cash Flow 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. In evaluating our performance as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the limitations of these measurements. EBITDA, Adjusted EBITDA and Distributable Cash Flow do not reflect our obligations for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only three of the measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the same manner. The following tables present a reconciliation of both net income to EBITDA, Adjusted

EBITDA and Distributable Cash Flow, and Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011		2010
	(In thousands)						(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income	$	19,614		$	21,221		$	16,164	$	7,247
Add:
Interest expense		12,577			7,794			30,602		22,505
Debt extinguishment costs		—			—			15,130		—
Depreciation and amortization		14,680			14,908			43,644		44,410
Income tax expense		236			79			674		339

EBITDA	$	47,107		$	44,002		$	106,214	$	74,501

Add:
Unrealized (gain) loss on derivatives	$	20,335		$	(1,931	)	$	23,876	$	13,835
Realized gain (loss) on derivatives, not included in net income		(771	)		(594	)		4,366		848
Amortization of turnaround costs		2,542			2,539			8,288		6,639
Non-cash equity based compensation		1,335			(10	)		3,298		442

Adjusted EBITDA	$	70,548		$	44,006		$	146,042	$	96,265

Less:
Replacement capital expenditures (1)		6,608			5,751			14,204		22,093
Cash interest expense (2)		11,869			6,821			28,239		19,626
Turnaround costs		1,348			493			8,849		9,041
Income tax expense		236			79			674		339

Distributable Cash Flow	$	50,487		$	30,862		$	94,076	$	45,166


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

(2)		Represents consolidated interest expense less non-cash interest expense.


	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to net cash provided by (used in) operating activities:
Distributable Cash Flow	$	94,076		$	45,166
Add:
Replacement capital expenditures (1)		14,204			22,093
Cash interest expense (2)		28,239			19,626
Turnaround costs		8,849			9,041
Income tax expense		674			339

Adjusted EBITDA	$	146,042		$	96,265

Less:
Unrealized loss on derivative instruments		23,876			13,835
Realized gain on derivatives, not included in net income		4,366			848
Amortization of turnaround costs		8,288			6,639
Non-cash equity based compensation		3,298			442

EBITDA	$	106,214		$	74,501

Add:
Unrealized loss on derivative instruments		23,876			13,835
Cash interest expense (2)		(28,239	)		(19,626	)
Non-cash equity based compensation		3,298			442
Amortization of turnaround costs		8,288			6,639
Income tax expense		(674	)		(339	)
Provision for doubtful accounts		255			74
Debt extinguishment costs		(729	)		—
Changes in assets and liabilities:
Accounts receivable		(44,714	)		(42,004	)
Inventories		(109,787	)		(12,964	)
Other current assets		(2,352	)		3,664
Turnaround costs		(8,849	)		(9,041	)
Derivative activity		4,928			849
Other assets		(197	)		—
Accounts payable		54,916			68,995
Other liabilities		(4,489	)		1,842
Other, including changes in noncurrent assets and liabilities		(2,304	)		835

Net cash provided by (used in) operating activities	$	(559	)	$	87,702


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

(2)		Represents consolidated interest expense less non-cash interest expense.

Changes in Results of Operations for the Three Months Ended September 30, 2011 and 2010

Sales. Sales increased $182.5 million, or 30.7%, to $777.8 million in the three months ended September 30, 2011 from $595.3 million in the same period in 2010. Sales for each of our principal product categories in these periods were as follows:


	Three Months Ended September 30,
	2011		2010		% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	262,175	$	214,926		22.0	%
Solvents		126,709		102,276		23.9	%
Waxes		38,908		34,089		14.1	%
Fuels (1)		1,047		298		251.3	%
Asphalt and by-products (2)		48,650		34,462		41.2	%

Total specialty products	$	477,489	$	386,051		23.7	%

Total specialty products sales volume (in barrels)		2,803,000		2,958,000		(5.2	)%
Average specialty products sales price per barrel	$	170.35	$	130.51		30.5	%
Fuel products:
Gasoline	$	132,286	$	73,550		79.9	%
Diesel		116,914		97,405		20.0	%
Jet fuel		47,190		34,998		34.8	%
By-products (3)		3,901		3,269		19.3	%

Total fuel products	$	300,291	$	209,222		43.5	%

Total fuel products sales volume (in barrels)		2,932,000		2,577,000		13.8	%
Average fuel products sales price per barrel (4)	$	102.42	$	81.19		26.1	%
Total sales	$	777,780	$	595,273		30.7	%

Total sales volume (in barrels)		5,735,000		5,535,000		3.6	%


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

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

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

(4)		Average fuel products sales price per barrel includes impact of hedging contracts.

Specialty products segment sales for the three months ended September 30, 2011 increased $91.4 million, or 23.7%, as a result of an increase in the average selling price per barrel of $39.84, or 30.5%. The increase is partially offset by a 5.2% decrease in sales volume as compared to the same period in 2010. Lubricating oils and solvents experienced price increases, driven by improving overall demand and a 23.4% increase in the average cost of crude oil per barrel for the 2011 period as compared to the same period in 2010.

Fuel products segment sales for the three months ended September 30, 2011 increased $91.1 million, or 43.5%, due primarily to an increase in the average selling price per barrel (excluding the impact of hedging activities) of $37.56, or 43.8% and a 13.8% increase in sales volume, driven by market conditions and higher Shreveport refinery run rates over the prior period. The increase in the average selling price per barrel of 43.8% compares to a 25.1% increase in the average price of crude oil per barrel. The average selling price per barrel increased for all fuel products, with jet fuel and gasoline selling prices experiencing significant increases driven by improved market pricing. Adversely impacting fuel product sales was a $49.6 million increase in realized derivative losses on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for discussion of the net impact of our crude oil and fuel products derivative instruments designated as cash flow hedges.

Gross Profit. Gross profit increased $34.5 million, or 55.5%, to $96.6 million in the three months ended September 30, 2011 from $62.1 million in the same period in 2010. Gross profit for our specialty products and fuel products segments was as follows:


	Three Months Ended September 30,
	2011			2010			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products	$	87,789		$	60,880			44.2	%
Percentage of sales		18.4	%		15.8	%
Specialty products gross profit per barrel	$	31.32		$	20.58			52.2	%
Fuel products	$	8,812		$	1,226			618.8	%
Percentage of sales		2.9	%		0.6	%
Fuel products gross profit per barrel	$	3.01		$	0.48			527.1	%
Total gross profit	$	96,601		$	62,106			55.5	%
Percentage of sales		12.4	%		10.4	%

The increase in specialty products segment gross profit of $26.9 million quarter over quarter was due primarily to a 30.5% increase in the average selling price per barrel as discussed above, partially offset by a 23.4% increase in the average cost of crude oil per barrel, a 5.2% decrease in sales volume and higher operating costs, primarily repairs and maintenance.

The increase in fuel products segment gross profit of $7.6 million quarter over quarter was due primarily to a 13.8% increase in sales volume and a 43.8% increase in the average selling price per barrel (excluding the impact of realized hedging losses), partially offset by increased realized losses on derivatives of $38.9 million in our fuel products hedging program, a 25.1% increase in the average cost of crude oil per barrel and higher operating costs, primarily repairs and maintenance.

Selling, general and administrative. Selling, general and administrative expenses increased $6.7 million, or 91.1%, to $14.1 million in the three months ended September 30, 2011 from $7.4 million in the same period in 2010. This increase is due primarily to increased accrued incentive compensation costs of $3.5 million in 2011 compared to 2010 and $2.1 million of acquisition costs related to the Superior Acquisition with no comparable expenses in 2010.

Interest expense. Interest expense increased $4.8 million, or 61.4%, to $12.6 million in the three months ended September 30, 2011 from $7.8 million in the three months ended September 30, 2010, due primarily to higher interest rates associated with the 2019 Notes as compared to our term loan that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.

Realized loss on derivative instruments. Realized loss on derivative instruments increased $1.5 million to $3.8 million in the three months ended September 30, 2011 from $2.3 million for the three months ended September 30, 2010. This change was due primarily to a gain of approximately $0.9 million in the prior period on crack spread derivatives not designated as hedges that were executed to economically lock in gains on a portion of our fuel products segment derivative hedging activity with no activity during the three months ended September 30, 2011 and an increase in ineffectiveness on settled crack spread hedges of approximately $1.9 million. Partially offsetting these increased realized losses were decreased realized losses of approximately $1.5 million in our specialty products segment related to crude oil derivatives not designated as hedges.

Unrealized gain (loss) on derivative instruments. Unrealized gain (loss) on derivative instruments decreased $22.3 million, to a $20.3 million loss in the three months ended September 30, 2011 from a $1.9 million gain in the three months ended September 30, 2010. This change was due primarily to an increase in ineffectiveness of approximately $21.6 million for the three months ended September 30, 2011. This increased loss ineffectiveness is due primarily to the continued widening of the spread between the West Texas Intermediate (“NYMEX WTI”) crude oil price, upon which our crude oil derivatives are settled, and other crude oil indices, such as Light Louisiana Sweet (“LLS”) and Brent, upon which a portion of our crude oil purchases are based.

Changes in Results of Operations for the Nine Months Ended September 30, 2011 and 2010

Sales. Sales increased $522.2 million, or 32.8%, to $2,116.8 million in the nine months ended September 30, 2011 from $1,594.5 million in the same period in 2010. Sales for each of our principal product categories in these periods were as follows:


	Nine Months Ended September 30,
	2011		2010		% Change
	(Dollars in thousands, except per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	717,674	$	555,328		29.2	%
Solvents		380,687		285,907		33.2	%
Waxes		107,089		88,698		20.7	%
Fuels (1)		2,470		4,268		(42.1	)%
Asphalt and by-products (2)		133,085		86,749		53.4	%

Total specialty products	$	1,341,005	$	1,020,950		31.3	%

Total specialty products sales volume (in barrels)		8,249,000		7,894,000		4.5	%
Average specialty products sales price per barrel	$	162.57	$	129.33		25.7	%
Fuel products:
Gasoline	$	355,519	$	225,720		57.5	%
Diesel		290,678		239,031		21.6	%
Jet fuel		114,650		100,378		14.2	%
By-products (3)		14,938		8,463		76.5	%

Total fuel products	$	775,785	$	573,592		35.3	%

Total fuel products sales volume (in barrels)		7,734,000		7,083,000		9.2	%
Average fuel products sales price per barrel (4)	$	100.31	$	80.98		23.9	%
Total sales	$	2,116,790	$	1,594,542		32.8	%

Total sales volume (in barrels)		15,983,000		14,977,000		6.7	%


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

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

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

(4)		Average fuel products sales price per barrel includes impact of hedging contracts.

Specialty products segment sales for the nine months ended September 30, 2011 increased $320.1 million, or 31.3%, as a result of an increase in the average selling price per barrel of $33.24, or 25.7%, and a 4.5% increase in sales volume as compared to the same period in 2010. Lubricating oils, solvents and asphalt and by-products experienced price increases, driven by improving overall demand and a 28.3% increase in the average cost of crude oil per barrel for the 2011 period as compared to the same period in 2010. The increased volume is due primarily to improving overall specialty products demand as a result of improved economic conditions and higher refinery run rates over the prior period.

Fuel products segment sales for the nine months ended September 30, 2011 increased $202.2 million, or 35.3%, due primarily to an increase in the average selling price per barrel (excluding the impact of hedging activities) of $35.33, or 40.9%, driven by market conditions compared to a 29.5% increase in the average price of crude oil per barrel and a 9.2% increase in sales volume. The average selling price per barrel increased for all fuel products, with gasoline and diesel selling prices experiencing significant increases driven by improved market pricing. Adversely impacting fuel products sales was a $127.4 million increase in realized derivative losses on our fuel products cash flow hedges recorded in sales. Please see “Gross Profit” below for discussion of the net impact of our crude oil and fuel products derivative instruments designated as cash flow hedges.

Gross Profit. Gross profit increased $50.6 million, or 35.3%, to $194.0 million in the nine months ended September 30, 2011 from $143.4 million in the same period in 2010. Gross profit for our specialty products and fuel products segments was as follows:


	Nine Months Ended September 30,
	2011			2010			% Change
	(Dollars in thousands, except per barrel data)
Gross profit by segment:
Specialty products	$	193,988		$	130,706			48.4	%
Percentage of sales		14.5	%		12.8	%
Specialty products gross profit per barrel	$	23.52		$	16.56			42.0	%
Fuel products	$	42		$	12,695			(99.7	)%
Percentage of sales		0.0	%		2.2	%
Fuel products gross profit per barrel	$	0.01		$	1.79			(99.4	)%
Total gross profit	$	194,030		$	143,401			35.3	%
Percentage of sales		9.2	%		9.0	%

The increase in specialty products segment gross profit of $63.3 million for the nine months ended September 30, 2011 compared to the same period in 2010 was due primarily to a 4.5% increase in sales volume and a 25.7% increase in the average selling price per barrel as discussed above, partially offset by a 28.3% increase in the average cost of crude oil per barrel and higher operating costs, primarily repair and maintenance.

The decrease in fuel products segment gross profit of $12.7 million for the nine months ended September 30, 2011 compared to the same period in 2010 was due primarily to increased realized losses on derivatives of $94.0 million in our fuel products hedging program, a 29.5% increase in the cost of crude oil per barrel and increased production of by-products, partially offset by a 9.2% increase in sales volume and a 40.9% increase in selling prices per barrel, excluding the impact of realized hedging losses. During the second quarter of 2011, our fuel products hedged volumes, combined with lower refinery run rates, resulted in our diesel and jet fuel sales volumes being approximately 100% hedged at approximately $12.00 per barrel, preventing us from realizing the benefit of increased market crack spreads for these products. By-product production increased in the 2011 period as compared to the 2010 period due primarily to an increase in run rates at the Shreveport refinery.

Selling, general and administrative. Selling, general and administrative expenses increased $12.2 million, or 53.5%, to $35.1 million in the nine months ended September 30, 2011 from $22.9 million in 2010. This increase is due primarily to increased accrued incentive compensation costs of $6.5 million in 2011 compared to 2010 and $2.1 million of acquisition costs related to the Superior Acquisition with no comparable costs in 2010, as well as increased overall salaries and wages and advertising.

Transportation. Transportation expenses increased $6.0 million, or 9.5%, to $69.5 million in the nine months ended September 30, 2011 from $63.5 million in the same period in 2010. This increase is due primarily to increased sales volumes of lubricating oils, solvents and waxes, as well as higher freight costs.

Insurance recoveries. Insurance recoveries were $8.7 million for the nine months ended September 30, 2011. The gain was related to a claim settled in the second quarter of 2011 with insurers related to the failure of an environmental operating unit at the Shreveport refinery in 2010.

Interest expense. Interest expense increased $8.1 million, or 36.0%, to $30.6 million in the nine months ended September 30, 2011 from $22.5 million in the nine months ended September 30, 2010, due primarily to higher interest rates associated with the 2019 Notes as compared to our term loan that was repaid in full and extinguished in connection with the issuance of the 2019 Notes.

Debt extinguishment costs. Debt extinguishment costs were $15.1 million during the nine months ended September 30, 2011. The debt extinguishment costs were related to the extinguishment of the term loan with proceeds from the issuance of the 2019 Notes.

Realized loss on derivative instruments. Realized loss on derivative instruments decreased $2.3 million to $5.8 million in the nine months ended September 30, 2011 from $8.1 million for the nine months ended September 30, 2010. This change was due primarily to a gain of approximately $3.0 million on crack spread derivatives not designated as hedges that were executed to economically lock in gains on a portion of our fuel products segment derivative hedging activity with no activity during the nine months ended September 30, 2011, and an increase in ineffectiveness on settled crack spread hedges of approximately $0.6 million. Partially offsetting these increased realized losses were decreased realized losses of approximately $7.0 million in our specialty products segment related to crude oil derivatives not designate as hedges.

Unrealized loss on derivative instruments. Unrealized loss on derivative instruments increased $10.0 million, to $23.9 million in the nine months ended September 30, 2011 from $13.8 million in the nine months ended September 30, 2010. The increased loss is due primarily to an increase in ineffectiveness of $11.2 million during the quarter ended September 30, 2011. This increased loss ineffectiveness is due primarily to the continued widening of the spread between the NYMEX WTI crude oil price, upon which our crude oil derivatives are settled, and other crude oil indices, such as LLS and Brent, upon which a portion of our crude oil purchases are based.

Liquidity and Capital Resources

The following should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” included under Part I Item 7 in our 2010 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 6 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for additional discussion related to long-term debt.

Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings, proceeds from notes offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions to our unitholders and general partner and debt service. We expect that our principal uses of cash in the future will be for distributions to our limited partners and general partner, debt service, replacement and environmental capital expenditures and capital expenditures related to internal growth projects and acquisitions from third parties or affiliates. We expect to fund future capital expenditures with current cash flow from operations and borrowings under our revolving credit facility. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and borrowings under our existing revolving credit facility and may require us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.

Cash Flows

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity to meet our financial commitments, debt service obligations and anticipated capital expenditures. However, we are subject to business and operational risks that could materially adversely affect our cash flows. A material decrease in our cash flow from operations including a significant, sudden decrease in crude oil prices would likely produce a corollary material adverse effect on our borrowing capacity under our revolving credit facility and potentially our ability to comply with the covenants under our credit facilities. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which would be funded by borrowings under our revolving credit facility.

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


	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Net cash provided by (used in) operating activities	$	(559	)	$	87,702
Net cash used in investing activities	$	(470,132	)	$	(27,109	)
Net cash provided by (used in) financing activities	$	470,720		$	(60,554	)

Operating Activities. Operating activities used cash of $0.6 million during the nine months ended September 30, 2011 compared to providing cash of $87.7 million during the same period in 2010. The change was due primarily to increases in working capital requirements of $111.4 million, primarily from increased crude oil inventory levels as a result of terminating certain just-in-time inventory supply arrangements with a related party, Legacy, effective May 31, 2011, increased working capital requirements resulting from increased run rates at our Shreveport facility and higher commodity prices in general, partially offset by insurance recoveries related to a settled claim with insurers during the second quarter of 2011 resulting from the failure of an environmental operating unit at the Shreveport refinery in 2010.

Investing Activities. Cash used in investing activities increased to $470.1 million during the nine months ended September 30, 2011 compared to $27.1 million during the nine months ended September 30, 2010. The increase is due primarily to the acquisition of the assets and assumption of liabilities in conjunction with the Superior Acquisition which closed on September 30, 2011 for $411.1 million, with no similar acquisition activities in the prior year.

Financing Activities. Financing activities provided cash of $470.7 million for the nine months ended September 30, 2011 compared to cash used of $60.6 million during the nine months ended September 30, 2010. The increase is due primarily to the net proceeds from the February 2011 and September 2011 public equity offerings of $281.9 million and proceeds from the 2019 Notes offerings of $586.0 million, net of discount, in the second and third quarters of 2011, partially offset by $23.1 million of debt issuance costs, the $367.4 million repayment of the senior secured first lien term loan and $56.4 million of distributions to our unitholders.

On October 11, 2011, we declared a quarterly cash distribution of $0.50 per unit on all outstanding units, or approximately $26.4 million in aggregate, for the quarter ended September 30, 2011. The distribution will be paid on November 14, 2011 to unitholders of record as of the close of business on November 4, 2011. This quarterly distribution of $0.50 per unit equates to $2.00 per unit, or approximately $105.4 million in aggregate on an annualized basis.

Capital Expenditures

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

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


	Nine Months Ended September 30,
	2011		2010
	(In thousands)
Capital improvement expenditures	$	16,463	$	5,217
Replacement capital expenditures		10,595		13,546
Environmental capital expenditures		3,609		8,547

Total	$	30,667	$	27,310

We anticipate that future capital expenditure requirements will be provided primarily through cash from operations and available borrowings under our revolving credit facility. We estimate our replacement and environmental capital expenditures will be approximately $15.0 million for the remainder of 2011, with total replacement and environmental capital expenditures, excluding capital expenditures related to the Superior refinery, remaining below 2010 levels. These estimated amounts for 2011 include a portion of the $11.0 million to $15.0 million in environmental projects to be spent over the next five years as required by our settlement with the LDEQ under the “Small Refinery and Single Site Refining Initiative.” Please read Note 5 of Part I Item 1 “Financial Statements — Commitments and Contingencies — Environmental” for additional information. Our capital improvement expenditures have increased due to various minor capital improvement projects to reduce energy costs, improve finished product quality and improve finished product yields. We do not expect to incur significant capital improvement expenditures for the remainder of 2011.

Debt and Credit Facilities

As of September 30, 2011, our debt and credit facilities consisted of:

	•		a $850.0 million senior secured revolving credit facility, subject to borrowing base restrictions, with a maximum letter of credit sublimit equal to $680.0 million, which is the greater of (i) $400.0 million and (ii) 80% of revolver commitments then in effect; and

	•		$600.0 million of 9 3/8% senior notes due 2019.

Amended and Restated Senior Secured Revolving Credit Facility

On June 24, 2011, we entered into an amended and restated senior secured revolving credit facility (the “revolving credit facility”), which increased the maximum availability of credit under the revolving credit facility from $375.0 million to $550.0 million, subject to borrowing base limitations, and included a $300.0 million incremental uncommitted expansion option. On September 30, 2011, in conjunction with the Superior Acquisition, we fully exercised the $300.0 million expansion option to increase the maximum availability of credit under the revolving credit facility from $550.0 million to $850.0 million, subject to borrowing base limitations. The lenders under our revolving credit facility, which matures in June 2016, have a first priority lien on our cash, accounts receivable, inventory and certain other personal property.

Our revolving credit facility contains various covenants that limit, among other things, our ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; and enter into a merger, consolidation or sale of assets. The revolving credit facility generally permits us to make cash distributions to our unitholders as long as immediately after giving effect to such a cash distribution we have availability under the revolving credit facility at least equal to the greater of (i) 15% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) without giving effect to the LC Reserve (as defined in the revolving credit agreement) and (b) the revolving credit facility commitments then in effect and (ii) $45.0 million. Further, the revolving credit facility contains one springing financial covenant which provides that only if our availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) the revolving credit agreement commitments then in effect and (ii) $46.4 million, (as increased, upon the effectiveness of the increase in the maximum availability under our revolving credit facility, by the same percentage as the percentage increase in our revolving credit agreement commitments), we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0.

Borrowings under the revolving credit facility are limited to a borrowing base that is determined based on advance rates of percentages of Eligible Accounts Receivable and Inventory (as defined in the revolving credit agreement). As such, the borrowing base can fluctuate based on changes in selling prices of our products and our current material costs, primarily the cost of crude oil. On September 30, 2011, we had availability on our revolving credit facility of $271.5 million, based on a $535.5 million borrowing base, $208.0 million in outstanding standby letters of credit and outstanding borrowings of $56.0 million. The borrowing base cannot exceed the revolving credit facility commitments then in effect. The lender group under our revolving credit facility is comprised of a syndicate of thirteen lenders with total commitments of $850.0 million.

The revolving credit facility, which is our primary source of liquidity for cash needs in excess of cash generated from operations, currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at our option. As of September 30, 2011, this margin was 125 basis points for prime and 250 basis points for LIBOR; however, the margin fluctuates quarterly based on our average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter as follows:


Quarterly Average	Margin on Base Rate			Margin on LIBOR
Availability Percentage	Revolving Loans			Revolving Loans
≥ 66%		1.00	%		2.25	%
≥ 33% and < 66%		1.25	%		2.50	%
< 33%		1.50	%		2.75	%

If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other rights and remedies. An event of default includes, among other things, the nonpayment of principal, interest, fees or other amounts; failure of any representation or warranty to be true and correct when made or confirmed; failure to perform or observe covenants in

the revolving credit facility or other loan documents, subject, in limited circumstances, to certain grace periods; cross-defaults in other indebtedness if the effect of such default is to cause, or permit the holders of such indebtedness to cause, the acceleration of such indebtedness under any material agreement; bankruptcy or insolvency events; monetary judgment defaults; asserted invalidity of the loan documentation; and a change of control over us.

Amounts outstanding under our revolving credit facility fluctuate materially during each quarter due to normal changes in working capital, payments of quarterly distributions to unitholders and debt service costs. Specifically, the amount borrowed under our revolving credit facility is typically at its highest level after we pay for the majority of our crude oil supplies on the 20th day of every month per standard industry terms. The maximum revolving credit facility borrowings during the third quarter of 2011 were $101.5 million. Nonetheless, our availability on our revolving credit facility during the peak borrowing days of a quarter has been ample to support our operations and service upcoming requirements. During the quarter ended September 30, 2011, availability for additional borrowings under our revolving credit facility was approximately $122.1 million at its lowest point. We believe that we will continue to have sufficient cash flow from operations and borrowing availability under our revolving credit facility to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, credit agreement covenants, contingencies and anticipated capital expenditures.

9 3/8% Senior Notes

On April 21, 2011, in connection with the restructuring of the majority of our outstanding long-term debt, we issued and sold $400.0 million in aggregate principal amount of 9 3/8% of senior notes due May 1, 2019 (the “2019 Notes issued in April 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at par. The 2019 Notes issued in April 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. We received proceeds of $389.0 million net of underwriters’ fees and expenses, which we used to repay in full borrowings outstanding under our existing senior secured first lien term loan facility, as well as all accrued interest and fees, and for general partnership purposes.

On September 19, 2011, in connection with the Superior Acquisition, we issued and sold $200.0 million in aggregate principal amount of 9 3/8% of senior notes due May 1, 2019 (the “2019 Notes issued in September 2011”) in a private placement pursuant to Rule 144A under the Securities Act to eligible purchasers at a discounted price of 93 percent of par. The 2019 Notes issued in September 2011 were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. We received proceeds of $180.3 million net of discount, underwriters’ fees and expenses, which the we used to fund a portion of the purchase price of the Superior Acquisition. Because the terms of the 2019 Notes issued in September 2011 are substantially identical to the terms of the 2019 Notes issued in April 2011, in this Quarterly Report, we collectively refer to the 2019 Notes issued in April 2011 and the 2019 Notes issued in September 2011 as the “2019 Notes.”

Interest on the 2019 Notes will be paid semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2011. The 2019 Notes will mature on May 1, 2019, unless redeemed prior to maturity. The 2019 Notes are guaranteed on a senior unsecured basis by all of our operating subsidiaries and certain of our future operating subsidiaries.

At any time prior to May 1, 2014, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.

On and after May 1, 2015, we may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:


Year	Percentage
2015		104.688	%
2016		102.344	%
2017 and at any time thereafter		100.000	%

Prior to May 1, 2015, we may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indentures governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.

The indentures governing the 2019 Notes contain covenants that, among other things, restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase our common units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indentures governing the 2019 Notes, has occurred and is continuing, many of these covenants will be suspended.

Upon the occurrence of certain change of control events, each holder of the 2019 Notes will have the right to require that we repurchase all or a portion of such holder’s 2019 Notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.

In connection with the 2019 Notes offering on April 21, 2011, our then current senior secured revolving credit facility was amended on April 15, 2011 to, among other things, (i) permit the issuance of the 2019 Notes issued in April 2011; (ii) upon consummation of the issuance of the 2019 Notes issued in April 2011 and the termination of the senior secured first lien credit facility, release the revolving credit facility lenders’ second priority lien on the collateral securing the senior secured first lien credit facility and (iii) change the interest rate pricing on the revolving credit facility.

Registration Rights Agreements

On April 21, 2011 and September 19, 2011, in connection with the issuances and sales of the 2019 Notes, we entered into registration rights agreements with the initial purchasers of the 2019 Notes obligating us to use reasonable best efforts to file an exchange registration statement with the SEC so that holders of the 2019 Notes can offer to exchange the 2019 Notes for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. We must use reasonable best efforts to cause the exchange offer registration statement to become effective by April 20, 2012 and remain effective until 180 days after the closing of the exchange. Additionally, we have agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, we must use reasonable best efforts to file a shelf registration statement for the resale of the 2019 Notes. If we fail to satisfy these obligations on a timely basis, the annual interest borne by the 2019 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

Senior Secured First Lien Credit Facility

On April 21, 2011, we used approximately $369.5 million of the net proceeds from the issuance and sale of the 2019 Notes issued in April 2011 to repay in full our term loan, as well as accrued interest and fees, and terminated the entire senior secured first lien credit facility, including the term loan and a $50.0 million prefunded letter of credit to support crack spread hedging. We did not incur any material early termination penalties in connection with our termination of the senior secured first lien credit facility. Further, in the second quarter of 2011 we recorded approximately $15.1 million of extinguishment charges related to the write off of the unamortized debt issuance costs and the unamortized discount associated with the term loan.

Borrowings under the senior secured first lien credit facility were used (i) to finance a portion of the acquisition of Penreco in 2008, (ii) to fund the anticipated growth in working capital and remaining capital expenditures associated with our Shreveport refinery expansion project completed in 2008, (iii) to refinance our then-existing term loan facility, (iv) to issue a $50.0 million letter credit to secure our obligations under one of our master derivative contracts and (v) for general partnership purposes. Each lender under the senior secured first lien credit facility generally had a first priority lien on our fixed assets and a second priority lien on our cash, accounts receivable, inventory and certain other personal property. The senior secured first lien credit facility would have matured in January 2015.

Amendments to Master Derivative Contracts

In connection with the termination of the term loan facility and the amendment of our senior secured revolving credit facility, on April 21, 2011, we entered into amendments to certain of our master derivatives contracts to provide new credit support arrangements to secure our payment obligations under these contracts following the termination of the term loan facility and the amendment and restatement of our senior secured revolving credit facility. Under the new credit support arrangements, our payment obligations under all of our master derivatives contracts for commodity hedging generally are secured by a first priority lien on our and our subsidiaries’ real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). We also issued to one counterparty a $25.0 million standby letter of credit under the revolving credit facility to replace a prefunded $50.0 million letter of credit previously issued under the senior secured first lien credit facility. In the event that such counterparty’s exposure to us exceeds $200.0 million, we will be required to post additional collateral support in the form of either cash or letters of credit with the counterparty to enter into additional crack spread hedges. We had no additional letters of credit or cash margin posted with any hedging counterparty as of September 30, 2011. Our master derivatives contracts and Collateral Trust Agreement (described below) continue to impose a number of covenant limitations on our operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements. For financial reporting purposes, we do not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to us upon settlement of the related derivative instrument liability.

The fair value of our derivatives increased by approximately $32.0 million subsequent to September 30, 2011 to a liability of approximately $129.0 million. All credit support thresholds with our hedging counterparties are at levels such that it would take a substantial increase in fuel products crack spreads to require significant additional collateral to be posted. As a result, we do not expect further increases in fuel products crack spreads to significantly impact our liquidity.

Collateral Trust Agreement

In connection with the Amendments, on April 21, 2011, we entered into a collateral sharing agreement (the “Collateral Trust Agreement”) with each of the secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties which governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by us to the secured hedging counterparties under their respective master derivatives contracts. Subject to certain conditions set forth in the Collateral Trust Agreement, we have the ability to add secured hedging counterparties thereto.

In connection with the closing of the Superior Acquisition, on September 30, 2011, we entered into an amendment (the “CTA Amendment”) to the Collateral Trust Agreement with each of the secured hedging counterparties and the administrative agent. The CTA Amendment modified the Collateral Trust Agreement so as to limit to $100.0 million the extent to which forward purchase contracts for physical commodities would be covered by, and secured under, the Collateral Trust Agreement. The CTA Amendment also eliminated the credit rating requirement with respect to forward purchase contract counterparties on physical commodities.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of September 30, 2011 at current maturities and reflects only those line items that are materially changed since December 31, 2010:


			Payments Due by Period
			Less Than		1-3		3-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Operating activities:
Interest on long-term debt at contractual rates (1)	$	461,533	$	67,159	$	125,480	$	123,582	$	145,312
Operating lease obligations (2)		49,889		18,836		23,622		6,516		915
Letters of credit (3)		207,960		207,960		—		—		—
Purchase commitments (4)		1,575,693		1,094,990		463,690		17,013		—
Financing activities:
Capital lease obligations		1,042		749		293		—		—
Long-term debt obligations, excluding capital lease obligations		656,000		—		—		56,000		600,000

Total obligations	$	2,952,117	$	1,389,694	$	613,085	$	203,111	$	746,227


(1)		Interest on long-term debt at contractual rates and maturities relates primarily to our 2019 Notes and revolving credit facility.

(2)		We have various operating leases primarily for the use of land, storage tanks, pressure stations, railcars, equipment, precious metals and office facilities that extend through June 2026.

(3)		Letters of credit primarily supporting crude oil purchases, precious metals leasing and hedging activities.

(4)		Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil and other feedstocks and finished products for resale from various suppliers based on current market prices at the time of delivery.

In connection with the closing of the acquisition of Penreco on January 3, 2008, we entered into a feedstock purchase agreement with ConocoPhillips related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, ConocoPhillips is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, we expect to purchase $71.9 million of feedstock for the LVT unit in each fiscal year of the term based on pricing estimates as of September 30, 2011. This amount is not included in the table above. If the Base Volume is not supplied at any point during the first five years of the ten year term, a penalty for each gallon of shortfall must be paid to us as liquidated damages.

In connection with the Superior Acquisition, we assumed pension plan liabilities, estimated at $17.2 million as of September 30, 2011. Due to the timing of the acquisition, the purchase price allocation and final opening balance sheet have not been finalized, and the breakout between periods cannot be determined at this time. We expect to make total contributions of $0.2 million to this pension plan during the remainder of 2011.

Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Part I Item 7 of our 2010 Annual Report.

Recent Accounting Pronouncements

For additional discussion regarding recent accounting pronouncements, see Note 2 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements.”

Equity Transactions

In February 2011, we satisfied the last of the earnings and distributions tests contained in our partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution on February 14, 2011. Two days following this quarterly distribution to our unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.

On February 24, 2011, we completed an equity offering of our common units in which we sold 4,500,000 common units to the underwriters of the offering at a price to the public of $21.45 per common unit. The proceeds received by us from this offering (net of underwriting discounts, commissions and expenses but before our general partner’s capital contribution) were $92.3 million. The net proceeds were used to repay borrowings under our revolving credit facility and for general partnership purposes. Underwriting discounts totaled $3.9 million. Our general partner contributed $2.0 million to retain its 2% general partner interest.

On September 8, 2011, we completed an equity offering of our common units in which we sold 11,000,000 common units to the underwriters of the offering at a price of $18.00 per common unit. The proceeds received by us from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were $189.6 million and were used to fund a portion of the purchase price of the Superior Acquisition. Underwriting discounts totaled $7.9 million. Our general partner contributed $4.0 million to retain its 2% general partner interest.

On October 13, 2011, the underwriters of our September 8, 2011 public equity offering elected to exercise a portion of their overallotment option. As a result, we sold an additional 750,000 common units to the underwriters at the offering price of $18.00 per unit, less the underwriting discount. The proceeds received by us from this offering (net of underwriting discounts, commissions and expenses but before our general partner’s capital contribution) were $12.9 million and were used to repay borrowings under our revolving credit facility. Underwriting discounts totaled $0.5 million. Our general partner contributed $0.3 million to retain its 2% general partner interest.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part I Item 7A in our 2010 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 7 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for additional discussion related to derivative instruments and hedging activities.

Commodity Price Risk

Holding all other variables constant, we expect a $1 increase in the applicable commodity prices would change our recorded mark-to-market valuation by the following amounts based upon the volumes hedged as of September 30, 2011:


	In millions
Crude oil swaps	$	11.7
Diesel swaps	$	(3.7	)
Jet fuel swaps	$	(7.5	)
Gasoline swaps	$	(0.5	)

Interest Rate Risk

Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates. Historically, our policy has been to enter into interest rate swap agreements to hedge up to 75% of our interest rate risk related to variable rate debt. With the issuances of our 2019 Notes, which constitute fixed rate debt, we do not expect to enter into additional hedges to fix our interest rates.

We are exposed to market risk from fluctuations in interest rates. As of September 30, 2011, we had approximately $56.0 million of variable rate debt outstanding under our revolving credit facility. Holding other variables constant (such as debt levels), a one hundred basis point change in interest rates on our variable rate debt as of September 30, 2011 would be expected to have an impact on net income and cash flows for 2011 of approximately $0.6 million.

Existing Commodity Derivative Instruments

We are also subject to the risk that the crude oil and fuel products derivatives we use to hedge against fuel products crack spread volatility do not provide adequate protection against volatility. All of the crude oil derivatives in our hedge portfolio are based on the market price of NYMEX WTI and the fuel products derivatives are all based on U.S. Gulf Coast market prices. In recent periods, the spread between NYMEX WTI and other crude oil indices (specifically LLS and Brent on which a portion of our crude oil purchases are based) has widened, which has led to more of our crude oil hedges not being as effective. To the extent the spread between NYMEX WTI and the other crude oil indices stays at current levels or continues to widen, our hedges could continue to become less effective and not provide adequate protection against crude oil price volatility.

Fuel Products Segment

The following table provides a summary of the implied crack spreads for the crude oil, diesel, jet fuel and gasoline swaps as of September 30, 2011 disclosed in Note 7 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements,” all of which are designated as cash flow hedges.


					Implied Crack
Crude Oil and Fuel Products Swap Contracts by Expiration Dates	Barrels		BPD		Spread ($/Bbl)
Fourth Quarter 2011		1,334,000		14,500	$	12.16
Calendar Year 2012		5,626,000		15,372		13.27
Calendar Year 2013		3,690,000		10,110		24.95
Calendar Year 2014		1,000,000		2,740		25.01

Totals		11,650,000
Average price					$	17.85

At September 30, 2011, we had the following jet fuel put options related to jet fuel crack spreads in our fuel products segment, none of which are designated as hedges.


					Average		Average
					Sold Put		Bought Put
Jet Fuel Put Option Crack Spread Contracts by Expiration Dates	Barrels		BPD		($/Bbl)		($/Bbl)
Fourth Quarter 2011		184,000		2,000	$	4.75	$	7.00

Totals		184,000
Average price					$	4.75	$	7.00

Specialty Products Segment

At September 30, 2011, we had no derivative positions outstanding related to crude oil purchases in our specialty products segment. Please refer to Note 7 under Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for detailed information on these derivatives.

Superior Acquisition

In addition, subsequent to the closing of the Superior Acquisition on September 30, 2011, we have entered into additional derivative positions to hedge our increased exposure to crack spreads resulting from the Superior Acquisition. The following tables provide a summary of such derivatives entered into as of November 4, 2011, all of which are designated as cash flow hedges.


					Average
	Barrels				Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased		BPD		($/Bbl)
Fourth Quarter 2011		552,000		6,000	$	78.50
Calendar Year 2012		5,490,000		15,000		83.35

Totals		6,042,000
Average price					$	82.90

Average

Barrels

Swap

Diesel Swap Contracts by Expiration Dates

Sold

BPD

($/Bbl)

Calendar Year 2012

1,830,000

5,000

115.27

Totals

1,830,000

Average price

115.27


					Average
	Barrels				Swap
Gasoline Swap Contracts by Expiration Dates	Sold		BPD		($/Bbl)
Fourth Quarter 2011		552,000		6,000	$	102.22
Calendar Year 2012		3,660,000		10,000		102.48

Totals		4,212,000
Average price					$	102.44


					Implied
					Crack
					Spread
Crude Oil and Fuel Products Swap Contracts by Expiration Dates	Barrels		BPD		($/Bbl)
Fourth Quarter 2011		552,000		6,000	$	23.72
Calendar Year 2012		5,490,000		15,000		23.39

Totals		6,042,000
Average price					$	23.42

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2011 at the reasonable assurance level.

(b) Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting during the third fiscal quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

We are not a party to, and our property is not the subject of, any pending legal proceedings other than ordinary routine litigation incidental to our business. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. The information provided under Note 5 “Commitments and Contingencies” in Part I Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” is incorporated herein by reference.

Item 1A. Risk Factors

In addition to the risk factors set forth below, you should carefully consider the risk factors discussed in Part I, Item 1A “Risk Factors” in our 2010 Annual Report and Part II, Item 1A “Risk Factors” in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2011 and June 30, 2011, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

As of September 30, 2011, upon completion of the Superior Acquisition and the issuance of the 2019 Notes issued in September 2011, we had approximately $657.0 million of outstanding indebtedness. Our level of indebtedness could have important consequences to us, including the following:

	•		our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

	•		covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

	•		we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payments of our debt obligations, including the notes; and

	•		our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to satisfy our obligations under the notes.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions to our unitholders, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to accomplish any of these remedies on satisfactory terms, or at all. Please read Part I Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information regarding our indebtedness.

Our revolving credit facility, indentures governing the 2019 Notes and master derivative contracts contain operating and financial restrictions that may restrict our business and financing activities.

The operating and financial restrictions and covenants in our revolving credit facility, indentures governing the 2019 Notes, master derivative contracts and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities, including restrictions on our ability to, among other things:

	•		sell assets, including equity interests in our subsidiaries;

	•		pay distributions or redeem or repurchase our units or repurchase our subordinated debt;

	•		incur or guarantee additional indebtedness or issue preferred units;

	•		create or incur certain liens;

	•		make certain acquisitions and investments;

	•		make capital expenditures above specified amounts;

	•		redeem or repay other debt or make other restricted payments;

	•		make capital expenditures above specified amounts;

	•		enter into transactions with affiliates;

	•		enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

	•		create unrestricted subsidiaries;

	•		enter into sale and leaseback transactions;

	•		enter into a merger, consolidation or transfer or sale of assets, including equity interests in our subsidiaries;

	•		cease our commodity hedging program; and

	•		engage in certain business activities.

Our revolving credit facility contains operating and financial restrictions similar to the above listed items, including a springing financial covenant which provides that if availability under the revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the credit agreement) (without giving effect to the LC Reserve (as defined in the credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $30.0 million, we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0. The failure to comply with any of these or other covenants would cause a default under our revolving credit facility.

Our existing indebtedness imposes, and any future indebtedness may impose, a number of covenants on us regarding collateral maintenance and insurance maintenance. As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with the covenants and restrictions contained in the indentures governing the 2019 Notes, our revolving credit facility and our master derivative contracts may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with the covenants, ratios or tests in the indentures governing the 2019 Notes, our revolving credit facility, our master derivative contracts or any future indebtedness could result in an event of default under the indentures, our revolving credit facility, our master derivatives contracts, the indentures governing our 2019 Notes or our future indebtedness, which, if not cured or waived, could have a material adverse affect on our business, financial condition and results of operations. In the event of any default on our indebtedness, our debt holders and lenders:

	•		will not be required to lend any additional amounts to us;

	•		could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

	•		could elect to require that all obligations accrue interest at the default rate, if such rate has not already been imposed;

	•		may have the ability to require us to apply all of our available cash to repay these borrowings; or

	•		may prevent us from making debt service payments under our other agreements, any of which could result in an event of default under the notes.

If an acceleration of our debt occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if new financing were available, it may be on terms that are less attractive to us than our then existing credit facilities or it may not be on terms that are acceptable to us.

If our existing indebtedness were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are secured by substantially all of our accounts receivable, inventory and certain related assets and our obligations under our master derivative contracts are secured by a first priority lien on our real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements), and if we are unable to repay our indebtedness under the revolving credit facility or master derivative contracts, the lenders could seek to foreclose on these assets. Please read Part I Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information regarding our long-term debt.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets and our ability to distribute cash to our unitholders and make payments on our debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the equity interests in our subsidiaries. As a result, our ability to distribute cash to our unitholders and payments of debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our revolving credit facility and applicable state laws and other laws and regulations. If we are unable to obtain the funds necessary to distribute cash to our unitholders or payments of debt obligations, we may be required to adopt one or more alternatives, such as a refinancing of our indebtedness, including our 2019 Notes, or incurring borrowings under our revolving credit facility. We cannot assure you that we would be able to refinance our indebtedness or that the terms on which we could refinance our indebtedness would be favorable.

A change of control could result in us facing substantial repayment obligations under our revolving credit facility and our 2019 Notes.

Our revolving credit agreement and the indentures governing our 2019 Notes contain provisions relating to change of control of our managing general partner, our partnership and our operating subsidiaries. Upon a change of control event, we may be required immediately to repay the outstanding principal, any accrued interest on and any other amounts owed by us under our revolving credit facility, the 2019 Notes and other outstanding indebtedness. The source of funds for these repayments would be our available cash or cash generated from other sources. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under our revolving credit facility would have the right to foreclose on our assets, which would have a material adverse effect on us. Furthermore, certain change of control events would constitute an event of default under the agreement governing our revolving credit facility, and we might not be able to obtain a waiver of such default. There is no restriction in our partnership agreement on the ability of our general partner to enter into a transaction which would trigger the change of control provisions of our revolving credit facility agreement or the indentures governing our 2019 Notes.

We depend on certain key crude oil and other feedstock suppliers for a significant portion of our supply of crude oil and other feedstocks, and the loss of any of these key suppliers or a material decrease in the supply of crude oil and other feedstocks generally available to our refineries could materially reduce our ability to make distributions to unitholders.

We purchase crude oil and other feedstocks from major oil companies as well as from various crude oil gatherers and marketers in east Texas and north Louisiana. In 2010, subsidiaries of Plains All American Pipeline, L.P. and Genesis Crude Oil, L.P. supplied us with approximately 49.6% and 4.6%, respectively, of our total crude oil supplies under term contracts and evergreen crude oil supply contracts and 41.5% of our total crude oil purchases in 2010 were from Legacy Resources, an affiliate of our general partner, to supply crude oil to our Princeton and Shreveport refineries. In addition, BP will supply the Superior, Wisconsin refinery with approximately 75% of its daily crude oil requirements, with such requirements estimated to be between 35,000 and 45,000 barrels per day. Each of our refineries is dependent on one or more of these suppliers and the loss of any of these suppliers would adversely affect our financial results to the extent we were unable to find another supplier of this substantial amount of crude oil. We do not maintain long-term contracts with most of our suppliers. For example, our contracts with Plains are currently month-to-month terminable upon 90 days’ notice. Additionally, we expect to purchase the crude oil supply for the Princeton refinery and Shreveport refinery directly from third-party suppliers under evergreen supply contracts and on the spot market. These evergreen contracts are generally terminable on 30 days notice, and purchases on the spot market may expose us to changes in commodity prices. For additional discussion regarding our crude oil and feedstock supply, please read Items 1 and 2 “Business and Properties — Crude Oil and Feedstock Supply” in our 2010 Annual Report.

To the extent that our suppliers reduce the volumes of crude oil and other feedstocks that they supply us as a result of declining production or competition or otherwise, our revenues, net income and cash available for distribution to unitholders and payments of our debt obligations would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks on comparable terms from other suppliers, which may not be possible in areas where the supplier that reduces its volumes is the primary supplier in the area. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines, governmental moratoriums on drilling or production activities or otherwise, could result in a decline in the volume of crude oil we refine. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We have no control over the level of drilling activity in the fields that supply our refineries, the amount of reserves underlying the wells in these fields, the rate at which production from a well will decline or the production decisions of producers, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital.

We are dependent on certain third-party pipelines for transportation of crude oil and refined products, and if these pipelines become unavailable to us, our revenues and cash available for distributions to our unitholders and payment of our debt obligations could decline.

Our Shreveport refinery is interconnected to pipelines that supply most of its crude oil and ship a portion of its refined fuel products to customers, such as pipelines operated by subsidiaries of Enterprise Products Partners L.P. and ExxonMobil. The Superior wholesale business transports products produced at the Superior refinery through several Magellan pipeline terminals in Minnesota, Wisconsin, Iowa, North Dakota and South Dakota. Since we do not own or operate any of these pipelines, their continuing operation is not within our control. In addition, any of these third-party pipelines could become unavailable to transport crude oil or our refined fuel products because of acts of God, accidents, government regulation, terrorism or other events. For example, our refinery run rates were affected by an approximately three week shutdown during May and June 2011 of the ExxonMobil crude oil pipeline serving our Shreveport refinery resulting from the Mississippi River flooding occurring during this period. If any of these third-party pipelines become unavailable to transport crude oil or our refined fuel products because of acts of God, accidents, government regulation, terrorism or other events, our revenues, net income and cash available for distributions to our unitholders and payment of our debt obligations could decline.

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

The borrowing base under our revolving credit facility is determined weekly or monthly depending upon availability levels or the existence of a default or event of default. Reductions in the value of our inventories as a result of lower crude oil prices could result in a reduction in our borrowing base, which would reduce the amount of financial resources available to meet our capital requirements. Further, if at any time our available capacity under our revolving credit facility falls below $54.1 million, or a default or event of default exists and for an additional 60 days after those circumstances do not exist, our cash balances in a dominion account established with the administrative agent will be applied on a daily basis to our outstanding obligations and the revolving credit facility. Further, if at any time our available capacity under our revolving credit facility falls below the greater of (i) 12.5% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) our revolving credit agreement commitments then in effect and (ii) $54.1 million (as increased, upon the effectiveness of the increase in the maximum availability under our revolving credit facility, by the same percentage as the percentage increase in our revolving credit agreement commitments), or a default or event of default exists thereunder and for an additional 60 days after those circumstances do not exist, our cash balances in a dominion account established with the administrative agent will be applied on a daily basis to our outstanding obligations under our revolving credit facility. In addition, decreases in the price of crude oil may require us to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our hedging positions. At September 30, 2011, we had $271.5 million in availability under our revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt and Credit Facilities” for additional information. If the borrowing base under our revolving credit facility decreases or we are required to post substantial amounts of cash collateral to our hedging counterparties, it could have a material adverse effect on our liquidity, financial condition and our ability to distribute cash to our unitholders.

An increase in interest rates will cause our debt service obligations to increase.

Borrowings under our revolving credit facility bear interest at a floating rate (4.50% as of September 30, 2011). The interest rate is subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) or prime rate. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow available for distribution to our unitholders. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

We may fail to successfully integrate the Superior Business with our existing business in a timely manner, which could have a material adverse effect on our business, financial condition, results of operations or cash flows, or fail to realize all of the expected benefits of the Superior Acquisition, which could negatively impact our future results of operations.

Integration of the Superior Business with our existing business will be a complex, time-consuming and costly process, particularly given that the Superior Acquisition has significantly increased our size, and diversify the geographic areas in which we operate. A failure to successfully integrate the Superior Business with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash flows. The difficulties of combining the Superior Business include, among other things:

	•		operating a larger combined organization and adding operations;

	•		difficulties in the assimilation of the assets and operations of the Superior refinery;

	•		customer or key employee loss from the Superior refinery;

	•		changes in key supply or feedstock agreements related to the Superior refinery;

	•		the diversion of management’s attention from other business concerns;

	•		integrating personnel from diverse business backgrounds and organizational cultures, including employees previously employed by Murphy Oil;

	•		managing relationships with new customers and suppliers for whom we have not previously provided products or services;

	•		maintaining an effective system of internal controls related to the Superior refinery and integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other regulatory compliance and corporate governance matters;

	•		an inability to complete other internal growth projects and/or acquisitions;

	•		difficulties integrating new technology systems that we have not historically used in our operations or financial reporting;

	•		an increase in our indebtedness;

	•		potential environmental or regulatory compliance matters or liabilities and title issues, including certain liabilities arising from the operation of the Superior refinery before the Superior Acquisition;

	•		coordinating geographically disparate organizations, systems and facilities;

	•		coordinating with the labor unions that represent the Superior refinery’s operating personnel; and

	•		coordinating and consolidating corporate and administrative functions.

If any of these risks or unanticipated liabilities or costs were to materialize, then any desired benefits of the Superior refinery may not be fully realized, if at all, and our future results of operations could be negatively impacted. In addition, the Superior refinery may actually perform at levels below the forecasts we used to evaluate the Superior Acquisition, due to factors that are beyond our control, such as competition in the Superior refinery’s region, market demand for the products the Superior refinery produces and regulatory requirements for maintenance and improvement projects at the Superior refinery. If the Superior refinery performs at levels below the forecasts we used to evaluate the Superior Acquisition, then our future results of operations could be negatively impacted.

In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors discussed in Part I Item 1A. “Risk Factors” in our 2010 Annual Report, which could materially affect our business, financial condition or future results. The risks described in this Quarterly Report and in our 2010 Annual Report are not the only risks facing the Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Removed and Reserved

Item 5. Other Information

None.

Item 6. Exhibits

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


Exhibit
Number		Description
2.1*		Asset Purchase Agreement, dated as of July 25, 2011, between Calumet Specialty Products Partners, L.P. and Murphy Oil Corporation.

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

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

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

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

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

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

4.1		Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)).

4.2		Indenture, dated September 19, 2011, by and among the Issuers, the Guarantors and the Trustee, governing the 2019 Senior Notes (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)).

4.3		Registration Rights Agreement, dated September 19, 2011, by and among the Issuers, the Guarantors and the Initial Purchasers, relating to the 2019 Senior Notes (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)).

10.1		Amendment No. 2 to Collateral Trust Agreement, effective as of September 30, 2011, by and among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on October 6, 2011 (File No. 000-51734)).

10.2*		Amendment to the ISDA Master Agreement, dated as of September 30, 2011, between J. Aron & Company and Calumet Lubricants Co., Limited Partnership.

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

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

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

100.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document


Exhibit
Number		Description
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document


*		Filed herewith.

**		XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

SIGNATURES

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


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

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

Date: November 4, 2011

Index to Exhibits


Exhibit
Number		Description
2.1*		Asset Purchase Agreement, dated as of July 25, 2011, between Calumet Specialty Products Partners, L.P. and Murphy Oil Corporation.

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

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

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

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

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

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

4.1		Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 4, 2010 (File No. 000-51734)).

4.2		Indenture, dated September 19, 2011, by and among the Issuers, the Guarantors and the Trustee, governing the 2019 Senior Notes (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)).

4.3		Registration Rights Agreement, dated September 19, 2011, by and among the Issuers, the Guarantors and the Initial Purchasers, relating to the 2019 Senior Notes (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 21, 2011 (File No. 000-51734)).

10.1		Amendment No. 2 to Collateral Trust Agreement, effective as of September 30, 2011, by and among Calumet Lubricants Co., Limited Partnership, the guarantors party thereto, the secured hedge counterparties thereto and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on October 6, 2011 (File No. 000-51734)).

10.2*		Amendment to the ISDA Master Agreement, dated as of September 30, 2011, between J. Aron & Company and Calumet Lubricants Co., Limited Partnership.

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

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

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

100.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document


Exhibit
Number		Description
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document


*		Filed herewith.

**		XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of the registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

TABLE OF CONTENTS

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

Exhibits

EX-2.1 EX-10.2 EX-31.1 EX-31.2 EX-32.1

CLMT 10-Q Quarter ended Sept. 30, 2011

Exhibits