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

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CLMT-2013.09.30-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013



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

FOR THE TRANSITION PERIOD FROM TO

Commission File Number: 000-51734

Calumet Specialty Products Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)



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

2780 Waterfront Parkway East Drive, Suite 200
Indianapolis, Indiana		46214
(Address of Principal Executive Officers)		(Zip Code)

(317) 328-5660

(Registrant’s Telephone Number, Including Area Code)

None

(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)

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 x No ¨

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 x No ¨

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.

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

At November 8, 2013, there were 69,317,278 common units outstanding.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

QUARTERLY REPORT

For the Three and Nine Months Ended September 30, 2013

Table of Contents



	Page
Part I
Item 1. Financial Statements
Condensed Consolidated Balance Sheets	4
Unaudited Condensed Consolidated Statements of Operations	5
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)	6
Unaudited Condensed Consolidated Statements of Partners’ Capital	7
Unaudited Condensed Consolidated Statements of Cash Flows	8
Notes to Unaudited Condensed Consolidated Financial Statements	10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 3. Quantitative and Qualitative Disclosures About Market Risk	70
Item 4. Controls and Procedures	72
Part II
Item 1. Legal Proceedings	73
Item 1A. Risk Factors	73
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	73
Item 3. Defaults Upon Senior Securities	73
Item 4. Mine Safety Disclosures	73
Item 5. Other Information	73
Item 6. Exhibits	74

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes certain “forward-looking statements.” 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 required audits or required operational changes 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, natural gas price changes and fuel products price changes, (iii) estimated costs of complying with the U.S. Environmental Protection Agency’s (“EPA”) Renewable Fuel Standards, including the prices paid for Renewable Identification Numbers (“RINs”) and (iv) our ability to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, debt instrument 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 sales 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. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in (1) Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (“2012 Annual Report”), (2) Part II, Item IA “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 (“Q1 Quarterly Report”) and (3) Part II, Item 1A “Risk Factors” in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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

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PART I

Item 1. Financial Statements

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2013		December 31, 2012
	(Unaudited)
	(In millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	133.9	$	32.2
Accounts receivable:
Trade	294.9		219.3
Other	7.1		7.5
	302.0		226.8
Inventories	559.7		553.6
Derivative assets	22.9		3.1
Prepaid expenses and other current assets	10.7		10.3
Deposits	2.7		7.9
Total current assets	1,031.9		833.9
Property, plant and equipment, net	1,118.7		986.9
Investment in unconsolidated affiliate	19.5		1.9
Goodwill	197.9		187.0
Other intangible assets, net	178.0		197.1
Other noncurrent assets, net	95.0		46.2
Total assets	$	2,641.0	$	2,253.0
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	454.5	$	333.4
Accrued interest payable	28.8		23.5
Accrued salaries, wages and benefits	13.3		20.1
Accrued income taxes payable	—		27.6
Other taxes payable	22.1		13.7
Other current liabilities	28.9		8.3
Current portion of long-term debt	0.5		0.8
Derivative liabilities	2.2		48.0
Total current liabilities	550.3		475.4
Pension and postretirement benefit obligations	21.1		24.0
Other long-term liabilities	1.0		1.1
Long-term debt, less current portion	863.8		862.7
Total liabilities	1,436.2		1,363.2
Commitments and contingencies
Partners’ capital:
Limited partners’ interest (69,317,278 and 57,529,778 units issued and outstanding at September 30, 2013 and December 31, 2012, respectively)	1,145.9		884.8
General partner’s interest	37.7		30.5
Accumulated other comprehensive income (loss)	21.2		(25.5		)
Total partners’ capital	1,204.8		889.8
Total liabilities and partners’ capital	$	2,641.0	$	2,253.0

See accompanying notes to unaudited condensed consolidated financial statements.

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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,
	2013			2012			2013			2012
	(In millions, except per unit and unit data)
Sales	$	1,505.5		$	1,179.8		$	4,178.3		$	3,436.4
Cost of sales	1,443.4			1,021.4			3,880.8			3,064.9
Gross profit	62.1			158.4			297.5			371.5
Operating costs and expenses:
Selling	13.9			15.0			46.7			26.7
General and administrative	15.8			12.8			59.9			41.3
Transportation	34.9			28.4			104.1			80.9
Taxes other than income taxes	3.7			1.8			9.7			5.4
Other	12.8			1.6			14.4			4.9
Operating income (loss)	(19.0		)	98.8			62.7			212.3
Other income (expense):
Interest expense	(24.2		)	(24.2		)	(73.7		)	(61.2		)
Realized gain (loss) on derivative instruments	4.2			(10.1		)	5.4			20.5
Unrealized gain (loss) on derivative instruments	2.4			(22.1		)	22.9			(11.3		)
Other	1.9			0.2			2.2			0.3
Total other expense	(15.7		)	(56.2		)	(43.2		)	(51.7		)
Net income (loss) before income taxes	(34.7		)	42.6			19.5			160.6
Income tax expense	0.1			0.2			0.5			0.6
Net income (loss)	$	(34.8	)	$	42.4		$	19.0		$	160.0
Allocation of net income (loss):
Net income (loss)	$	(34.8	)	$	42.4		$	19.0		$	160.0
Less:
General partner’s interest in net income (loss)	(0.7		)	0.8			0.4			3.2
General partner’s incentive distribution rights	3.8			1.7			10.9			3.3
Non-vested share based payments	—			0.2			0.2			0.9
Net income (loss) available to limited partners	$	(37.9	)	$	39.7		$	7.5		$	152.6
Weighted average limited partner units outstanding:
Basic	69,626,650			57,745,806			67,367,326			54,826,636
Diluted	69,626,650			57,825,603			67,553,709			54,866,915
Limited partners’ interest basic and diluted net income (loss) per unit	$	(0.54	)	$	0.69		$	0.11		$	2.78
Cash distributions declared per limited partner unit	$	0.685		$	0.59		$	2.015		$	1.68

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2013			2012			2013		2012
	(In millions)
Net income (loss)	$	(34.8	)	$	42.4		$	19.0	$	160.0
Other comprehensive income (loss):
Cash flow hedges:
Cash flow hedge (gain) loss reclassified to net income (loss)	(5.6		)	41.8			4.4		137.8
Change in fair value of cash flow hedges	14.1			(83.4		)	41.3		(236.3		)
Defined benefit pension and retiree health benefit plans	0.1			1.0			1.0		1.3
Total other comprehensive income (loss)	8.6			(40.6		)	46.7		(97.2		)
Comprehensive income (loss) attributable to partners’ capital	$	(26.2	)	$	1.8		$	65.7	$	62.8

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Accumulated Other Comprehensive Income (Loss)			Partners’ Capital
	Accumulated Other Comprehensive Income (Loss)			General Partner			Limited Partners			Total
	(In millions)
Balance at December 31, 2012	$	(25.5	)	$	30.5		$	884.8		$	889.8
Other comprehensive income	46.7			—			—			46.7
Net income	—			11.3			7.7			19.0
Common units repurchased for phantom unit grants	—			—			(5.0		)	(5.0		)
Amortization of vested phantom units	—			—			2.4			2.4
Issuances of phantom units, net of repurchases for taxes	—			—			(0.3		)	(0.3		)
Proceeds from public offerings of common units, net	—			—			392.5			392.5
Contributions from Calumet GP, LLC	—			8.4			—			8.4
Distributions to partners	—			(12.5		)	(136.2		)	(148.7		)
Balance at September 30, 2013	$	21.2		$	37.7		$	1,145.9		$	1,204.8

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	For the Nine Months Ended
	September 30,
	2013			2012
	(In millions)
Operating activities
Net income	$	19.0		$	160.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	88.2			63.9
Amortization of turnaround costs	10.9			10.3
Non-cash interest expense	5.2			4.4
Provision for doubtful accounts	0.6			0.3
Unrealized (gain) loss on derivative instruments	(22.9		)	11.3
Non-cash equity based compensation	3.4			5.1
Other non-cash activities	14.5			1.1
Changes in assets and liabilities:
Accounts receivable	(75.8		)	(32.4		)
Inventories	10.9			33.7
Prepaid expenses and other current assets	(0.3		)	(1.6		)
Derivative activity	3.0			0.9
Turnaround costs	(62.9		)	(14.1		)
Deposits	5.2			(1.8		)
Other assets	0.1			—
Accounts payable	121.7			26.8
Accrued interest payable	5.3			20.3
Accrued salaries, wages and benefits	(5.8		)	2.3
Accrued income taxes payable	(27.6		)	0.1
Other taxes payable	8.4			3.3
Other liabilities	11.6			2.9
Pension and postretirement benefit obligations	(2.4		)	(7.4		)
Net cash provided by operating activities	110.3			289.4
Investing activities
Additions to property, plant and equipment	(114.1		)	(36.7		)
Cash paid for acquisitions, net of cash acquired	(124.1		)	(379.0		)
Investment in unconsolidated affiliate	(17.8		)	—
Proceeds from sale of property, plant and equipment	—			1.9
Net cash used in investing activities	(256.0		)	(413.8		)
Financing activities
Proceeds from borrowings — revolving credit facility	731.9			1,147.8
Repayments of borrowings — revolving credit facility	(731.9		)	(1,147.8		)
Payments on capital lease obligations	(0.9		)	(1.2		)
Proceeds from other financing obligations	3.5			—
Proceeds from senior notes offering	—			270.2
Debt issuance costs	—			(7.5		)
Proceeds from public offerings of common units, net	392.5			146.6

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Contributions from Calumet GP, LLC	8.4			3.1
Common units repurchased and taxes paid for phantom unit grants	(7.1		)	(2.1		)
Distributions to partners	(149.0		)	(94.2		)
Net cash provided by financing activities	247.4			314.9
Net increase in cash and cash equivalents	101.7			190.5
Cash and cash equivalents at beginning of period	32.2			—
Cash and cash equivalents at end of period	$	133.9		$	190.5
Supplemental disclosure of noncash financing and investing activities
Equipment acquired under capital lease	$	—		$	5.8

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2013, the Company had 69,317,278 limited partner common units and 1,414,638 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain expenses. The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, waxes, asphalt and fuel and fuel related products including gasoline, diesel, jet fuel and heavy fuel oils. The Company is also engaged in the resale of purchased crude oil to third party customers. The Company owns facilities located in Shreveport, Louisiana (“Shreveport” and “Calumet Packaging” (formerly “TruSouth”)); Superior, Wisconsin (“Superior”); San Antonio, Texas (“San Antonio”); Great Falls, Montana (“Montana”); Princeton, Louisiana (“Princeton”); Cotton Valley, Louisiana (“Cotton Valley”); Karns City, Pennsylvania (“Karns City”); Dickinson, Texas (“Dickinson”); Louisiana, Missouri (“Missouri”) and Porter, Texas (“Royal Purple”) 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, 2013 and for the three and nine months ended September 30, 2013 and 2012 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, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2012 Annual Report.

2. New and Recently Adopted Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2011-11, Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the balance sheet. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet Topic (210) — Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies the scope of the offsetting disclosures and addresses any unintended consequences. Amendments to ASU 2011-11, as superseded by ASU 2013-01, are effective for the first reporting period (including interim periods) beginning on or after January 1, 2013 and should be applied retrospectively for any period presented. The adoption of ASU 2013-01 and ASU 2011-11 concerns presentation and disclosure only.

In October 2012, the FASB issued ASU No. 2012-04, Technical Corrections and Improvements (“ASU 2012-04”). ASU 2012-04 covers a wide range of topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. ASU 2012-04 is effective for fiscal periods beginning after December 15, 2012. The adoption of ASU 2012-04 did not have an impact on the Company’s consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires entities to report either on the statement of operations or disclose in the footnotes to the consolidated financial statements the effects on earnings from items that are reclassified out of comprehensive income. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. ASU 2013-02 is effective prospectively for the first reporting period after December 15, 2012 with early adoption permitted. The adoption of ASU 2013-02 concerns presentation and disclosure only.

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In February 2013, the FASB issued ASU No. 2013-04, Liabilities (Topic 405) — Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date (“ASU 2013-04”). ASU 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements from which the total amount of the obligation within the scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal periods, (including interim periods), beginning after December 15, 2013 and should be applied retrospectively. The Company is currently evaluating the impacts of the adoption of ASU 2013-04 on its consolidated financial statements.

3. Acquisitions

Missouri Acquisition

On January 3, 2012, the Company completed the acquisition of the aviation and refrigerant lubricants business (a polyolester based synthetic lubricants business) of Hercules Incorporated, a subsidiary of Ashland, Inc., including a manufacturing facility located in Louisiana, Missouri for aggregate consideration of approximately $19.6 million (“Missouri Acquisition”). The Missouri Acquisition was financed with borrowings under the Company’s revolving credit facility and cash on hand. The Company believes the Missouri Acquisition provides greater diversity to its specialty products segment. The assets acquired and results of operations have been included in the Company’s condensed consolidated balance sheets and the Company’s unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the Missouri Acquisition, the Company incurred no acquisition costs during the three months ended September 30, 2012 and $0.5 million during the nine months ended September 30, 2012, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

The Company recorded $1.5 million of goodwill as a result of the Missouri Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired is as follows (in millions):



	Allocation of Purchase Price
Inventories	$	2.7
Property, plant and equipment	10.0
Goodwill	1.5
Other intangible assets	5.4
Total purchase price	$	19.6

The component of the intangible assets listed in the table above as of January 3, 2012, based upon a third party appraisal, was as follows (in millions):



	Amount		Life (Years)
Customer relationships	$	5.4	20

Calumet Packaging Acquisition

On January 6, 2012, the Company completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC (“TruSouth”), a specialty petroleum packaging and distribution company located in Shreveport, Louisiana for aggregate consideration of approximately $26.9 million, net of cash acquired (“Calumet Packaging Acquisition”). The Calumet Packaging Acquisition was financed with borrowings under the Company’s revolving credit facility. Immediately prior to its acquisition by the Company, TruSouth was owned in part by affiliates of the Company’s general partner. The Company believes the Calumet Packaging Acquisition provides greater diversity to its specialty products segment. The assets acquired and liabilities assumed have been included in the Company’s condensed consolidated balance sheets and results of operations have been included in the Company’s unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the Calumet Packaging Acquisition, the Company incurred no acquisition costs during the three months ended September 30, 2012 and approximately $0.2 million during the nine months ended September 30, 2012, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

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The Company recorded $0.4 million of goodwill as a result of the Calumet Packaging Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment. The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows (in millions):



	Allocation of Purchase Price
Accounts receivable	$	5.2
Inventories	8.0
Prepaid expenses and other current assets	0.3
Property, plant and equipment	17.7
Goodwill	0.4
Other intangible assets	2.6
Accounts payable	(2.7		)
Accrued salaries, wages and benefits	(0.2		)
Other current liabilities	(0.9		)
Long-term debt	(3.5		)
Total purchase price, net of cash acquired	$	26.9

The components of intangible assets listed in the table above as of January 6, 2012, based upon a third party appraisal, were as follows (in millions):



	Amount		Life (Years)
Customer relationships	$	1.8	16
Tradenames	0.7		9
Non-competition agreements	0.1		2
Total	$	2.6
Weighted average amortization period			14

Royal Purple Acquisition

On July 3, 2012, the Company completed the acquisition of Royal Purple, Inc. (“Royal Purple”), a Texas corporation which was converted into a Delaware limited liability company at closing, for aggregate consideration of approximately $331.2 million, net of cash acquired (“Royal Purple Acquisition”). Royal Purple is a leading independent formulator and marketer of premium industrial and consumer lubricants to a diverse customer base across several large markets including oil and gas, chemicals and refining, power generation, manufacturing and transportation, food and drug manufacturing and automotive aftermarket. The Royal Purple Acquisition was financed with net proceeds of $262.6 million from the Company’s June 2012 private placement of 9 5/8% senior notes due August 1, 2020 and cash on hand. The Company believes the Royal Purple Acquisition increases its position in the specialty lubricants market, expands its geographic reach, increases its asset diversity and enhances its specialty products segment. The assets acquired and liabilities assumed have been included in the Company’s condensed consolidated balance sheets and results of operations have been included in the Company’s unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the Royal Purple Acquisition, during the three and nine months ended September 30, 2012, the Company incurred approximately $0.3 million and $0.4 million, respectively, of acquisition costs, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

The Company recorded $109.2 million of goodwill as a result of the Royal Purple Acquisition, all of which was recorded within the Company’s specialty products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its specialty products segment.

The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows (in millions):

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	Allocation of Purchase Price
Accounts receivable	$	15.2
Inventories	19.3
Prepaid expenses and other current assets	0.2
Property, plant and equipment	10.6
Goodwill	109.2
Other intangible assets	183.4
Accounts payable	(3.8		)
Accrued salaries, wages and benefits	(1.7		)
Taxes payable	(0.2		)
Other current liabilities	(1.0		)
Total purchase price, net of cash acquired	$	331.2

The components of intangible assets listed in the table above as of July 3, 2012, based upon a third party appraisal, were as follows (in millions):



	Amount		Life (Years)
Customer relationships	$	118.7	20
Tradenames	14.8		Indefinite
Tradenames	5.7		10
Trade secrets	44.2		12
Total	$	183.4
Weighted average amortization period			18

Montana Acquisition

On October 1, 2012, the Company completed the acquisition from Connacher Oil and Gas Limited (“Connacher”) of all the shares of common stock of Montana Refining Company, Inc. (“Montana”) and an insignificant affiliated company for aggregate consideration of approximately $191.6 million, net of cash acquired (“Montana Acquisition”). Montana produces gasoline, diesel, jet fuel and asphalt, which are marketed primarily into local markets in Washington, Montana, Idaho and Alberta, Canada. The Montana Acquisition was funded primarily with cash on hand with the balance through borrowings under the Company’s revolving credit facility. The Company believes the Montana Acquisition further diversifies its crude oil feedstock slate, operating asset base and geographic presence. The assets acquired and liabilities assumed and results of operations have been included in the Company’s condensed consolidated balance sheets and unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the Montana Acquisition, the Company incurred no acquisition costs during the three months ended September 30, 2013 and approximately $0.1 million during the nine months ended September 30, 2013, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

Immediately after closing the Montana Acquisition, the Company converted Montana Refining Company, Inc. into a Delaware limited liability company, Calumet Montana Refining, LLC. This conversion resulted in the recognition of a current income tax liability of approximately $27.6 million, which was paid during the nine months ended September 30, 2013, and was offset by the derecognition of a deferred tax liability for a comparable amount assumed in connection with the acquisition.

The Company recorded $27.6 million of goodwill as a result of the Montana Acquisition, all of which was recorded within the Company’s fuel products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its fuel products segment.

The allocation of the aggregate purchase price to assets acquired and liabilities assumed is as follows (in millions):

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	Allocation of Purchase Price
Accounts receivable	$	29.0
Inventories	43.7
Prepaid expenses and other current assets	23.1
Deposits	0.3
Property, plant and equipment	125.9
Goodwill	27.6
Other noncurrent assets, net	0.3
Accounts payable	(8.4		)
Accrued salaries, wages and benefits	(1.4		)
Deferred income tax liability	(27.6		)
Accrued income taxes payable	(15.6		)
Other taxes payable	(3.0		)
Other current liabilities	(0.1		)
Pension and postretirement benefit obligations	(2.2		)
Total purchase price, net of cash acquired	$	191.6

San Antonio Acquisition

On January 2, 2013, the Company completed the acquisition of NuStar Energy L.P.’s (“NuStar”) San Antonio, Texas refinery, together with related assets and the assumption of certain liabilities and obligations (“San Antonio Acquisition”). Total consideration for the San Antonio Acquisition was approximately $117.9 million, net of cash acquired and excluding certain purchase price adjustments. The refinery has total crude oil throughput capacity of 14,500 bpd and primarily produces jet fuel, diesel, other fuel products and specialty solvents. The San Antonio Acquisition was funded with borrowings under the Company’s revolving credit facility with the balance through cash on hand. The Company believes the San Antonio Acquisition further diversifies the Company’s crude oil feedstock slate, operating asset base and geographic presence. The assets acquired and results of operations have been included in the Company’s condensed consolidated balance sheets and unaudited condensed consolidated statements of operations since the date of acquisition. In connection with the San Antonio Acquisition, the Company incurred no acquisition costs during the three months ended September 30, 2013 and approximately $0.5 million during the nine months ended September 30, 2013, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

The Company recorded $5.7 million of goodwill as a result of the San Antonio Acquisition, all of which was recorded within the Company’s fuel products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s strategic platform for expansion in its fuel products segment.

The San Antonio 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 to assets acquired and liabilities assumed is as follows (in millions):



	Allocation of Purchase Price
Inventories	$	17.0
Property, plant and equipment, net	100.7
Goodwill	5.7
Accrued salaries, wages and benefits	(0.1		)
Other current liabilities	(5.4		)
Total purchase price, net of cash acquired	$	117.9

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Crude Oil Logistics Acquisition

On August 9, 2013, the Company completed the acquisition of seven crude oil loading facilities and related assets in North Dakota and Montana from Murphy Oil USA, Inc. (“Murphy”) for aggregate consideration of approximately $6.2 million (“Crude Oil Logistics Acquisition”). The Crude Oil Logistics Acquisition was funded with cash on hand. As part of this acquisition, the Company assumed pipeline space on the Enbridge Pipeline System (“Enbridge Pipeline”) previously held by Murphy. The Company will have the ability to transport crude oil directly from the point of lease, into the Company’s newly acquired crude oil loading facilities and then onto the Enbridge Pipeline where it can be routed to the Company’s refineries and/or third party customers. As part of this transaction, the Company and Murphy jointly consented to terminate an existing crude oil purchase agreement (“Murphy Crude Oil Supply Agreement”) wherein Murphy supplied the Company’s Superior refinery with up to 10,000 barrels per day of crude oil. In connection with the Crude Oil Logistics Acquisition, during the three and nine months ended September 30, 2013, the Company incurred acquisition costs of approximately $0.2 million, which are reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

The preliminary allocation of the aggregate purchase price to assets acquired was primarily comprised of $0.9 million of property, plant and equipment, net and $5.2 million of goodwill, all of which was recorded within the Company’s fuel products segment. Goodwill recognized in the acquisition relates primarily to enhancing the Company’s crude oil gathering operations to support the Superior refinery.

Results of Sales and Earnings

The following financial information reflects sales and operating income of the Royal Purple, Montana and San Antonio Acquisitions that are included in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013 (in millions):



	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
Sales	$	276.6	$	810.5
Operating income	$	2.7	$	28.2

Pro Forma Financial Information (Unaudited)

The following unaudited pro forma financial information reflects the unaudited condensed consolidated results of operations of the Company as if the Royal Purple, Montana and San Antonio Acquisitions had taken place on January 1, 2012 (in millions, except for per unit data):



	Three Months Ended September 30, 2012		Nine Months Ended September 30, 2012
Sales	$	1,463.6	$	4,255.4
Net income	$	54.1	$	168.5
Limited partners’ interest net income per unit — basic	$	0.73	$	2.31
Limited partners’ interest net income per unit — diluted	$	0.74	$	2.31

The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Royal Purple, Montana and San Antonio Acquisitions. 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.

Fair Value Measurements of Acquisitions

The fair value of the property, plant and equipment and intangible assets are based upon the discounted cash flow method that involves inputs that are not observable in the market (Level 3). Goodwill assigned represents the amount of consideration transferred in excess of the fair value assigned to individual assets acquired and liabilities assumed.

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4. Inventories

The cost of inventory is recorded using the last-in, first-out (LIFO) method. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation. 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. The replacement cost of these inventories, based on current market values, would have been $91.5 million and $38.3 million higher as of September 30, 2013 and December 31, 2012, respectively.

Inventories consist of the following (in millions):



	September 30, 2013		December 31, 2012
Raw materials	$	124.5	$	85.4
Work in process	122.3		119.5
Finished goods	312.9		348.7
	$	559.7	$	553.6

Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs.

5. Joint Venture

On February 7, 2013, the Company entered into a joint venture agreement with MDU Resources Group, Inc. (“MDU”) to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture is named Dakota Prairie Refining, LLC. The refinery’s total construction cost is estimated at approximately $300.0 million. The capitalization of the joint venture is expected to be funded through contributions of $150.0 million from MDU and $75.0 million from the Company and proceeds of $75.0 million from an unsecured syndicated term loan facility with the joint venture as the borrower. The term loan facility was funded in April 2013. Funding for the project will occur over the course of the construction period, with the majority of the direct funding by the Company expected to occur in 2014. The diesel refinery is expected to be operational in the fourth quarter of 2014. The joint venture will allocate profits on a 50%/50% basis to the Company and MDU. The joint venture will be governed by a board of managers comprised of representatives from both the Company and MDU. MDU will provide a portion of the crude oil supply to the refinery, as well as natural gas and electricity utility services. The Company will provide refinery operations, crude oil procurement and refined product marketing expertise to the joint venture.

The Company accounts for its ownership in its joint venture under the equity method of accounting. As of September 30, 2013, the Company has an investment of $19.5 million in Dakota Prairie Refining, LLC primarily related to the development of the refinery.

6. Other Noncurrent Assets

Other noncurrent assets primarily include deferred debt issuance costs and turnaround costs. Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $66.3 million and $14.3 million as of September 30, 2013 and December 31, 2012, respectively. The Company capitalizes these costs and amortizes the costs on a straight-line basis over the lives of the turnaround assets. These amounts are net of accumulated amortization of $22.0 million and $17.8 million at September 30, 2013 and December 31, 2012, respectively.

7. 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 EPA, various state environmental regulatory bodies, the Internal Revenue Service, various state and local departments of revenue and the federal 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.

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Environmental

The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent and complex federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, 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, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Certain of these 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.

In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require the Company to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on September 12, 2012, the EPA published final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. The Company is currently evaluating the effect that the NSPS rule may have on its refinery operations.

Voluntary remediation of subsurface contamination is in process at certain 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.

San Antonio Refinery

In connection with the San Antonio Acquisition, the Company agreed to indemnify NuStar from any environmental liabilities associated with the San Antonio refinery, except for any governmental penalties or fines that may result from NuStar’s actions or inactions during NuStar’s 20 month period of ownership of the San Antonio refinery. Anadarko Petroleum Corporation (“Anadarko”) and Age Refining, Inc. (“Age Refining”), a third party that has since entered bankruptcy, are subject to a 1995 Agreed Order from the Texas Natural Resource Conservation Commission, now known as the Texas Commission on Environmental Quality (“TCEQ”), pursuant to which Anadarko and Age Refining are obligated to assess and remediate contamination at the San Antonio refinery. The Company is not a party to this Agreed Order. The Company is in discussions with both TCEQ and Anadarko over how best to address pre-existing contamination at the San Antonio refinery.

Montana Refinery

In connection with the Montana Acquisition (see Note 3), the Company became a party to an existing 2002 Refinery Initiative consent decree (“Montana Consent Decree”) with the EPA and the Montana Department of Environmental Quality(“MDEQ”). The material obligations imposed by the Montana Consent Decree have been completed. Periodic reporting is the primary current obligation under the Montana Consent Decree. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previous hazardous waste permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. The Company believes the majority of damages related to such contamination at the Montana refinery are covered by a contractual indemnity provided by Holly Corporation (“Holly”), the owner and operator of the Montana refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Montana refinery. Under this asset purchase agreement, Holly agreed to indemnify Connacher and Montana Refining Company, Inc. for environmental conditions arising under Holly’s ownership and operation of the Montana refinery, and existing as of the date of sale to Connacher. As a result of the Montana Acquisition, the Company’s liability is limited under the asset purchase agreement between Holly and Connacher and the costs to be covered by the Company are not believed to be material at this time. Some of these costs covered by the Company will be voluntary to prepare the expansion area in conjunction with the Company’s planned capacity expansion at the Montana refinery. Prior to the Montana Acquisition, Holly had reimbursed Connacher in accordance with the contractual indemnity for remedial actions related to such contamination at the Montana refinery.

Superior Refinery

In connection with the Superior Acquisition, the Company became a party to an existing consent decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to its

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Superior refinery. Under the Superior Consent Decree, the Company will have to complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the facility to the EPA and the WDNR. The Company currently estimates costs of approximately $0.9 million to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be significant. In addition, the Company may have to pursue certain additional environmental and safety-related projects at the Superior refinery including, but not limited to: (i) installing process equipment pursuant to applicable EPA fuel content regulations; (ii) purchasing emission credits on an interim basis until such time as any process equipment that may be required under the EPA fuel content regulations is installed and operational; (iii) performing monitoring of historical contamination at the facility; (iv) upgrading treatment equipment or possibly pursuing other remedies, as necessary, to satisfy new effluent discharge limits under a federal Clean Water Act permit renewal that is pending and (v) pursuing various voluntary programs at the Superior refinery, including removing asbestos-containing materials or enhancing process safety or other maintenance practices. Completion of these additional projects will result in the Company incurring additional costs, which could be substantial. For the three months ended September 30, 2013 and 2012, the Company incurred approximately $0.5 million and $0.6 million, respectively, of costs related to installing process equipment pursuant to the EPA fuel content regulations. For the nine months ended September 30, 2013 and 2012, the Company incurred approximately $0.7 million and $2.1 million, respectively, of costs related to installing process equipment pursuant to the EPA fuel content regulations.

On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery, which included a proposed penalty amount of $0.1 million. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and attended an informal conference with the EPA held September 12, 2012. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial results or operations.

The Company is contractually indemnified by Murphy Oil Corporation (“Murphy Oil”) under an asset purchase agreement between the Company and Murphy Oil for specified environmental liabilities arising from the operations of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior 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 believes contractual indemnity by Murphy Oil for such specified environmental liabilities is unlimited in duration and not subject to any monetary deductibles or maximums. The Company was also contractually indemnified by Murphy Oil under the asset purchase agreement until October 1, 2013 for liabilities arising from breaches of certain environmental representations and warranties made by Murphy Oil, subject to a maximum liability of $22.0 million, for which the Company was required to contribute up to the first $6.6 million. The amount of any damages payable by Murphy Oil pursuant to the contractual indemnities under the asset purchase agreement were net of any amount recoverable under an environmental insurance policy that the Company obtained in connection with the Superior Acquisition, which named the Company and Murphy Oil as insureds and covers environmental conditions existing at the Superior refinery prior to the Superior Acquisition.

Shreveport, Cotton Valley and Princeton Refineries

On December 23, 2010, the Company entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations prior to December 31, 2010. Among other things, the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During the three months ended September 30, 2013 and 2012, the Company incurred approximately $0.3 million and $0.1 million, respectively, of such expenditures. During the nine months ended September 30, 2013 and 2012, the Company incurred approximately $4.8 million and $2.2 million, respectively, of such expenditures and estimates additional expenditures of approximately $6.0 million to $8.0 million of capital expenditures and expenditures related to additional personnel and environmental studies over the next three years as a result of the implementation of these requirements. These capital investment requirements are incorporated into the Company’s annual capital expenditures budgets and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the Global Settlement to have a material adverse effect on the Company’s financial results or operations.

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In August 2011, the EPA conducted an inspection of the Shreveport refinery’s Risk Management Program compliance. An inspection report dated October 20, 2011 was transmitted to the Shreveport refinery. The Company submitted supplemental information to the EPA, which was followed by a site visit from EPA personnel. On September 12, 2013, the EPA issued a revised draft Consent Agreement and Final Order to the Shreveport refinery, which included a proposed civil penalty of $0.3 million.

The Company is contractually indemnified by Shell Oil Company (“Shell”), as successor to Pennzoil-Quaker State Company and Atlas Processing Company under an asset purchase agreement between the Company and Shell, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The contractual indemnity is believed by the Company to be unlimited in amount and duration, but requires the Company to contribute up to $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities.

Current and former owners of a property in Bossier Parish, Louisiana, filed a lawsuit in March 2006 against the Company and other defendants, including Chevron USA, Inc. (“Chevron”), Legacy Resources Co., L.P. (“Legacy”) and Exxon Mobil Corporation (“Exxon Mobil”), alleging damage from salt water and other environmental contamination on the property arising from historical oil field production on the property. Oil field exploration and production on the property began in the 1920’s by predecessors of Exxon Mobil. The Company received an assignment of certain mineral leases for portions of the property in 1993 from an affiliate of Texaco, prior to Texaco’s merger with Chevron. The Company then assigned those mineral leases to Legacy. The mineral lease assignments include indemnity provisions obligating the assignees to provide certain indemnities to the assignors. The Company, Chevron, Legacy and the plaintiffs are participating in mediation in an attempt to settle the litigation.

Occupational Health and Safety

The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and 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 and training programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard 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’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.

The Company has completed studies to assess the adequacy of its PSM practices at its Shreveport refinery with respect to certain consensus codes and standards. During the three months ended September 30, 2013 and 2012, the Company incurred approximately $0.8 million and $0.2 million, respectively, of related capital expenditures. During the nine months ended September 30, 2013 and 2012, the Company incurred approximately $2.8 million and $0.5 million, respectively, of related capital expenditures and expects to incur additional capital expenditures of approximately $1.0 million during the last quarter of 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.

In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program under OSHA’s National Emphasis Program. 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 $0.2 million. The Company has contested the Cotton Valley Citation and associated penalty 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.

Labor Matters

The Company has employees covered by various collective bargaining agreements. The Cotton Valley and Dickinson collective bargaining agreements were ratified on March 21, 2013 and April 1, 2013, respectively, and both will expire on March 31, 2016. The Shreveport collective bargaining agreement was ratified on April 30, 2013 and will expire on April 30, 2016.

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Standby Letters of Credit

The Company has agreements with various financial institutions for standby letters of credit which have been issued to vendors. As of September 30, 2013 and December 31, 2012, the Company had outstanding standby letters of credit of $140.5 million and $222.4 million, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 8 for additional information regarding the Company’s revolving credit facility. The maximum amount of letters of credit the Company could issue at September 30, 2013 and December 31, 2012 under its revolving credit facility is subject to borrowing base limitations, 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 in effect ($850.0 million at September 30, 2013 and December 31, 2012).

As of September 30, 2013 and December 31, 2012, the Company had availability to issue letters of credit of $477.1 million and $355.1 million, respectively, under its revolving credit facility. As of December 31, 2012, the outstanding standby letters of credit issued under the revolving credit facility included a $25.0 million letter of credit issued to a hedging counterparty to support a portion of its fuel products hedging program.

8. Long-Term Debt

Long-term debt consisted of the following (in millions):



	September 30, 2013			December 31, 2012
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments monthly, borrowings due June 2016	$	—		$	—
Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.94% for the nine months ended September 30, 2013	600.0			600.0
Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.02% for the nine months ended September 30, 2013	275.0			275.0
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	4.9			5.5
Less unamortized discounts	(15.6		)	(17.0		)
Total long-term debt	864.3			863.5
Less current portion of long-term debt	0.5			0.8
	$	863.8		$	862.7

9 5/8% Senior Notes

On June 29, 2012, in connection with the Royal Purple Acquisition, the Company issued and sold $275.0 million in aggregate principal amount of 9 5/8% of senior notes due August 1, 2020 (the “2020 Notes”) in a private placement pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 98.25 percent of par. The 2020 Notes 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 net proceeds of $262.6 million, net of discount, underwriters’ fees and expenses, which the Company used to fund a portion of the purchase price of the Royal Purple Acquisition. Refer to Note 3 for additional information regarding the Royal Purple Acquisition.

Interest on the 2020 Notes is paid semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2013. The 2020 Notes will mature on August 1, 2020, unless redeemed prior to maturity. The 2020 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (100%-owned Delaware corporation that is minor and was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2020 Notes). The operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indenture governing the 2020 Notes.

The indenture governing the 2020 Notes contains 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

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subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2020 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2020 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 2020 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 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.

On December 4, 2012, the Company filed an exchange offer registration statement for the 2020 Notes with the SEC, which was declared effective on June 27, 2013. The exchange offer was completed on July 26, 2013, thereby fulfilling all of the requirements of the 2020 Notes registration rights agreement.

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 $400.0 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 Section 4(a)(2) of 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 $389.0 million net of underwriters’ fees and expenses, which the Company used to repay in full borrowings outstanding under its prior term loan, 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 $200.0 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 Section 4(a)(2) 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 $180.3 million 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 is 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 jointly and severally guaranteed on a senior unsecured basis by all of the Company’s current operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of Calumet Finance Corp. (100%-owned Delaware corporation that is minor and was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2019 Notes). The operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the 2019 Notes.

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 both Moody’s Investors Service, Inc. and 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.

On December 16, 2011, the Company filed exchange offer registration statements for the 2019 Notes with the SEC, which were declared effective on January 3, 2012. The exchange offers were completed on February 2, 2012, thereby fulfilling all of the requirements of the 2019 Notes registration rights agreements by the specified dates.

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Amended and Restated Senior Secured Revolving Credit Facility

The Company has an $850.0 million senior secured revolving credit facility, which is its primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility 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, 2013, the margin was 100 basis points for prime and 225 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter.

In addition to paying interest monthly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.375% to 0.50% per annum depending on the average daily available unused borrowing capacity. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.

The borrowing capacity at September 30, 2013 under the revolving credit facility was $617.6 million. As of September 30, 2013, the Company had no outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $140.5 million, leaving $477.1 million available for additional borrowings based on specified availability limitations. 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 revolving credit agreement) (without giving effect to the LC Reserve (as defined in the revolving credit agreement)) and (b) the credit agreement commitments then in effect and (ii) $46.4 million, (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 revolving credit agreement) of at least 1.0 to 1.0. As of September 30, 2013, the Company’s Fixed Charge Coverage Ratio was 2.8 to 1.0.

As of September 30, 2013, the Company was in compliance with all covenants under the revolving credit facility.

Maturities of Long-Term Debt

As of September 30, 2013, maturities of the Company’s long-term debt are as follows (in millions):



Year	Maturity
2013	$	0.2
2014	0.4
2015	0.3
2016	0.3
2017	0.4
Thereafter	878.3
Total	$	879.9

9. Derivatives

The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment) and natural gas. The Company uses various strategies to reduce its exposure to commodity price risk. The Company does not attempt to eliminate all of the Company’s risk as the costs of such actions are believed to be too high in relation to the risk posed to the Company’s future cash flows, earnings and liquidity. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, futures and options, to attempt to reduce the Company’s exposure with respect to:


•	crude oil purchases and sales;

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•	fuel product sales and purchases;


•	natural gas purchases; and


•	fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX WTI, Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”).

The Company does not hold or issue derivative instruments for trading purposes.

The Company recognizes all derivative instruments at their fair values (see Note 10) as either current assets or current 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 a derivative’s fair value could result in significant ineffectiveness and potentially no longer qualify it for hedge accounting. The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets and liabilities on the Company’s condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012 (in millions):



	September 30, 2013								December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets			Gross Amounts of Recognized Assets		Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets

Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	47.1	$	(10.5	)	$	36.6		$	24.9	$	(14.4	)	$	10.5
Gasoline swaps	—		—			—			5.2		(4.9		)	0.3
Diesel swaps	12.5		(22.3		)	(9.8		)	7.0		(14.9		)	(7.9		)
Jet fuel swaps	1.6		(5.6		)	(4.0		)	8.0		(7.8		)	0.2
Total derivative instruments designated as hedges	61.2		(38.4		)	22.8			45.1		(42.0		)	3.1
Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps	2.2		(0.9		)	1.3			0.1		(0.1		)	—
Crude oil basis swaps	—		(3.1		)	(3.1		)	0.1		(0.1		)	—
Gasoline swaps	0.2		(0.1		)	0.1			—		—			—
Diesel swaps	3.6		(0.7		)	2.9			5.1		(5.1		)	—
Jet fuel swaps	0.4		(0.2		)	0.2			—		—			—
Specialty products segment:
Crude oil swaps	—		—			—			1.6		(1.6		)	—
Natural gas swaps	0.1		(1.4		)	(1.3		)	—		—			—
Total derivative instruments not designated as hedges	6.5		(6.4		)	0.1			6.9		(6.9		)	—
Total derivative instruments	$	67.7	$	(44.8	)	$	22.9		$	52.0	$	(48.9	)	$	3.1

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	September 30, 2013								December 31, 2012
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets			Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets

Derivative instruments designated as hedges:
Fuel products segment:
Crude oil swaps	$	(8.8	)	$	10.5	$	1.7		$	(41.1	)	$	14.4	$	(26.7	)
Gasoline swaps	—			—		—			(2.8		)	4.9		2.1
Diesel swaps	(22.9		)	22.3		(0.6		)	(25.2		)	14.9		(10.3		)
Jet fuel swaps	(5.6		)	5.6		—			(10.1		)	7.8		(2.3		)
Total derivative instruments designated as hedges	(37.3		)	38.4		1.1			(79.2		)	42.0		(37.2		)
Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps	(1.1		)	0.9		(0.2		)	(10.8		)	0.1		(10.7		)
Crude oil basis swaps	(5.3		)	3.1		(2.2		)	(3.5		)	0.1		(3.4		)
Gasoline swaps	(0.1		)	0.1		—			(2.2		)	—		(2.2		)
Diesel swaps	(0.3		)	0.7		0.4			(1.2		)	5.1		3.9
Jet fuel swaps	0.1			0.2		0.3			—			—		—
Specialty products segment:
Crude oil swaps	—			—		—			—			1.6		1.6
Natural gas swaps	(3.0		)	1.4		(1.6		)	—			—		—
Total derivative instruments not designated as hedges	(9.7		)	6.4		(3.3		)	(17.7		)	6.9		(10.8		)
Total derivative instruments	$	(47.0	)	$	44.8	$	(2.2	)	$	(96.9	)	$	48.9	$	(48.0	)

The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel 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. Periodically, the Company may enter into crude oil and fuel product basis swaps to more effectively hedge its crude oil purchases and fuel products sales. These derivatives can be combined with a swap contract in order to create a more effective hedge. The Company has entered into crude oil basis swaps for 2013 that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract.

To the extent a derivative instrument designated as a hedge is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations. Hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously accumulated in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated

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deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments.

Effective January 1, 2012, hedge accounting was discontinued prospectively for certain crude oil derivative instruments when it was determined that they were no longer highly effective in offsetting changes in the cash flows associated with crude oil purchases at the Company’s Superior refinery due to the volatility in crude oil pricing differentials between heavy crude oil and NYMEX WTI. Effective April 1, 2012, hedge accounting was discontinued prospectively for certain gasoline and diesel derivative instruments associated with gasoline and diesel sales at the Company’s Superior refinery. The discontinuance of hedge accounting on these derivative instruments has caused the Company to recognize the following gains and losses in realized gain (loss) on derivative instruments and unrealized gain (loss) in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012 (in millions):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013			2012
Realized gain (loss) on derivative instruments	$	1.6	$	(4.8	)	$	(2.6	)	$	49.7
Unrealized gain (loss) on derivative instruments	$	1.3	$	(35.0	)	$	8.7		$	(6.8	)

The amount reclassified from accumulated other comprehensive income (loss) into earnings, as a result of the discontinuance of hedge accounting for certain jet fuel derivative instruments because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, caused the Company to recognize derivative losses of $0.7 million and $1.7 million in realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2012, respectively.

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, determined on a derivative by derivative basis or in the aggregate for a specific commodity, and has the potential for the future loss of hedge accounting. Ineffectiveness and the loss of hedge accounting has resulted in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize cash flows.

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive income (loss) and unaudited condensed consolidated statements of partners’ capital as of, and for the three months ended September 30, 2013 and 2012 related to its derivative instruments that were designated as cash flow hedges (in millions):



	Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)						Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Loss) (Effective Portion)							Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
	Three Months Ended						Location of Gain (Loss)	Three Months Ended						Location of Gain (Loss)	Three Months Ended
	September 30,							September 30,							September 30,
Type of Derivative	2013			2012				2013			2012				2013			2012
Fuel products segment:
Crude oil swaps	$	59.2		$	13.0		Cost of sales	$	11.1		$	8.0		Unrealized/ Realized	$	11.3		$	34.1
Gasoline swaps	(0.3		)	8.9			Sales	(0.1		)	—			Unrealized/ Realized	(0.6		)	(23.1		)
Diesel swaps	(33.1		)	(49.3		)	Sales	(4.4		)	(29.2		)	Unrealized/ Realized	(0.6		)	(1.2		)
Jet fuel swaps	(11.7		)	(56.0		)	Sales	(0.2		)	(20.4		)	Unrealized/ Realized	(0.5		)	(4.5		)
Specialty products segment:
Crude oil swaps	—			—			Cost of sales	(0.8		)	(0.2		)	Unrealized/ Realized	—			—
Total	$	14.1		$	(83.4	)		$	5.6		$	(41.8	)		$	9.6		$	5.3

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The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended September 30, 2013 and 2012 related to its derivative instruments not designated as cash flow hedges (in millions):



	Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments						Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments
	Three Months Ended						Three Months Ended
	September 30,						September 30,
Type of Derivative	2013			2012			2013			2012
Fuel products segment:
Crude oil swaps	$	2.0		$	(8.9	)	$	2.7		$	40.2
Crude oil basis swaps	(0.2		)	—			(7.2		)	—
Gasoline swaps	—			2.4			(0.4		)	(40.9		)
Diesel swaps	0.9			2.8			(1.1		)	(34.2		)
Jet fuel swaps	0.7			(0.6		)	0.5			0.5
Specialty products segment:
Crude oil swaps	0.1			—			(0.1		)	1.0
Natural gas swaps	—			(1.4		)	(0.9		)	1.6
Interest rate swaps	—			(0.1		)	—			0.1
Total	$	3.5		$	(5.8	)	$	(6.5	)	$	(31.7	)

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of other comprehensive income (loss) and its unaudited condensed consolidated statements of partners’ capital as of, and for the nine months ended September 30, 2013 and 2012 related to its derivative instruments that were designated as cash flow hedges (in millions):



	Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)						Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Loss) (Effective Portion)							Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
	Nine Months Ended						Location of Gain (Loss)	Nine Months Ended						Location of Gain (Loss)	Nine Months Ended
	September 30,							September 30,							September 30,
Type of Derivative	2013			2012				2013			2012				2013			2012
Fuel products segment:
Crude oil swaps	$	32.5		$	(85.9	)	Cost of sales	$	(2.5	)	$	42.6		Unrealized/ Realized	$	(16.5	)	$	84.0
Gasoline swaps	(0.7		)	(31.3		)	Sales	(0.2		)	(39.2		)	Unrealized/ Realized	(1.2		)	(38.4		)
Diesel swaps	8.5			(70.7		)	Sales	(3.0		)	(52.0		)	Unrealized/ Realized	(3.9		)	(3.0		)
Jet fuel swaps	1.0			(48.4		)	Sales	1.8			(89.0		)	Unrealized/ Realized	6.0			(2.6		)
Specialty products segment:
Crude oil swaps	—			—			Cost of sales	(0.5		)	(0.2		)	Unrealized/ Realized	—			—
Total	$	41.3		$	(236.3	)		$	(4.4	)	$	(137.8	)		$	(15.6	)	$	40.0

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the nine months ended September 30, 2013 and 2012 related to its derivative instruments not designated as cash flow hedges (in millions):

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	Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments						Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
Type of Derivative	2013			2012			2013			2012
Fuel products segment:
Crude oil swaps	$	(6.8	)	$	(16.2	)	$	42.5		$	(40.0	)
Crude oil basis swaps	7.3			—			(1.9		)	—
Gasoline swaps	2.9			13.8			(0.4		)	(1.1		)
Diesel swaps	6.4			8.0			(4.5		)	6.7
Jet fuel swaps	0.7			(1.7		)	0.4			—
Specialty products segment:
Crude oil swaps	1.8			—			(1.6		)	1.6
Natural gas swaps	—			(4.9		)	(2.9		)	2.7
Interest rate swaps	—			(0.7		)	—			1.0
Total	$	12.3		$	(1.7	)	$	31.6		$	(29.1	)

The cash flow impact of the Company’s derivative activities is classified primarily 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. As of September 30, 2013, the Company had seven counterparties, in which derivatives held were net assets, totaling $22.9 million. As of December 31, 2012, the Company had two counterparties, in which the derivatives held were net assets, totaling $3.1 million. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa2 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 master derivative contracts with these counterparties. No such collateral was held by the Company as of September 30, 2013 or December 31, 2012. The Company’s contracts with these counterparties allow for netting of derivative instruments 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 is not netted against derivative assets or liabilities. As of September 30, 2013, the Company had provided its counterparties with no collateral. As of December 31, 2012, the Company had provided its counterparties with no collateral except for a $25.0 million letter of credit provided to one counterparty to support crack spread hedging. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.

Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. In certain cases, the Company’s credit threshold is dependent upon the Company’s maintenance of certain corporate credit ratings with Moody’s and S&P. In the event that the Company’s corporate credit rating is lowered below specified levels by Moody’s and 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, 2013 and December 31, 2012, there was a net asset of $5.0 million and a net liability $7.5 million, 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.

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The effective portion of the cash flow hedges classified in accumulated other comprehensive income was $31.7 million as of September 30, 2013. The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was $14.0 million as of December 31, 2012. Absent a change in the fair market value of the underlying transactions, the following other comprehensive income (loss) at September 30, 2013 will be reclassified to earnings by December 31, 2016 with balances being recognized as follows (in millions):



Year	Accumulated Other Comprehensive Income (Loss)
2013	$	21.4
2014	9.9
2015	(0.8		)
2016	1.2
Total	$	31.7

Based on fair values as of September 30, 2013, the Company expects to reclassify $30.2 million of net gains on derivative instruments from accumulated other comprehensive income to earnings during the next twelve months due to actual crude oil purchases and diesel and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the dates of settlement.

Crude Oil Swap Contracts — Specialty Products Segment

At September 30, 2013, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.

At December 31, 2012, the Company had purchased a crude oil swap for 200,000 barrels in the second quarter of 2012 related to future crude oil purchases in its specialty products segment, which was not designated as a cash flow hedge. The Company subsequently sold a crude oil derivative swap in the third quarter of 2012, and the net impact of these two derivatives was a net gain of $1.6 million that was recorded to unrealized loss on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012. This gain was realized in January 2013 upon settlement and was recorded to realized gain on derivative instruments in the unaudited condensed consolidated statements of operations.

Natural Gas Swap Contracts — Specialty Products Segment

At September 30, 2013, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as cash flow hedges:



Natural Gas Swap Contracts by Expiration Dates	MMBtu	$/MMBtu
Fourth Quarter 2013	1,250,000	$	4.12
Calendar Year 2014	3,100,000	4.16
Calendar Year 2015	3,500,000	4.27
Calendar Year 2016	2,700,000	4.42
Calendar Year 2017	1,000,000	4.29
Totals	11,550,000
Average price		$	4.26

At December 31, 2012, the Company did not have any natural gas derivatives related to future natural gas purchases in its specialty products segment.

Crude Oil Contracts — Fuel Products Segment

Crude Oil Swap Contracts

At September 30, 2013, 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:

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Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Swap ($/Bbl)
Fourth Quarter 2013	1,104,000	12,000	$	93.41
Calendar Year 2014	6,068,500	16,626	89.93
Calendar Year 2015	5,329,000	14,600	89.08
Calendar Year 2016	1,098,000	3,000	85.12
Totals	13,599,500
Average price			$	89.49

At September 30, 2013, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as cash flow hedges:



Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Swap ($/Bbl)
Fourth Quarter 2013	368,000	4,000	$	96.58
Calendar Year 2014	411,000	1,126	95.21
Calendar Year 2015	637,500	1,747	89.89
Totals	1,416,500
Average price			$	93.17

At September 30, 2013, the Company had the following derivatives to sell crude oil in its fuel products segment, none of which are designated as cash flow hedges:



Crude Oil Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
Fourth Quarter 2013	92,000	1,000	$	102.30
Totals	92,000
Average price			$	102.30

At December 31, 2012, 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:



Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Swap ($/Bbl)
First Quarter 2013	1,665,000	18,500	$	101.67
Second Quarter 2013	1,911,000	21,000	100.22
Third Quarter 2013	1,426,000	15,500	95.62
Fourth Quarter 2013	1,104,000	12,000	93.41
Calendar Year 2014	5,110,000	14,000	89.47
Calendar Year 2015	4,781,500	13,100	89.49
Totals	15,997,500
Average price			$	92.85

At December 31, 2012, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as cash flow hedges:

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Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Swap ($/Bbl)
First Quarter 2013	630,000	7,000	$	101.34
Second Quarter 2013	455,000	5,000	98.56
Third Quarter 2013	368,000	4,000	96.58
Fourth Quarter 2013	368,000	4,000	96.58
Totals	1,821,000
Average price			$	98.72

Crude Oil Basis Swap Contracts

During 2012 and 2013, the Company entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between Canadian heavy crude oil and NYMEX WTI, pricing differentials between LLS and NYMEX WTI and pricing differentials between MSW and NYMEX WTI. At September 30, 2013, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as cash flow hedges:



Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Differential to NYMEX WTI ($/Bbl)
Fourth Quarter 2013	794,000	8,630	$	(17.92	)
Totals	794,000
Average price			$	(17.92	)

At December 31, 2012, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as cash flow hedges:



Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Differential to NYMEX WTI ($/Bbl)
First Quarter 2013	180,000	2,000	$	(23.75	)
Second Quarter 2013	364,000	4,000	(27.38		)
Third Quarter 2013	184,000	2,000	(23.75		)
Fourth Quarter 2013	184,000	2,000	(23.75		)
Totals	912,000
Average differential			$	(25.20	)

During the third quarter of 2013, the Company entered into crude oil basis swaps for 250,000 barrels related to future crude oil purchases and sales to mitigate the risk of future changes in pricing differentials between Brent and NYMEX WTI on the Company’s reselling of crude oil. The net impact of these derivative instruments, none of which are designated as cash flow hedges, was a net gain of $0.1 million that has been recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013. The net impact of these derivative instruments will be realized upon settlement in the fourth quarter of 2013 and will be recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations.

At December 31, 2012, the Company did not have any crude oil basis swaps related to future crude oil purchases and sales to mitigate the risk of future changes in pricing differentials between Brent and NYMEX WTI.

Fuel Products Swap Contracts — Fuel Products Segment

Diesel Swap Contracts

At September 30, 2013, the Company had the following derivatives related to diesel sales in its fuel products segment, all of which are designated as cash flow hedges:

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Diesel Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
Fourth Quarter 2013	828,000	9,000	$	120.82
Calendar Year 2014	4,793,500	13,133	116.88
Calendar Year 2015	4,781,500	13,100	115.81
Calendar Year 2016	1,098,000	3,000	111.93
Totals	11,501,000
Average price			$	116.25

At September 30, 2013, the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as cash flow hedges:



Diesel Swap Contracts by Expiration Dates	Barrels Sold