Calumet Specialty Products Partners (CLMT) 10-K3 Mar 142013 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Mar. 03, 2014	Jun. 28, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'Calumet Specialty Products Partners, L.P.	'	'
Entity Central Index Key	'0001340122	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$1,862.20
Entity Common Stock, Shares Outstanding	'	69,317,278	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:	'	'
Cash and cash equivalents	$121.10	$32.20
Accounts receivable:	'	'
Trade, less allowance for doubtful accounts of $1.2 million and $1.2 million, respectively	250.3	219.3
Other	13	7.5
Total accounts receivable	263.3	226.8
Inventories	567.4	553.6
Derivative assets	0	3.1
Prepaid expenses and other current assets	18.9	10.3
Deposits	3.7	7.9
Total current assets	974.4	833.9
Property, plant and equipment, net	1,160.40	986.9
Investment in unconsolidated affiliate	33.4	1.9
Goodwill	207	187
Other intangible assets, net	212.9	197.1
Other noncurrent assets, net	100	46.2
Total assets	2,688.10	2,253
Current liabilities:	'	'
Accounts payable	355.8	332.6
Accrued interest payable	22.5	23.5
Accrued salaries, wages and benefits	14	20.1
Accrued income taxes payable	0	27.6
Other taxes payable	18.4	13.7
Other current liabilities	36.2	9.1
Current portion of long-term debt	0.4	0.8
Derivative liabilities	54.8	48
Total current liabilities	502.1	475.4
Pension and postretirement benefit obligations	11.7	24
Other long-term liabilities	1.1	1.1
Long-term debt, less current portion	1,110.40	862.7
Total liabilities	1,625.30	1,363.20
Commitments and contingencies	'	'
Partnersâ€™ capital:	'	'
Limited partnersâ€™ interest (69,317,278 units and 57,529,778 units, issued and outstanding at December 31, 2013 and 2012, respectively)	1,079.60	884.8
General partnerâ€™s interest	36.6	30.5
Accumulated other comprehensive loss	-53.4	-25.5
Total partnersâ€™ capital	1,062.80	889.8
Total liabilities and partnersâ€™ capital	$2,688.10	$2,253

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Allowance for doubtful accounts	$1.20	$1.20
Limited Partners	'	'
Limited partners' interest units issued	69,317,278	57,529,778
Limited partners' interest units outstanding	69,317,278	57,529,778

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Sales	$5,421.40	$4,657.30	$3,134.90
Cost of sales	5,011.40	4,144.10	2,860.80
Gross profit	410	513.2	274.1
Operating costs and expenses:	'	'	'
Selling	62.6	41.6	12.2
General and administrative	82.1	60.9	38.6
Transportation	142.7	107.9	94.2
Taxes other than income taxes	14.2	9.1	5.7
Insurance recoveries	0	0	-8.7
Other	16.8	7.8	6.8
Operating income	91.6	285.9	125.3
Other income (expense):	'	'	'
Interest expense	-96.8	-85.6	-48.7
Debt extinguishment costs	-14.6	0	-15.1
Realized gain (loss) on derivative instruments	-4.7	9.5	-7.9
Unrealized gain (loss) on derivative instruments	25.7	-3.8	-10.4
Other	2.7	0.5	0.8
Total other expense	-87.7	-79.4	-81.3
Income before income taxes	3.9	206.5	44
Income tax expense	0.4	0.8	1
Allocation of net income:	'	'	'
Net income	3.5	205.7	43
Less:	'	'	'
General partnerâ€™s interest in net income	0.1	4.1	0.9
General partnerâ€™s incentive distribution rights	14.7	5.5	0.2
Non-vested share based payments	0.2	1.1	0
Net income (loss) available to limited partners	($11.50)	$195	$41.90
Weighted average limited partner units outstanding:	'	'	'
Basic	67,938,784	55,559,183	42,598,876
Diluted	67,938,784	55,676,741	42,644,086
Limited partnersâ€™ interest basic net income (loss) per unit	($0.17)	$3.51	$0.98
Limited partnersâ€™ interest diluted net income (loss) per unit	($0.17)	$3.50	$0.98
Cash distributions declared per limited partner unit	$2.70	$2.30	$1.94

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]	'	'	'
Net income	$3.50	$205.70	$43
Cash flow hedges:	'	'	'
Cash flow hedge (income) loss reclassified to net income	-0.5	154.1	104
Change in fair value of cash flow hedges	-36.9	-215.1	-34.2
Defined benefit pension and retiree health benefit plans	9.6	-3	-3.7
Foreign currency translation adjustment	-0.1	0	0
Total other comprehensive income (loss)	-27.9	-64	66.1
Comprehensive income (loss) attributable to partnersâ€™ capital	($24.40)	$141.70	$109.10

Consolidated_Statements_of_Par

Consolidated Statements of Partners' Capital (USD $)	Total	Accumulated Other Comprehensive Income (Loss)	General Partner	Limited Partner, Common	Limited Partner, Subordinated
In Millions, unless otherwise specified	Total	Accumulated Other Comprehensive Income (Loss)	General Partner	Limited Partner, Common	Limited Partner, Subordinated
Beginning balance at Dec. 31, 2010	$398.30	($27.60)	$18.20	$390.80	$16.90
Increase (Decrease) in Partners' Capital [Roll Forward]	'	'	'	'	'
Other comprehensive income (loss)	66.1	66.1	0	0	0
Net income	43	0	1.1	41.9	0
Common units repurchased for phantom unit grants	-0.6	0	0	-0.6	0
Issuances of phantom units, net of taxes withheld	0.8	0	0	0.8	0
Amortization of vested phantom units	3	0	0	3	0
Proceeds from public offerings of common units, net	294.7	0	0	294.7	0
Contribution from Calumet GP, LLC	6.3	0	6.3	0	0
Subordinated unit conversion	0	0	0	10.8	-10.8
Distributions to partners	'	0	-1.7	-74.9	-6.1
Payments of Capital Distribution	82.7	'	'	'	'
Ending balance at Dec. 31, 2011	728.9	38.5	23.9	666.5	0
Increase (Decrease) in Partners' Capital [Roll Forward]	'	'	'	'	'
Other comprehensive income (loss)	-64	-64	0	0	0
Net income	205.7	0	9.6	196.1	0
Common units repurchased for phantom unit grants	-2.1	0	0	-2.1	0
Issuances of phantom units, net of taxes withheld	1.7	0	0	1.7	0
Amortization of vested phantom units	2.3	0	0	2.3	0
Proceeds from public offerings of common units, net	146.6	0	0	146.6	0
Contribution from Calumet GP, LLC	3.1	0	3.1	0	0
Distributions to partners	'	0	-6.1	-126.3	0
Payments of Capital Distribution	132.4	'	'	'	'
Ending balance at Dec. 31, 2012	889.8	-25.5	30.5	884.8	0
Increase (Decrease) in Partners' Capital [Roll Forward]	'	'	'	'	'
Other comprehensive income (loss)	-27.9	-27.9	0	0	0
Net income	3.5	0	14.8	-11.3	0
Common units repurchased for phantom unit grants	-5	0	0	-5	0
Issuances of phantom units, net of taxes withheld	-0.3	0	0	-0.3	0
Amortization of vested phantom units	3.2	0	0	3.2	0
Proceeds from public offerings of common units, net	392.5	0	0	392.5	0
Contribution from Calumet GP, LLC	8.4	0	8.4	0	0
Distributions to partners	-201.4	0	-17.1	-184.3	0
Payments of Capital Distribution	201.6	'	'	'	'
Ending balance at Dec. 31, 2013	$1,062.80	($53.40)	$36.60	$1,079.60	$0

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities	'	'	'
Net income	$3.50	$205.70	$43
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation and amortization	117.8	91.6	63.1
Amortization of turnaround costs	15.9	13.4	11.4
Non-cash interest expense	7	6.1	3.7
Non-cash debt extinguishment costs	3.4	0	14.4
Provision for doubtful accounts	0.1	0	0.4
Unrealized (gain) loss on derivative instruments	-25.7	3.8	10.4
Loss on disposal of fixed assets	15.2	2.5	1.5
Non-cash equity based compensation	4.8	6.5	4.9
Other non-cash activities	0.6	1.1	0
Changes in assets and liabilities:	'	'	'
Accounts receivable	-32.3	34.6	-54.5
Inventories	14.3	17.9	-167
Prepaid expenses and other current assets	2.6	21.7	-0.4
Derivative activity	-1.8	-5	11.7
Turnaround costs	-68.6	-14.9	-14.1
Deposits	4.2	-5.9	0
Other assets	-0.1	-4	-0.4
Accounts payable	6.8	11.1	131.3
Accrued interest payable	-1	13	7.4
Accrued salaries, wages and benefits	-7.1	1	4.1
Accrued income taxes payable	-27.6	-16.1	0.4
Other taxes payable	3	0.9	5.5
Other liabilities	6.8	2.7	-12.1
Pension and postretirement benefit obligations	-2.7	-7.6	-0.9
Net cash provided by operating activities	39.1	380.1	63.8
Investing activities	'	'	'
Additions to property, plant and equipment	-160.8	-57	-49.5
Investment in unconsolidated affiliate	-31.8	0	0
Proceeds from insurance recoveries â€” equipment	0	0	1.9
Cash paid for acquisitions, net of cash acquired	-177.7	-569.2	-413.2
Proceeds from sale of property, plant and equipment	0	2	0.4
Net cash used in investing activities	-370.3	-624.2	-460.4
Financing activities	'	'	'
Proceeds from borrowings â€” revolving credit facility	865.6	1,558.30	1,598.70
Repayments of borrowings â€” revolving credit facility	-865.6	-1,558.30	-1,609.50
Repayments of borrowings â€” term loan credit facility	0	0	-367.4
Repayments of borrowings â€” senior notes	-100	0	0
Repayments of borrowings â€” acquisition debt assumed	-11.9	0	0
Payments on capital lease obligations	-1.1	-1.5	-1.1
Proceeds from other financing obligations	3.5	0	0
Proceeds from public offerings of common units, net	392.5	146.6	294.7
Proceeds from senior notes offerings	344.7	270.2	586
Debt issuance costs	-7.3	-7.7	-27.7
Contributions from Calumet GP, LLC	8.4	3.1	6.3
Common units repurchased and taxes paid for phantom unit grants	-7.1	-2.1	-0.6
Distributions to partners	-201.6	-132.4	-82.7
Net cash provided by financing activities	420.1	276.2	396.7
Net increase in cash and cash equivalents	88.9	32.1	0.1
Cash and cash equivalents at beginning of year	32.2	0.1	0
Cash and cash equivalents at end of year	121.1	32.2	0.1
Supplemental disclosure of cash flow information	'	'	'
Interest paid, net of capitalized interest	91.4	66.2	37.9
Income taxes paid	29.8	0.7	0.6
Non-cash property, plant and equipment additions	$13.10	$5.80	$0

Description_of_the_Business

Description of the Business	12 Months Ended
Description of the Business	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
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 December 31, 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 of its 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 and fuel and fuel-related products including gasoline, diesel, jet fuel, asphalt 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”); Porter, Texas (“Royal Purple”) and Wall Township, New Jersey (“Bel-Ray”) and terminals located in Burnham, Illinois (“Burnham”); Rhinelander, Wisconsin (“Rhinelander”); Crookston, Minnesota (“Crookston”) and Proctor, Minnesota (“Duluth”).

Summary_of_Significant_Account

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Consolidation
	The consolidated financial statements reflect the accounts of the Company and its wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.
	Reclassifications
	Certain amounts in the prior years’ consolidated financial statements have been reclassified to conform to the current year presentation.
	Use of Estimates
	The Company’s consolidated financial statements are prepared in conformity with U.S. generally accepted accounting (“U.S. GAAP”) principles which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Cash and Cash Equivalents
	Cash and cash equivalents includes all highly liquid investments with a maturity of three months or less at the time of purchase.
	Accounts Receivable
	The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are carried at their face amounts and are generally due within 30 days to 45 days from date of invoice for the specialty products segment and 10 days from date of invoice for the fuel products segment. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay. Individual accounts are written off against the allowance for doubtful accounts after all reasonable collection efforts have been exhausted. The activity in the allowance for doubtful accounts was as follows (in millions):


		December 31,
		2013				2012			2011
	Beginning balance	$	1.2			$	0.9		$	0.6

	Provision	0.1				—			0.4

	Recoveries	—				0.4			—

	Write-offs, net	(0.1		)		(0.1		)	(0.1		)
	Ending balance	$	1.2			$	1.2		$	0.9

	Inventories
	The cost of inventory is recorded using the last-in, first-out (LIFO) method. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. The replacement cost of these inventories, based on current market values, would have been $32.2 million and $38.3 million higher as of December 31, 2013 and 2012, respectively. At December 31, 2013 and 2012, the Company had $2.6 million and $2.3 million, respectively, of consigned inventory.
	Inventories consist of the following (in millions):


		December 31,
		2013				2012
	Raw materials	$	122.7			$	85.4

	Work in process	102.6				119.5

	Finished goods	342.1				348.7

		$	567.4			$	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. For each of the years ended December 31, 2013, 2012 and 2011, the Company recorded gains and (losses) of $4.2 million, $(4.2) million and $5.2 million, respectively, in cost of sales in the consolidated statements of operations due to the liquidation of inventory layers.
	In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. During the years ended December 31, 2013, 2012 and 2011 the Company recorded $6.0 million, $8.1 million and $2.0 million, respectively, of losses in cost of sales in the consolidated statements of operations due to the lower of cost or market valuation.
	Derivatives
	The Company is exposed to fluctuations in the price of numerous commodities, such as crude oil (its principal raw material) and natural gas, as well as the sales prices of gasoline, diesel and jet fuel. Given the historical volatility of commodity prices, these fluctuations can significantly impact sales, gross profit and net income. Therefore, the Company utilizes derivative instruments primarily to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas and the sale of fuel products. The Company employs various hedging strategies and does not hold or issue derivative instruments for trading purposes. For further information, please refer to Note 8.
	Property, Plant and Equipment
	Property, plant and equipment are stated on the basis of cost. Depreciation is calculated generally on composite groups, using the straight-line method over the estimated useful lives of the respective groups. Assets under capital leases are amortized over the lesser of the useful life of the asset or the term of the lease.
	Property, plant and equipment, including depreciable lives, consisted of the following (in millions):


		December 31,
		2013				2012
	Land	$	17.6			$	11.2

	Buildings and improvements (10 to 40 years)	39.1				28.1

	Machinery and equipment (10 to 20 years)	1,327.40				1,173.00

	Furniture and fixtures (5 to 10 years)	21.7				7.6

	Assets under capital leases (10 to 28 years)	11.1				11.1

	Construction-in-progress	121.5				53.8

		1,538.40				1,284.80

Less accumulated depreciation	(378.0		)		(297.9		)
	$	1,160.40			$	986.9

Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related accumulated depreciation are retired, and any gain or loss is reflected in earnings.
During 2013, 2012 and 2011, the Company incurred $101.2 million, $86.3 million and $49.3 million, respectively, of interest expense of which $4.4 million, $0.7 million and $0.6 million, respectively, was capitalized as a component of property, plant and equipment.
The Company has not recorded an asset retirement obligation as of December 31, 2013 or 2012 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.
During the years ended December 31, 2013, 2012 and 2011, the Company recorded $92.0 million, $74.3 million and $55.5 million, respectively, of depreciation expense on its property, plant and equipment. Depreciation expense included $0.7 million, $1.0 million and $1.1 million for the years ended 2013, 2012 and 2011, respectively, related to the Company’s capital lease assets.
The Company capitalizes the cost of computer software developed or obtained for internal use. Capitalized software is amortized using the straight-line method over five years. As of December 31, 2013 and 2012, the Company has $17.3 million and $15.0 million, respectively, of unamortized capitalized software costs. During the years ended December 31, 2013, 2012 and 2011, the Company recorded $3.3 million, $1.0 million, and $0.4 million, respectively, of amortization expense on capitalized computer software.
Investment in Unconsolidated Affiliate
The Company accounts for its ownership in its Dakota Prairie Refining, LLC joint venture in accordance with ASC 323, Investments — Equity Method and Joint Ventures. The joint venture’s refinery was not operational in 2013. The equity method of accounting is applied when the investor has an ownership interest of less than 50% and/or has significant influence over the operating or financial decisions of the investee. Under the equity method, the Company’s proportionate share of net income (loss) is reflected as a single-line item in the consolidated statements of operations and increases or decreases, as applicable, in the carrying value of the Company’s investment in the consolidated balance sheets. In addition, the proportionate share of net income (loss) is reflected as a non-cash activity in operating activities in the consolidated statements of cash flows. Contributions increase the carrying value of the investment and are reflected as an investing activity in the consolidated statements of cash flows.
Equity method investments are assessed for other-than-temporary impairment when the investment generates net losses. No impairment was recognized in 2013 or 2012. For further information on investment in unconsolidated affiliate, refer to Note 4.
Goodwill and Indefinite Lived Intangible Assets
Goodwill represents the excess of purchase price over fair value of the net assets acquired in various acquisitions. See Note 3 for more information. The Company reviews goodwill for impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable in accordance with ASC 350, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). In September 2011, the FASB amended ASU 2011-08 which amended the rules for testing for impairment. Under ASU 2011-08, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The Company early adopted ASU 2011-08 for the October 1, 2011 annual goodwill impairment test.
In assessing the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company assesses relevant events and circumstances that may impact the fair value and the carrying amount of the reporting unit. The identification of relevant events and circumstances and how these may impact a reporting unit’s fair value or carrying amount involve significant judgment and assumptions. The judgment and assumptions include the identification of macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and Company specific events and making the assessment on whether each relevant factor will impact the impairment test positively or negatively and the magnitude of any such impact.
If the Company’s qualitative assessment concludes that it is probable that an impairment exists or the Company skips the qualitative assessment then the Company needs to perform a quantitative assessment. In the first step of the quantitative assessment, the Company’s assets and liabilities, including existing goodwill and other intangible assets, are assigned to the identified reporting units to determine the carrying value of the reporting units. If the carrying value of a reporting unit is in excess of its fair value, an impairment may exist, and the Company must perform an impairment analysis, in which the implied fair value of the goodwill is compared to its carrying value to determine the impairment charge, if any.
When performing the quantitative assessment, the fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation, and risks associated with the reporting unit.
Intangible assets with an indefinite life are not amortized but are subject to review each reporting period to determine whether events and circumstances continue to support an indefinite useful life as well as an annual impairment test.
Based on the results of the quantitative assessment in 2013 and qualitative assessments in 2012 and 2011 of the reporting units, the Company believes it is more likely than not that the fair value of its reporting units are greater than their carrying amounts. No impairment was recognized for goodwill and indefinite lived intangible assets in 2013, 2012 or 2011.
Other Intangible Assets
Other intangible assets consist of intangible assets associated with customer relationships, supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements that were acquired in various acquisitions. The majority of these assets are being amortized using discounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships are being amortized using the discounted estimated future cash flows method based upon assumed rates of annual customer attrition. For more information, refer to Note 5.
Other Noncurrent Assets
Other noncurrent assets include deferred debt issuance costs and turnaround costs. Deferred debt issuance costs were $29.7 million and $29.4 million as of December 31, 2013 and 2012, respectively, and are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $13.6 million and $6.6 million at December 31, 2013 and 2012, respectively.
Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $67.0 million and $14.3 million as of December 31, 2013 and 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 $25.7 million and $17.8 million at December 31, 2013 and 2012, respectively.
Impairment of Long-Lived Assets
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In such an event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair value of the long-lived asset. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.
During 2013 and 2012, the Company recorded write-downs related to idle fixed assets within its specialty products segment. The non-cash charges of $10.5 million and $1.6 million, were recorded in other operating costs and expenses on the consolidated statements of operations and loss on disposal of fixed assets in the consolidated statements of cash flows for the years ended December 31, 2013 and 2012, respectively.
Business Combinations and Related Business Acquisition Costs
Assets and liabilities associated with business acquisitions are recorded at fair value, using the acquisition method of accounting. The Company allocates the purchase price of acquisitions based upon the fair value of each component, which may be derived from various observable or unobservable inputs and assumptions. The Company may utilize third-party valuation specialists to assist the Company in this allocation. Initial purchase price allocations are preliminary and subject to revision within the measurement period, not to exceed one year from the date of acquisition. 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 identifiable assets acquired and liabilities assumed.
Business acquisition costs are expensed as incurred, and are reported as general and administrative expenses in the consolidated statements of operations. The Company defines these costs to include finder’s fees, advisory, legal, accounting, valuation, and other professional or consulting fees, as well as travel associated with the evaluation and effort to acquire specific businesses. For further information, refer to Note 3.
Revenue Recognition
The Company recognizes revenue on orders received from its customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under the Company’s normal billing and credit terms, all of the Company’s obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.
Concentrations of Credit Risk
The Company performs periodic credit evaluations of its customers’ financial condition and in some instances requires cash in advance or letters of credit prior to shipment for domestic orders. For international orders, letters of credit are generally required and the Company maintains insurance policies which cover certain export orders. The Company maintains an allowance for doubtful customer accounts for estimated losses resulting from the inability of its customers to make required payments. The allowance for doubtful accounts is developed based on several factors including historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay, which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, from time to time the Company has significant derivative assets with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s ASC 820-10, Fair Value Measurements and Disclosures, valuations to determine the impact of the counterparty credit risk on the valuation of its derivative instruments.
Income Taxes
The Company, as a partnership, is generally not liable for federal income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries. However, certain wholly-owned subsidiaries of the Company, are corporations and, as a result, are liable for income taxes on their earnings. Income taxes related to these subsidiaries were not significant in 2013, 2012 and 2011. Additionally, the Company is subject to franchise taxes which were not material for 2013, 2012 and 2011. Income taxes on the earnings of the Company, with the exception of the above mentioned items, are the responsibility of its partners, with earnings of the Company included in partners’ earnings.
In the event that the Company’s taxable income did not meet certain qualification requirements, the Company would be taxed as a corporation. Interest and penalties related to income taxes, if any, would be recorded in income tax expense. Generally, tax returns remain subject to examination by taxing authorities for three years. The Company had no unrecognized tax benefits as of December 31, 2013 and 2012.
Excise and Sales Taxes
The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of its products to non-exempt customers. Excise taxes and sales taxes assessed and collected from customers are recorded on a net basis within sales in the Company’s consolidated statements of operations.
Earnings per Unit
The Company calculates earnings per unit under ASC 260-10, Earnings per Share. The Company treats incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to receive IDRs. Also, the undistributed earnings are allocated to the partnership interests based on the allocation of earnings to the Company’s partners’ capital accounts as specified in the Company’s partnership agreement. When distributions exceed earnings, net income is reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the Company’s partnership agreement.
Unit Based Compensation
For unit based compensation awards granted, compensation expense is recognized in the Company’s consolidated financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The unit based compensation awards vest over a period not exceeding four years. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.
Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). Liability Awards are recorded in accrued salaries, wages and benefits based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense. See Note 11 for more information on Liability Awards.
Shipping and Handling Costs
The Company complies with ASC 605-45, Revenue Recognition — Principal Agent Considerations. ASC 605-45 requires the classification of shipping and handling costs billed to customers in sales and the classification of shipping and handling costs incurred in cost of sales, or to be disclosed if classified elsewhere. The Company has reflected $142.7 million, $107.9 million and $94.2 million, respectively, for the years ended December 31, 2013, 2012, and 2011, in transportation expense in the consolidated statements of operations, the majority of which is billed to customers.
Advertising Expenses
The Company expenses advertising costs as incurred which totaled $14.6 million, $8.2 million and $1.7 million in 2013, 2012 and 2011, respectively. Advertising expenses are reported as selling expenses in the consolidated statements of operations.
Renewable Identification Numbers Obligation
The Company’s Renewable Identification Numbers obligation (“RINs Obligation”) represents a liability for the purchase of RINs to satisfy the U.S. Environmental Protection Agency (“EPA”) requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as of the balance sheet date. The Company uses the inventory model to account for RINs, measuring acquired RINs at weighted-average cost. The cost of RINs used each period is charged to cost of sales with cash inflows and outflows recorded in the operating cash flow section of the consolidated statements of cash flows. Excess RINs are classified as inventory in the consolidated balance sheets. The Company recognizes a liability at the end of each reporting period in which the Company does not have sufficient RINs to cover the RINs Obligation. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN spot price.

New 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 July 2012, the FASB issued ASU No. 2012-02, Intangibles (Topic 350)—Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). ASU 2012-02 permits an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is more than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset exceeds its carrying amount, quantitative impairment testing is not required. However, if an entity concludes otherwise, quantitative impairment testing is required. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The adoption of ASU 2012-02 did not have a material impact on the Company’s consolidated financial statements.
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 in the consolidated statements 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.
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.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions	'
	Acquisitions
	On December 10, 2013, the Company completed the acquisition of Bel-Ray Company, LLC, a manufacturer and global distributor of high-performance lubricants and greases, for aggregate consideration of approximately $53.6 million, net of cash acquired and excluding debt assumed and certain purchase price adjustments (“Bel-Ray Acquisition”). Bel-Ray manufactures and distributes both domestically and internationally, a wide array of high-end specialty synthetic lubricants and greases which are used in the aerospace, automotive, energy, food, marine, military, mining, motorcycle, powersports, steel and textiles industries. The Bel-Ray Acquisition was financed by using a portion of the net proceeds of $337.4 million from the Company’s November 2013 private placement of 7 5/8% senior notes due January 15, 2022. The Company believes the Bel-Ray Acquisition increases its sales in the specialty lubricants market, expands its geographic reach and increases its asset diversity. At closing, the Company repaid the $11.9 million of debt assumed in connection with the Bel-Ray 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. The Company believes this acquisition expands its growing portfolio of crude oil logistics assets, while positioning the Company to purchase increased volumes of price-advantaged feedstock directly from the producers that operate in some of the major shale oil plays encompassing the Company’s refineries.
	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. The refinery has total crude oil throughput capacity of 17,500 bpd and primarily produces diesel, jet fuel, gasoline, 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.
	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 Refining”) and an insignificant affiliated company for aggregate consideration of approximately $191.6 million, net of cash acquired (“Montana Acquisition”). Montana Refining 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. Immediately after closing the Montana Acquisition, the Company converted Montana Refining 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 year ended December 31, 2013 and was offset by the derecognition of a deferred tax liability for a comparable amount assumed in connection with the 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 $262.5 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.
	On January 6, 2012, the Company completed the acquisition of all of the outstanding membership interests of TruSouth Oil, LLC, renamed Calumet Packaging, LLC in 2013 (“Calumet Packaging”), 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, Calumet Packaging 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.
	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.
	Purchase Price Allocation
	The Bel-Ray 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 assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. The assets and results of the operations from such assets acquired as a result of the Superior, Montana, San Antonio and Crude Oil Logistics Acquisitions have been included in the fuel products segments since the date of acquisition, September 30, 2011, October 1, 2012, January 2, 2013 and August 9, 2013, respectively. The assets and results of operations from such assets acquired as a result of the Missouri, Calumet Packaging, Royal Purple and Bel-Ray Acquisitions have been included in the specialty products segment since the date of acquisition, January 3, 2012, January 6, 2012, July 3, 2012 and December 10, 2013, respectively.
	The allocations of the aggregate purchase prices to assets acquired and liabilities assumed for acquisitions are as follows (in millions):


		2013 Acquisitions											2012 Acquisitions
		Bel-Ray				Crude Oil Logistics				San Antonio			Montana			Royal Purple				Calumet Packaging				Missouri
	Accounts receivable	$	4.3			$	—			$	—		$	29		$	15.2			$	5.2			$	—

	Inventories	11.1				—				17			43.7			19.3				8				2.7

	Prepaid expenses and other current assets	0.6				0.1				—			23.1			0.2				0.3				—

	Deposits	—				—				—			0.3			—				—				—

	Property, plant and equipment	6.5				0.9				100.7			125.4			10.6				17.7				10

	Goodwill	9.1				5.2				5.7			27.6			109.2				0.4				1.5

	Other intangible assets	41.4				—				—			—			183.4				2.6				5.4

	Other noncurrent assets, net	0.3				—				—			0.3			—				—				—

	Accounts payable	(3.9		)		—				—			(8.4		)	(3.8		)		(2.7		)		—

	Accrued salaries, wages and benefits	(1.3		)		—				(0.1		)	(1.4		)	(1.7		)		(0.2		)		—

	Deferred income tax liability	—				—				—			(27.6		)	—				—				—

	Accrued income taxes payable	—				—				—			(15.6		)	—				—				—

	Other taxes payable	(1.7		)		—				—			(3.0		)	(0.2		)		—				—

	Other current liabilities	(0.8		)		—				(5.4		)	(0.1		)	(1.0		)		(0.9		)		—

	Current portion of long-term debt	(11.9		)		—				—			—			—				—				—

	Long-term debt	—				—				—			—			—				(3.5		)		—

	Pension and postretirement benefit obligations	—				—				—			(1.7		)	—				—				—

	Other long-term liabilities	(0.1		)		—				—			—			—				—				—

	Total purchase price, net of cash acquired	$	53.6			$	6.2			$	117.9		$	191.6		$	331.2			$	26.9			$	19.6

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


		Bel-Ray						Royal Purple						Calumet Packaging						Missouri
		10-Dec-13						3-Jul-12						6-Jan-12						3-Jan-12
		Amount				Life (Years)		Amount				Life (Years)		Amount			Life (Years)			Amount				Life (Years)
	Customer relationships	$	28.6			30		$	118.7			20		$	1.8		16			$	5.4			20

Trade names	—				Indefinite		14.8				Indefinite		—			Indefinite			—				Indefinite

Trade names	4.2				18		5.7				10		0.7			9			—				—

Trade secrets	8.5				18		44.2				12		—			—			—				—

Non-competition agreements	0.1				3		—				—		0.1			2			—				—

Totals	$	41.4					$	183.4					$	2.6					$	5.4

Weighted average amortization period					26						18					14							20

Goodwill
The Company recorded the following goodwill (in millions):


	Amount				Business Segment
Bel-Ray Acquisition (1)	$	9.1			Specialty Products

Crude Oil Logistics Acquisition (2)	$	5.2			Fuel Products

San Antonio Acquisition (1)	$	5.7			Fuel Products

Montana Acquisition (1)	$	27.6			Fuel Products

Royal Purple Acquisition (1)	$	109.2			Specialty Products

Calumet Packaging Acquisition (1)	$	0.4			Specialty Products

Missouri Acquisition (1)	$	1.5			Specialty Products





-1	Goodwill recognized relates primarily to enhancing the Company’s strategic platform for expansion in the respective business segment noted above.

-2	Goodwill recognized relates primarily to enhancing the Company’s crude oil gathering operations to support the Superior refinery.
Acquisition Expenses
In connection with the respective acquisition, the Company incurred the following expenses, which are reflected in general and administrative expenses in the consolidated statements of operations for the years ended December 31, 2013 and 2012 (in millions):


	Year Ended December 31,
	2013				2012
Bel-Ray Acquisition	$	0.4			$	—

Crude Oil Logistics Acquisition	$	0.2			$	—

San Antonio Acquisition	$	0.5			$	—

Montana Acquisition	$	0.1			$	3.3

Royal Purple Acquisition	$	—			$	0.4

Calumet Packaging Acquisition	$	—			$	0.2

Missouri Acquisition	$	—			$	0.5



Acquisition Sales and Operating Income
The following financial information reflects sales and operating income of the acquisitions of San Antonio and Bel-Ray in 2013, the acquisitions of Missouri, Calumet Packaging, Royal Purple and Montana in 2012 and the acquisition of Superior in 2011 that are included in the consolidated statements of operations (in millions):


	Year Ended December 31,
	2013				2012			2011
Sales	$	480.1			$	266.1		$	341.2

Operating income (loss)	$	(22.5	)		$	18.6		$	18

Unaudited Pro Forma Financial Information
The following unaudited pro forma financial information reflects the 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 per unit data):


	Year Ended December 31,
	2012
Sales	$	5,626.10

Net income	$	189.2

Limited partners’ interest net income per unit — basic	$	2.61

Limited partners’ interest net income per unit — diluted	$	2.6

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.

Investment_in_Unconsolidated_A

Investment in Unconsolidated Affiliate	12 Months Ended
Investment in Unconsolidated Affiliate	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]	'
Investment in Unconsolidated Affiliate	'
	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 a total of $150.0 million from the Company comprised of $75.0 million through contributions and proceeds of $75.0 million from an unsecured syndicated term loan facility with the joint venture as the borrower which is expected be repaid by the Company through its allocation of profits from the joint venture. 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 joint venture will allocate profits on a 50%/50% basis to the Company and MDU. The joint venture is 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 is providing 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 December 31, 2013 and 2012, the Company has an investment of $33.4 million and $1.9 million, respectively, in Dakota Prairie Refining, LLC primarily related to the development of the refinery.

Goodwill_and_Intangible_Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Goodwill and Other Intangible Assets	'
	Goodwill and Other Intangible Assets
	Changes in goodwill balances are as follows (in millions):


		Year Ended December 31,
		2013												2012
		Specialty				Fuel								Specialty				Fuel
		Products				Products				Total				Products				Products		Total
	Beginning balance:	$	159.4			$	27.6			$	187			$	48.3			$	—	$	48.3

	Acquisitions	9.1				10.9				20				111.1				27.6		138.7

	Accumulated impairment losses	—				—				—				—				—		—

	Ending balance:	$	168.5			$	38.5			$	207			$	159.4			$	27.6	$	187

	Other intangible assets consist of the following (in millions):


		Weighted Average Life (Years)		31-Dec-13								31-Dec-12
				Gross Amount				Accumulated Amortization				Gross Amount				Accumulated Amortization
	Customer relationships	22		$	182.9			$	(40.3	)		$	154.3			$	(22.6	)

	Supplier agreements	4		21.5				(21.5		)		21.5				(21.5		)

	Tradenames	Indefinite		14.8				—				14.8				—

	Tradenames	13		10.6				(1.6		)		6.4				(0.6		)

	Trade secrets	13		52.7				(9.6		)		44.2				(3.1		)

	Patents	12		1.6				(1.2		)		1.6				(1.1		)

	Non-competition agreements	5		5.9				(5.8		)		5.8				(5.8		)

	Distributor agreements	3		2				(2.0		)		2				(2.0		)

	Royalty agreements	19		4.5				(1.6		)		4.5				(1.3		)

		18		$	296.5			$	(83.6	)		$	255.1			$	(58.0	)

	Supplier agreements, tradenames (other than indefinite lived), trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements are being amortized to properly match expense with the discounted estimated future cash flows over the terms of the related agreements. Agreements with terms allowing for the potential extension of such agreements are being amortized based on the initial term only. Customer relationships are being amortized using discounted estimated future cash flows based upon assumed rates of annual customer attrition. For the years ended December 31, 2013, 2012 and 2011, the Company recorded amortization expense of intangible assets of $25.6 million, $16.9 million and $7.0 million, respectively.
	The Company estimates that amortization of intangible assets for the next five years will be as follows (in millions):


	Year		Amortization Amount
	2014		$	29.4

	2015		$	26.8

	2016		$	24.4

	2017		$	21.4

	2018		$	18.2

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Operating Leases
	The Company has various operating leases primarily for the use of land, storage tanks, railcars, equipment, precious metals and office facilities that extend through April 2027. Renewal options are available on certain of these leases in which the Company is the lessee. Rent expense for the years ended December 31, 2013, 2012, and 2011 was $35.3 million, $26.9 million and $20.5 million, respectively.
	As of December 31, 2013, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows (in millions):


	Year	Operating
		Leases
	2014	$	30

	2015	26.8

	2016	22.4

	2017	19.6

	2018	16.7

	Thereafter	30.6

	Total	$	146.1

	Crude Oil Supply, Other Feedstocks and Finished Products
	The Company is currently purchasing a majority of its crude oil under month-to-month evergreen contracts or on a spot basis.
	On October 5, 2011, the Company entered into a Crude Oil Purchase Agreement (the “BP Purchase Agreement”) with BP Products North America Inc. (“BP”), pursuant to which BP supplies the Superior refinery with a portion of its daily crude oil requirements, utilizing a market-based pricing mechanism, plus transportation and handling costs. Total crude oil requirements for the Superior refinery are estimated to be between 35,000 and 45,000 bpd. In April 2012, the Company amended and restated the BP Purchase Agreement, which had an initial term of one year ending April 1, 2013, and automatically renews for successive one-year terms unless terminated by either party upon 90 days’ notice prior to the end of any renewal term. To secure a portion of the Company’s payment obligations under the BP Purchase Agreement, the Company and its affiliates have granted a limited interest capped at $100.0 million for physical forwards in the collateral pledged as security under the Collateral Trust Agreement to BP as a “Forward Purchase Secured Hedge Counterparty” under its Collateral Trust Agreement, as such term is defined therein.
	On October 16, 2013, the Company entered into a definitive agreement with TexStar Midstream Logistics, L.P. (“TexStar”) under which TexStar will construct, own and operate a 30,000 bpd crude oil pipeline system that will supply crude oil to the Company’s San Antonio refinery. Under the terms of the 15 year agreement, TexStar has committed to install and operate the Karnes North Pipeline System (“KNPS”), a pipeline that will transport crude oil from Karnes City, Texas to the San Antonio refinery’s Elmendorf, Texas terminal, a key supply hub for the San Antonio refinery. The Company expects to receive deliveries of at least 10,000 bpd of crude oil through the KNPS-Elmendorf terminal supply route once the pipeline comes into service during the fourth quarter of 2014.
	Certain other feedstocks are purchased under long-term supply contracts. The Company also purchases finished products from Houston Refining. The Company is required to purchase at least a minimum volume of 3,100 bpd of naphthenic lubricating oils produced at Houston Refining’s refinery in Houston, Texas, and has a right of first refusal to purchase any additional naphthenic lubricating oils produced at the refinery. In addition, Houston Refining is required to process a minimum of approximately 800 bpd of white mineral oil for the Company at Houston Refining’s Houston, Texas refinery. The annual purchase commitment under these agreements is approximately $140.7 million.
	As of December 31, 2013, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows (in millions):


	Year	Commitment
	2014	$	867

	2015	3.1

	2016	0.8

	2017	0.3

	2018	—

	Thereafter	—

	Total	$	871.2

	In connection with the Company’s acquisition of Penreco on January 3, 2008, the Company entered into a feedstock purchase agreement with Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, Phillips 66 is obligated to supply a minimum quantity (the “Base Volume”) of feedstock for the LVT unit for a term of ten years. Based upon this minimum supply quantity, the Company is obligated to purchase approximately $77.0 million of feedstock for the LVT unit in each fiscal year of the term of the contract, expiring January 1, 2018, based on pricing estimates as of December 31, 2013. This amount is not included in the table above.
	Labor Matters
	The Company has approximately 570 employees covered by various collective bargaining agreements, or approximately 40.7% of its total workforce of approximately 1,400 employees. These agreements have expiration dates of April 30, 2014, October 31, 2014, January 31, 2015, March 31, 2016, April 30, 2016 and June 30, 2017. The Company has approximately 80 employees, or approximately 5.7% of its total workforce, covered by collective bargaining agreements that expire in less than one year and does not expect any work stoppages.
	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.
	Insurance Recoveries
	During the second quarter of 2011, the Company reached a final settlement of its insurance claim related to the failure of an environmental operating unit at its Shreveport refinery in 2010, resulting in a gain (insurance recoveries) of $8.7 million recorded for the year ended December 31, 2011 in the consolidated statements of operations and used the proceeds to repair the failed unit and for working capital needs. This claim related to both property damage and business interruption. Recoveries of $1.9 million related to property damage have been reflected within investing activities (with the remainder in operating activities) in the consolidated statements of cash flows.
	Environmental
	The Company operates crude oil and specialty hydrocarbon refining and terminal operations, which are subject to stringent 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 (see Note 3), the Company agreed to indemnify NuStar for an unlimited term and without consideration of a monetary cap 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. The indemnification is unlimited in duration and not subject to any monetary deductibles or maximums. 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 certain contamination at the San Antonio refinery that pre-dates the Company’s acquiring of the facility. 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 this pre-existing contamination at the San Antonio refinery.
	Montana Refinery
	In connection with the Montana Acquisition from Connacher (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 HollyFrontier 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., subject to a 5-year time limit following closing and certain monetary baskets and cap, 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. To date, Holly has reimbursed the Company for eligible remediation costs.
	Superior Refinery
In connection with the Superior acquisition, the Company became a party to an existing Refinery Initiative consent decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to its 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 refinery to the EPA and the WDNR. The Company currently estimates costs of approximately $1.0 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 material. In addition, the Company may have to pursue certain additional environmental and safety-related projects at the Superior refinery. Completion of these additional projects will result in the Company incurring additional costs, which could be substantial. During 2013 and 2012, the Company incurred approximately $1.9 million and $2.4 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 operation 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 otherwise 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 are 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 that arose 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 2013 and 2012, the Company incurred approximately $4.9 million and $4.2 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 two years as a result of the implementation of these requirements. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the Global Settlement to have a material adverse effect on the Company’s financial results or operations.
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 November 7, 2013, the EPA issued a Consent Agreement and Final Order to the Shreveport refinery, which included a 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 for an unlimited term and without consideration of a monetary cap for the benefit of the assignors. The Company, Chevron, Legacy and the plaintiffs are participating in mediation in an attempt to settle the litigation. The Company believes any obligation will be covered under the indemnification.
Bel-Ray Facility
Bel-Ray executed an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection, effective January 4, 1994, which required investigation and remediation of contamination at or emanating from the Bel-Ray facility. In 2000, Bel-Ray entered into a fixed price remediation contract with Weston Solutions (“Weston”) (a large remediation contractor) whereby Weston agreed to be fully liable for the remediation of the soil and groundwater issues at the facility, including an offsite groundwater plume pursuant to the ACO (“Weston Agreement”). The Weston Agreement set up a trust fund to reimburse Weston, administered by Bel-Ray’s environmental counsel. As of December 31, 2013, the trust fund contained approximately $0.7 million. In addition, there is remediation cost containment insurance, should Weston be unable to complete the work required under the Weston Agreement. In connection with the Bel-Ray Acquisition, the Company became a party to the Weston Agreement.
Weston has been addressing the environmental issues at the Bel-Ray facility over time, and the next phase will address the groundwater issues, which extend offsite.
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 and has implemented 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 years ended December 31, 2013 and 2012, the Company incurred approximately $3.2 million and $0.7 million, respectively, of related capital expenditures and expects to incur up to $1.0 million of capital expenditures during 2014 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.
Beginning in February 2010, OSHA conducted an inspection of the Shreveport refinery’s process safety management program under OSHA’s National Emphasis Program. On August 19, 2010, OSHA issued a Citation and Notification of Penalty to the Company as a result of the Shreveport inspection, which included a civil penalty amount of $0.1 million that was paid in January 2011. In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program under this OSHA initiative. 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 have reached a tentative settlement with OSHA on the matter, which the Company does not believe will have a material adverse effect on its results of operations or financial condition.
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 December 31, 2013 and December 31, 2012, the Company had outstanding standby letters of credit of $95.2 million and $222.4 million, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 7 for additional information regarding the Company’s revolving credit facility. The maximum amount of letters of credit the Company could issue at December 31, 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 December 31, 2013 and December 31, 2012).
As of December 31, 2013 and December 31, 2012, the Company had availability to issue letters of credit of $472.4 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.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	Long-term debt consisted of the following (in millions):


		December 31,			December 31,
		2013			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 9.9% for the years ended December 31, 2013 and 2012	500			600

	Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the years ended December 31, 2013 and 2012	275			275

	Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 7.9% for the year ended December 31, 2013	350			—

	Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	4.8			5.5

	Less unamortized discounts	(19.0		)	(17.0		)
	Total long-term debt	1,110.80			863.5

	Less current portion of long-term debt	0.4			0.8

		$	1,110.40		$	862.7

	7 5/8% Senior Notes
	On November 26, 2013, the Company issued and sold $350.0 million in aggregate principal amount of 7 5/8% of senior notes due January 15, 2022 (the “2022 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 98.494 percent of par. The 2022 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S under the Securities Act. The Company received net proceeds of $337.4 million, net of discount, underwriters’ fees and expenses, which the Company used for general partnership purposes, to fund previously announced organic growth projects, to fund the purchase price of the Bel-Ray Acquisition and the redemption of $100.0 million in aggregate principal amount outstanding of 2019 Notes (defined below). Refer to Note 3 for additional information regarding the Bel-Ray Acquisition.
	Interest on the 2022 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2014. The 2022 Notes will mature on January 15, 2022, unless redeemed prior to maturity. The 2022 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. (“Calumet Finance”) (100%-owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2022 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 2022 Notes. Since all Company’s operating subsidiaries, with the exception of Calumet Finance and three immaterial subsidiaries, guarantee the 2022 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.
	At any time prior to January 15, 2017, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.625% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2022 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 180 days of the date of the closing of such public or private equity offering.
	On and after January 15, 2018, the Company may on any one or more occasions redeem all or a part of the 2022 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2022 Notes, if redeemed during the twelve-month period beginning on January 15 of the years indicated below:


	Year		Percentage
	2018		103.813	%
	2019		101.906	%
	2020 and thereafter		100	%
	Prior to January 15, 2018, the Company may on any one or more occasions redeem all or part of the 2022 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2022 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
	The indenture governing the 2022 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 subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2022 Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default, each as defined in the indenture governing the 2022 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 2022 Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2022 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 November 26, 2013, in connection with the issuance and sale of the 2022 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2022 Notes obligating the Company to use reasonable best efforts to file an exchange offer registration statement with the SEC, so that holders of the 2022 Notes can offer to exchange the 2022 Notes for registered notes having substantially the same terms as the 2022 Notes and evidencing the same indebtedness as the 2022 Notes. On November 27, 2013, the Company filed an exchange offer registration statement for the 2022 Notes with the SEC, which was declared effective on December 10, 2013. The exchange offer was completed on January 13, 2014, thereby fulfilling all of the requirements of the 2022 Notes registration rights agreement.
	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, 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 U.S. pursuant to Regulation S under the Securities Act. The Company received net proceeds of $262.5 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 (100%-owned Delaware corporation that 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. Since all Company’s operating subsidiaries, with the exception of Calumet Finance and three immaterial subsidiaries, guarantee the 2020 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.
	At any time prior to August 1, 2015, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.625% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2020 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.
	On and after August 1, 2016, the Company may on any one or more occasions redeem all or a part of the 2020 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2020 Notes, if redeemed during the twelve-month period beginning on August 1 of the years indicated below:


	Year		Percentage
	2016		104.813	%
	2017		102.406	%
	2018 and at any time thereafter		100	%
	Prior to August 1, 2016, the Company may on any one or more occasions redeem all or part of the 2020 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2020 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
	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 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.
	In connection with the issuance and sale of the 2020 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2020 Notes obligating the Company to use reasonable best efforts to file an exchange offer registration statement with the SEC so that holders of the 2020 Notes could offer to exchange the 2020 Notes for registered notes having substantially the same terms as the 2020 Notes and evidencing the same indebtedness as the 2020 Notes. On December 4, 2012, the Company filed initially 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 of the Securities Act and to persons outside the U.S. 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) of 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 of the Securities Act and to persons outside the U.S. 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 Annual 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.”
	On November 26, 2013, the Company redeemed approximately $74.0 million and $26.0 million in aggregate principal amount outstanding of the 2019 issued in April 2011 and 2019 Notes issued in September 2011, respectively, with the net proceeds from the issuance of the 2022 Notes at a redemption price of $111.2 million. In conjunction with the early redemption, the Company recognized a loss of $14.6 million recorded in debt extinguishment costs on the consolidated statements of operations for the year ended December 31, 2013.
	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 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. Since all Company’s operating subsidiaries, with the exception of Calumet Finance and three immaterial subsidiaries, guarantee the 2019 Notes, condensed consolidating financial statements of non-guarantors are not required in accordance with Rule 3-10 of Regulation S-X.
	At any time prior to May 1, 2014, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net proceeds of a public or private equity offering at a redemption price of 109.375% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2019 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 120 days of the date of the closing of such public or private equity offering.
	On and after May 1, 2015, the Company may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:


	Year		Percentage
2015		104.688	%
2016		102.344	%
2017 and at any time thereafter		100	%
Prior to May 1, 2015, the Company may on any one or more occasions redeem all or part of the 2019 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indentures governing the 2019 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
The indentures governing the 2019 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by 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.
In connection with the issuances and sales of the 2019 Notes, the Company entered into registration rights agreements with the initial purchasers of the 2019 Notes obligating the Company to use reasonable best efforts to file an exchange offer registration statement with the SEC so that holders of the 2019 Notes could offer to exchange the 2019 Notes for registered notes having substantially the same terms as the 2019 Notes and evidencing the same indebtedness as the 2019 Notes. 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.
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 December 31, 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 as follows:


Quarterly Average Availability Percentage		Margin on Base Rate		Margin on LIBOR
		Revolving Loans		Revolving Loans
≥ 66%		1.00%		2.25%
≥ 33% and < 66%		1.25%		2.50%
< 33%		1.50%		2.75%
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% or 0.50% per annum depending on the average daily available unused borrowing capacity for the preceding month. 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 December 31, 2013 under the revolving credit facility was $567.6 million. As of December 31, 2013, the Company had no outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $95.2 million, leaving $472.4 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 December 31, 2013, the Company’s Fixed Charge Coverage Ratio was 2.39 to 1.0.
As of December 31, 2013, the Company was in compliance with all covenants under the revolving credit facility.
Amendments to Master Derivative Contracts
The Company’s payment obligations under all of the Company’s master derivatives contracts for commodity hedging generally are secured by a first priority lien on the Company’s real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). The Company had no additional letters of credit or cash margin posted with any hedging counterparty as of December 31, 2013. The Company issued to one counterparty a $25.0 million standby letter of credit under the revolving credit facility as of December 31, 2012. The Company’s master derivatives contracts and Collateral Trust Agreement (as defined below) continue to impose a number of covenant limitations on the Company’s operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.
Collateral Trust Agreement
The Company has a collateral sharing agreement (the “Collateral Trust Agreement”) with each of its secured hedging counterparties and an administrative agent for the benefit of the secured hedging counterparties, which governs how the secured hedging counterparties will share collateral pledged as security for the payment obligations owed by the Company to the secured hedging counterparties under their respective master derivatives contracts. The Collateral Trust Agreement limits to $100.0 million the extent to which forward purchase contracts for physical commodities would be covered by, and secured under, the Collateral Trust Agreement. There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, the Company has the ability to add secured hedging counterparties from time to time.
Maturities of Long-Term Debt
As of December 31, 2013, maturities of the Company’s long-term debt are as follows (in millions):


Year		Maturity
2014		$	0.4

2015		0.4

2016		0.3

2017		0.4

2018		0.4

Thereafter		1,127.90

Total		$	1,129.80

Capital Lease Obligations
The Company had a capital lease obligation for catalysts used in refining processes which expired in 2013. In connection with the Calumet Packaging Acquisition, the Company recorded $5.8 million of capital leases for a building and equipment that will expire in 2027 and 2018, respectively. Assets recorded under these capital lease obligations are included in property, plant and equipment and total $11.1 million as of December 31, 2013 and 2012. As of December 31, 2013 and 2012, the Company had recorded $5.0 million and $4.3 million, respectively, in accumulated depreciation for these capital lease assets.
As of December 31, 2013, the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows (in millions):


Year		Capital
		Leases
2014		$	0.8

2015		0.7

2016		0.7

2017		0.7

2018		0.7

Thereafter		4.1

Total minimum lease payments		7.7

Less amount representing interest		2.9

Capital lease obligations		4.8

Less obligations due within one year		0.4

Long-term capital lease obligations		$	4.4

Derivatives

Derivatives	12 Months Ended
Derivatives	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivatives	'
	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, collars and options to attempt to reduce the Company’s exposure with respect to:

	•	crude oil purchases and sales;

	•	fuel product sales and purchases;

	•	natural gas purchases; and

	•	fluctuations in the value of crude oil between geographic regions and in 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 9) as either current assets or current liabilities on the 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 consolidated balance sheets as of December 31, 2013 and 2012 (in millions):


		31-Dec-13												December 31, 2012
		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts of Assets Presented in the Consolidated Balance Sheets				Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts of Assets Presented in the Consolidated Balance Sheets

	Derivative instruments designated as hedges:
	Fuel products segment:
	Crude oil swaps	$	45.4			$	(45.4	)		$	—			$	24.9			$	(14.4	)		$	10.5
	Crude oil swaps	$	45.4			$	(45.4	)		$	—			$	24.9			$	(14.4	)		$	10.5
	Gasoline swaps	1				(1.0		)		—				5.2				(4.9		)		0.3
	Gasoline swaps	1				(1.0		)		—				5.2				(4.9		)		0.3
	Diesel swaps	3.5				(3.5		)		—				7				(14.9		)		(7.9		)
	Diesel swaps	3.5				(3.5		)		—				7				(14.9		)		(7.9		)
	Jet fuel swaps	0.1				(0.1		)		—				8				(7.8		)		0.2
	Jet fuel swaps	0.1				(0.1		)		—				8				(7.8		)		0.2
	Total derivative instruments designated as hedges	50				(50.0		)		—				45.1				(42.0		)		3.1
	Total derivative instruments designated as hedges	50				(50.0		)		—				45.1				(42.0		)		3.1
	Derivative instruments not designated as hedges:
	Fuel products segment:
	Crude oil swaps	6.3				(6.3		)		—				0.1				(0.1		)		—
	Crude oil swaps	6.3				(6.3		)		—				0.1				(0.1		)		—
	Crude oil basis swaps	1				(1.0		)		—				0.1				(0.1		)		—
	Crude oil basis swaps	1				(1.0		)		—				0.1				(0.1		)		—
	Gasoline swaps	—				—				—				—				—				—
	Gasoline swaps	—				—				—				—				—				—
	Diesel swaps	0.7				(0.7		)		—				5.1				(5.1		)		—
	Diesel swaps	0.7				(0.7		)		—				5.1				(5.1		)		—
	Jet fuel swaps	0.9				(0.9		)		—				—				—				—
	Jet fuel swaps	0.9				(0.9		)		—				—				—				—
	Diesel crack spread collars	0.3				(0.3		)		—				—				—				—
	Diesel crack spread collars	0.3				(0.3		)		—				—				—				—
	Specialty products segment:
	Crude oil swaps	—				—				—				1.6				(1.6		)		—
	Crude oil swaps	—				—				—				1.6				(1.6		)		—
	Natural gas swaps	0.4				(0.4		)		—				—				—				—
	Natural gas swaps	0.4				(0.4		)		—				—				—				—
	Total derivative instruments not designated as hedges	9.6				(9.6		)		—				6.9				(6.9		)		—
	Total derivative instruments not designated as hedges	9.6				(9.6		)		—				6.9				(6.9		)		—
	Total derivative instruments	$	59.6			$	(59.6	)		$	—			$	52			$	(48.9	)		$	3.1
	Total derivative instruments	$	59.6			$	(59.6	)		$	—			$	52			$	(48.9	)		$	3.1



		31-Dec-13												31-Dec-12
		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts of Liabilities Presented in the Consolidated Balance Sheets				Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts of Liabilities Presented in the Consolidated Balance Sheets

	Derivative instruments designated as hedges:
	Fuel products segment:
	Crude oil swaps	$	(13.0	)		$	45.4			$	32.4			$	(41.1	)		$	14.4			$	(26.7	)
	Crude oil swaps	$	(13.0	)		$	45.4			$	32.4			$	(41.1	)		$	14.4			$	(26.7	)
	Gasoline swaps	(19.7		)		1				(18.7		)		(2.8		)		4.9				2.1
	Gasoline swaps	(19.7		)		1				(18.7		)		(2.8		)		4.9				2.1
Diesel swaps	(51.3		)		3.5				(47.8		)		(25.2		)		14.9				(10.3		)
Diesel swaps	(51.3		)		3.5				(47.8		)		(25.2		)		14.9				(10.3		)
Jet fuel swaps	(13.4		)		0.1				(13.3		)		(10.1		)		7.8				(2.3		)
Jet fuel swaps	(13.4		)		0.1				(13.3		)		(10.1		)		7.8				(2.3		)
Total derivative instruments designated as hedges	(97.4		)		50				(47.4		)		(79.2		)		42				(37.2		)
Total derivative instruments designated as hedges	(97.4		)		50				(47.4		)		(79.2		)		42				(37.2		)
Derivative instruments not designated as hedges:
Fuel products segment:
Crude oil swaps	(1.7		)		6.3				4.6				(10.8		)		0.1				(10.7		)
Crude oil swaps	(1.7		)		6.3				4.6				(10.8		)		0.1				(10.7		)
Crude oil basis swaps	(0.6		)		1				0.4				(3.5		)		0.1				(3.4		)
Crude oil basis swaps	(0.6		)		1				0.4				(3.5		)		0.1				(3.4		)
Gasoline swaps	(9.4		)		—				(9.4		)		(2.2		)		—				(2.2		)
Gasoline swaps	(9.4		)		—				(9.4		)		(2.2		)		—				(2.2		)
Diesel swaps	(3.5		)		0.7				(2.8		)		(1.2		)		5.1				3.9
Diesel swaps	(3.5		)		0.7				(2.8		)		(1.2		)		5.1				3.9
Jet fuel swaps	—				0.9				0.9				—				—				—
Jet fuel swaps	—				0.9				0.9				—				—				—
Diesel crack spread collars	(0.2		)		0.3				0.1				—				—				—
Diesel crack spread collars	(0.2		)		0.3				0.1				—				—				—
Specialty products segment:
Crude oil swaps	—				—				—				—				1.6				1.6
Crude oil swaps	—				—				—				—				1.6				1.6
Natural gas swaps	(1.6		)		0.4				(1.2		)		—				—				—
Natural gas swaps	(1.6		)		0.4				(1.2		)		—				—				—
Total derivative instruments not designated as hedges	(17.0		)		9.6				(7.4		)		(17.7		)		6.9				(10.8		)
Total derivative instruments not designated as hedges	(17.0		)		9.6				(7.4		)		(17.7		)		6.9				(10.8		)
Total derivative instruments	$	(114.4	)		$	59.6			$	(54.8	)		$	(96.9	)		$	48.9			$	(48.0	)
Total derivative instruments	$	(114.4	)		$	59.6			$	(54.8	)		$	(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 consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. 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, crude oil sales 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 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 consolidated balance sheets, until the underlying transaction hedged is recognized in the 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 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 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 consolidated statements of operations for the years ended December 31, 2013 and December 31, 2012 (in millions):


	Year Ended December 31,
	2013				2012
Realized gain on derivative instruments	$	0.2			$	40.1
Realized gain on derivative instruments	$	0.2			$	40.1
Unrealized loss on derivative instruments	$	(3.9	)		$	(2.9	)
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 $1.7 million in realized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2012.
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 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 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 has resulted, 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 consolidated balance sheets, consolidated statements of operations, consolidated statements of other comprehensive income (loss) and its consolidated statements of partners’ capital as of, and for the years ended December 31, 2013 and 2012 related to its derivative instruments that were designated as cash flow hedges (in millions):


	Amount of Gain (Loss)								Amount of Gain (Loss)										Amount of Gain (Loss) Recognized in Net
	Recognized in								Reclassified from										Income on Derivatives
	Accumulated Other								Accumulated Other										(Ineffective Portion)
	Comprehensive								Comprehensive Loss into
	Loss on Derivatives								Net Income (Effective Portion)
	(Effective Portion)
	Year Ended December 31,								Location of		Year Ended December 31,								Location of		Year Ended December 31,
Type of Derivative	2013				2012				(Gain) Loss		2013				2012				Gain (Loss)		2013				2012
Fuel products segment:
Crude oil swaps	$	18.7			$	(100.0	)		Cost of sales		$	3.1			$	49.8			Unrealized/Realized		$	(3.0	)		$	99.7
Crude oil swaps	$	18.7			$	(100.0	)		Cost of sales		$	3.1			$	49.8			Unrealized/Realized		$	(3.0	)		$	99.7
Gasoline swaps	(19.5		)		(16.0		)		Sales		(0.4		)		(38.4		)		Unrealized/Realized		(1.7		)		(52.0		)
Diesel swaps	(28.8		)		(59.3		)		Sales		(4.4		)		(63.0		)		Unrealized/Realized		(5.3		)		(10.5		)
Jet fuel swaps	(7.3		)		(39.8		)		Sales		1.7				(104.4		)		Unrealized/Realized		5.1				(0.1		)
Jet fuel swaps	(7.3		)		(39.8		)		Sales		1.7				(104.4		)		Unrealized/Realized		5.1				(0.1		)
Specialty products segment:
Crude oil swaps	—				—				Cost of sales		0.5				1.9				Unrealized/Realized		—				—
Crude oil swaps	—				—				Cost of sales		0.5				1.9				Unrealized/Realized		—				—
Total	$	(36.9	)		$	(215.1	)				$	0.5			$	(154.1	)				$	(4.9	)		$	37.1
Total	$	(36.9	)		$	(215.1	)				$	0.5			$	(154.1	)				$	(4.9	)		$	37.1
The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2013 and 2012 related to its derivative instruments not designated as cash flow hedges (in millions):


	Amount of Gain (Loss)								Amount of Gain (Loss)
	Recognized in								Recognized in Unrealized Gain
	Realized Gain (Loss) on								(Loss) on Derivatives
	Derivatives								Year Ended December 31,
	Year Ended December 31,
Type of Derivative	2013				2012				2013				2012
Fuel products segment:
Crude oil swaps	$	(6.3	)		$	(30.5	)		$	46.3			$	(40.0	)
Crude oil swaps	$	(6.3	)		$	(30.5	)		$	46.3			$	(40.0	)
Crude oil basis swaps	(7.7		)		2.1				3.8				(3.4		)
Crude oil basis swaps	(7.7		)		2.1				3.8				(3.4		)
Gasoline swaps	3.2				22.1				(9.9		)		0.5
Gasoline swaps	3.2				22.1				(9.9		)		0.5
Diesel swaps	8.1				10.9				(11.7		)		8.9
Diesel swaps	8.1				10.9				(11.7		)		8.9
Jet fuel swaps	0.7				(1.7		)		0.9				—
Jet fuel swaps	0.7				(1.7		)		0.9				—
Diesel crack spread collars	—				—				0.1				—
Diesel crack spread collars	—				—				0.1				—
Specialty products segment:
Crude oil swaps	1.8				—				(1.6		)		1.6
Crude oil swaps	1.8				—				(1.6		)		1.6
Natural gas swaps	(0.6		)		(5.4		)		(1.2		)		3.2
Natural gas swaps	(0.6		)		(5.4		)		(1.2		)		3.2
Interest rate swaps:	—				(0.7		)		—				1
Interest rate swaps:	—				(0.7		)		—				1
Total	$	(0.8	)		$	(3.2	)		$	26.7			$	(28.2	)
Total	$	(0.8	)		$	(3.2	)		$	26.7			$	(28.2	)
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 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 December 31, 2013, the Company had no counterparties in which derivatives held were net assets. 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 December 31, 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 consolidated balance sheets and not netted against derivative assets or liabilities. As of December 31, 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 December 31, 2013 there were no net positions associated with the Company’s outstanding derivative instruments subject to such requirements. As of December 31, 2012, there was a net liability of $7.5 million, associated with the Company’s outstanding derivative instruments subject to such requirements. In addition, the majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.
The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was $51.4 million and $14.0 million as of December 31, 2013 and 2012, respectively. Absent a change in the fair market value of the underlying transactions, the following other comprehensive loss at December 31, 2013 will be reclassified to earnings by December 31, 2016 with balances being recognized as follows (in millions):


Year		Accumulated Other
Year		Comprehensive Loss
2014		$	(26.8	)
2015		(22.3		)
2016		(2.3		)
Total		$	(51.4	)
Based on fair values as of December 31, 2013, the Company expects to reclassify $26.8 million of net losses on derivative instruments from accumulated other comprehensive loss to earnings during the next 12 months due to actual crude oil purchases and gasoline, diesel and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the dates of settlements.
Crude Oil Swap Contracts — Specialty Products Segment
As of December 31, 2013, the Company did not have any crude oil derivatives related to future crude oil purchases in its specialty products segment.
As of 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 is 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 is a net gain of $1.6 million that has been recorded to unrealized loss 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 (loss) on derivative instruments in the consolidated statements of operations.
Natural Gas Swap Contracts
At December 31, 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
First Quarter 2014	750,000			$	4.14
First Quarter 2014	750,000			$	4.14
Second Quarter 2014	750,000			4.14
Second Quarter 2014	750,000			4.14
Third Quarter 2014	750,000			4.14
Third Quarter 2014	750,000			4.14
Fourth Quarter 2014	850,000			4.21
Fourth Quarter 2014	850,000			4.21
Calendar Year 2015	3,500,000			4.27
Calendar Year 2015	3,500,000			4.27
Calendar Year 2016	2,700,000			4.42
Calendar Year 2016	2,700,000			4.42
Calendar Year 2017	1,000,000			4.29
Calendar Year 2017	1,000,000			4.29
Total	10,300,000
Total	10,300,000
Average price				$	4.28
Average price				$	4.28

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 December 31, 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.


Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased			BPD			Average Swap
Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
First Quarter 2014	2,520,000			28,000			$	92.06
First Quarter 2014	2,520,000			28,000			$	92.06
Second Quarter 2014	2,411,500			26,500			91.97
Second Quarter 2014	2,411,500			26,500			91.97
Third Quarter 2014	2,530,000			27,500			91.23
Third Quarter 2014	2,530,000			27,500			91.23
Fourth Quarter 2014	2,024,000			22,000			90.61
Fourth Quarter 2014	2,024,000			22,000			90.61
Calendar Year 2015	5,556,500			15,223			89.08
Calendar Year 2015	5,556,500			15,223			89.08
Calendar Year 2016	1,830,000			5,000			84.73
Calendar Year 2016	1,830,000			5,000			84.73
Total	16,872,000
Total	16,872,000
Average price							$	89.97
Average price							$	89.97
At December 31, 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
Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
First Quarter 2014	810,000			9,000			$	94.56
First Quarter 2014	810,000			9,000			$	94.56
Second Quarter 2014	591,500			6,500			94.37
Second Quarter 2014	591,500			6,500			94.37
Third Quarter 2014	874,000			9,500			92.92
Third Quarter 2014	874,000			9,500			92.92
Fourth Quarter 2014	184,000			2,000			94.62
Fourth Quarter 2014	184,000			2,000			94.62
Calendar Year 2015	1,004,000			2,751			89.28
Calendar Year 2015	1,004,000			2,751			89.28
Total	3,463,500
Total	3,463,500
Average price							$	92.59
Average price							$	92.59
At December 31, 2013, the Company had the following derivatives related to crude oil sales 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
Crude Oil Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2014	45,000			500			$	96.9
First Quarter 2014	45,000			500			$	96.9
Second Quarter 2014	45,500			500			96.9
Second Quarter 2014	45,500			500			96.9
Third Quarter 2014	46,000			500			96.9
Third Quarter 2014	46,000			500			96.9
Fourth Quarter 2014	46,000			500			96.9
Fourth Quarter 2014	46,000			500			96.9
Total	182,500
Total	182,500
Average price							$	96.9
Average price							$	96.9
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			BPD			Average Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased			BPD			($/Bbl)
First Quarter 2013	1,665,000			18,500			$	101.67
First Quarter 2013	1,665,000			18,500			$	101.67
Second Quarter 2013	1,911,000			21,000			100.22
Second Quarter 2013	1,911,000			21,000			100.22
Third Quarter 2013	1,426,000			15,500			95.62
Third Quarter 2013	1,426,000			15,500			95.62
Fourth Quarter 2013	1,104,000			12,000			93.41
Fourth Quarter 2013	1,104,000			12,000			93.41
Calendar Year 2014	5,110,000			14,000			89.47
Calendar Year 2014	5,110,000			14,000			89.47
Calendar Year 2015	4,781,500			13,100			89.49
Calendar Year 2015	4,781,500			13,100			89.49
Total	15,997,500
Total	15,997,500
Average price							$	92.85
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.


Crude Oil Swap Contracts by Expiration Dates	Barrels			BPD			Average Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased			BPD			($/Bbl)
First Quarter 2013	630,000			7,000			$	101.34
First Quarter 2013	630,000			7,000			$	101.34
Second Quarter 2013	455,000			5,000			98.56
Second Quarter 2013	455,000			5,000			98.56
Third Quarter 2013	368,000			4,000			96.58
Third Quarter 2013	368,000			4,000			96.58
Fourth Quarter 2013	368,000			4,000			96.58
Fourth Quarter 2013	368,000			4,000			96.58
Total	1,821,000
Total	1,821,000
Average price							$	98.72
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 crude oil, pricing differentials between LLS and NYMEX WTI and pricing differentials between MSW and NYMEX WTI. At December 31, 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
Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
First Quarter 2014	118,000			1,311			$	(28.50	)
First Quarter 2014	118,000			1,311			$	(28.50	)
Third Quarter 2014	184,000			2,000			(21.75		)
Third Quarter 2014	184,000			2,000			(21.75		)
Fourth Quarter 2014	184,000			2,000			(21.50		)
Fourth Quarter 2014	184,000			2,000			(21.50		)
Total	486,000
Total	486,000
Average differential							$	(23.29	)

As of December 31, 2013, the Company had approximately 248,000 barrels of 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 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 loss of $0.6 million that has been recorded to unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2013. The net impact of these derivative instruments will be realized upon settlement in the first quarter of 2014 and will be recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations.
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
Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
First Quarter 2013	180,000			2,000			$	(23.75	)
First Quarter 2013	180,000			2,000			$	(23.75	)
Second Quarter 2013	364,000			4,000			(27.38		)
Second Quarter 2013	364,000			4,000			(27.38		)
Third Quarter 2013	184,000			2,000			(23.75		)
Third Quarter 2013	184,000			2,000			(23.75		)
Fourth Quarter 2013	184,000			2,000			(23.75		)
Fourth Quarter 2013	184,000			2,000			(23.75		)
Total	912,000
Total	912,000
Average differential							$	(25.20	)

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
Diesel Swap Contracts
At December 31, 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.


Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2014	1,125,000			12,500			$	117.54
First Quarter 2014	1,125,000			12,500			$	117.54
Second Quarter 2014	1,183,000			13,000			116.78
Second Quarter 2014	1,183,000			13,000			116.78
Third Quarter 2014	1,288,000			14,000			116.82
Third Quarter 2014	1,288,000			14,000			116.82
Fourth Quarter 2014	1,288,000			14,000			116.96
Fourth Quarter 2014	1,288,000			14,000			116.96
Calendar Year 2015	4,781,500			13,100			115.81
Calendar Year 2015	4,781,500			13,100			115.81
Calendar Year 2016	1,830,000			5,000			112
Calendar Year 2016	1,830,000			5,000			112
Total	11,495,500
Total	11,495,500
Average price							$	115.72
Average price							$	115.72
At December 31, 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			BPD			Average Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2014	270,000			3,000			$	121.72
First Quarter 2014	270,000			3,000			$	121.72
Second Quarter 2014	182,000			2,000			123.22
Second Quarter 2014	182,000			2,000			123.22
Third Quarter 2014	230,000			2,500			121.74
Third Quarter 2014	230,000			2,500			121.74
Fourth Quarter 2014	184,000			2,000			123.02
Fourth Quarter 2014	184,000			2,000			123.02
Calendar Year 2015	1,004,000			2,751			117.15
Calendar Year 2015	1,004,000			2,751			117.15
Total	1,870,000
Total	1,870,000
Average price							$	119.54
Average price							$	119.54
At December 31, 2013, the Company had the following derivatives related to diesel purchases in its fuel products segment, none of which are designated as cash flow hedges.


Diesel Swap Contracts by Expiration Dates	Barrels Purchased			BPD			Average Swap
Diesel Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
First Quarter 2014	45,000			500			$	121.8
First Quarter 2014	45,000			500			$	121.8
Second Quarter 2014	45,500			500			121.8
Second Quarter 2014	45,500			500			121.8
Third Quarter 2014	46,000			500			121.8
Third Quarter 2014	46,000			500			121.8
Fourth Quarter 2014	46,000			500			121.8
Fourth Quarter 2014	46,000			500			121.8
Total	182,500
Total	182,500
Average price							$	121.8
Average price							$	121.8
At December 31, 2012, the Company had the following derivatives related to diesel sales in its fuel products segment, all of which are designated as cash flow hedges.


Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
Second Quarter 2013	546,000			6,000			$	122.74
Second Quarter 2013	546,000			6,000			$	122.74
Third Quarter 2013	874,000			9,500			122.23
Third Quarter 2013	874,000			9,500			122.23
Fourth Quarter 2013	828,000			9,000			120.82
Fourth Quarter 2013	828,000			9,000			120.82
Calendar Year 2014	3,835,000			10,507			116
Calendar Year 2014	3,835,000			10,507			116
Calendar Year 2015	4,781,500			13,100			115.81
Calendar Year 2015	4,781,500			13,100			115.81
Total	10,864,500
Total	10,864,500
Average price							$	117.13
Average price							$	117.13
At December 31, 2012, 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			BPD			Average Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2013	540,000			6,000			$	130.57
First Quarter 2013	540,000			6,000			$	130.57
Second Quarter 2013	364,000			4,000			126.82
Second Quarter 2013	364,000			4,000			126.82
Third Quarter 2013	276,000			3,000			124.17
Third Quarter 2013	276,000			3,000			124.17
Fourth Quarter 2013	276,000			3,000			124.17
Fourth Quarter 2013	276,000			3,000			124.17
Total	1,456,000
Total	1,456,000
Average price							$	127.2
Average price							$	127.2
Jet Fuel Swap Contracts
At December 31, 2013, the Company had the following derivatives related to jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2014	450,000			5,000			$	117.5
First Quarter 2014	450,000			5,000			$	117.5
Second Quarter 2014	273,000			3,000			116.68
Second Quarter 2014	273,000			3,000			116.68
Third Quarter 2014	276,000			3,000			116.18
Third Quarter 2014	276,000			3,000			116.18
Fourth Quarter 2014	276,000			3,000			115.65
Fourth Quarter 2014	276,000			3,000			115.65
Calendar Year 2015	775,000			2,123			114.05
Calendar Year 2015	775,000			2,123			114.05
Total	2,050,000
Total	2,050,000
Average price							$	115.66
Average price							$	115.66
At December 31, 2013, the Company had the following derivatives to purchase jet fuel in its fuel products segment, none of which are designated as cash flow hedges:


Jet Fuel Swap Contracts by Expiration Dates	Barrels Purchased			BPD			Average Swap ($/Bbl)
First Quarter 2014	90,000			1,000			$	116.71
First Quarter 2014	90,000			1,000			$	116.71
Total	90,000
Total	90,000
Average price							$	116.71
Average price							$	116.71
At December 31, 2012, the Company had the following derivatives related to jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2013	1,035,000			11,500			$	127.39
First Quarter 2013	1,035,000			11,500			$	127.39
Second Quarter 2013	819,000			9,000			129.2
Second Quarter 2013	819,000			9,000			129.2
Third Quarter 2013	368,000			4,000			125.13
Third Quarter 2013	368,000			4,000			125.13
Fourth Quarter 2013	276,000			3,000			122.36
Fourth Quarter 2013	276,000			3,000			122.36
Calendar Year 2014	1,275,000			3,493			116.64
Calendar Year 2014	1,275,000			3,493			116.64
Total	3,773,000
Total	3,773,000
Average price							$	123.56
Average price							$	123.56
Gasoline Swap Contracts
At December 31, 2013, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2014	945,000			10,500			$	104.39
First Quarter 2014	945,000			10,500			$	104.39
Second Quarter 2014	955,500			10,500			109.68
Second Quarter 2014	955,500			10,500			109.68
Third Quarter 2014	966,000			10,500			106.6
Third Quarter 2014	966,000			10,500			106.6
Fourth Quarter 2014	460,000			5,000			104.85
Fourth Quarter 2014	460,000			5,000			104.85
Total	3,326,500
Total	3,326,500
Average price							$	106.61
Average price							$	106.61
At December 31, 2013, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2014	630,000			7,000			$	105.67
First Quarter 2014	630,000			7,000			$	105.67
Second Quarter 2014	409,500			4,500			110.48
Second Quarter 2014	409,500			4,500			110.48
Third Quarter 2014	644,000			7,000			108.24
Third Quarter 2014	644,000			7,000			108.24
Total	1,683,500
Total	1,683,500
Average price							$	107.82
Average price							$	107.82
At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2013	630,000			7,000			$	113.59
First Quarter 2013	630,000			7,000			$	113.59
Second Quarter 2013	546,000			6,000			116.32
Second Quarter 2013	546,000			6,000			116.32
Third Quarter 2013	184,000			2,000			114.73
Third Quarter 2013	184,000			2,000			114.73
Total	1,360,000
Total	1,360,000
Average price							$	114.84
Average price							$	114.84
At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.


Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2013	90,000			1,000			$	105.5
First Quarter 2013	90,000			1,000			$	105.5
Second Quarter 2013	91,000			1,000			105.5
Second Quarter 2013	91,000			1,000			105.5
Third Quarter 2013	92,000			1,000			105.5
Third Quarter 2013	92,000			1,000			105.5
Fourth Quarter 2013	92,000			1,000			105.5
Fourth Quarter 2013	92,000			1,000			105.5
Total	365,000
Total	365,000
Average price							$	105.5
Average price							$	105.5
Diesel Crack Spread Collars
At December 31, 2013, the Company had the following diesel crack spread collars related to diesel sales and crude oil purchases in its fuel products segment, none of which are designated as hedges.


Diesel Crack Spread Collars by Expiration Dates	Barrels Purchased and Sold			BPD			Average Bought				Average Sold
Diesel Crack Spread Collars by Expiration Dates	Barrels Purchased and Sold			BPD			Put ($/Bbl)				Call ($/Bbl)
First Quarter 2014	90,000			1,000			$	26			$	35
First Quarter 2014	90,000			1,000			$	26			$	35
Second Quarter 2014	91,000			1,000			26				35
Second Quarter 2014	91,000			1,000			26				35
Third Quarter 2014	92,000			1,000			26				35
Third Quarter 2014	92,000			1,000			26				35
Fourth Quarter 2014	92,000			1,000			26				35
Fourth Quarter 2014	92,000			1,000			26				35
Total	365,000
Total	365,000
Average price							$	26			$	35
Average price							$	26			$	35

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:

	•	Level 1—inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities

	•	Level 2—inputs include other than quoted prices in active markets that are either directly or indirectly observable

	•	Level 3—inputs include unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions
	In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.
	Recurring Fair Value Measurements
	Derivative Assets and Liabilities
	Derivative instruments are reported in the accompanying consolidated financial statements at fair value. The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least Baa2 and A- by Moody’s and S&P, respectively.
	To estimate the fair values of the Company’s derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and credit worthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. As a result of applying the applicable CVA at December 31, 2013, the net liability of the Company was reduced by approximately $1.9 million. As a result of applying the CVA at December 31, 2012, the Company’s net asset was reduced by approximately $0.1 million and the net liability was reduced by approximately $0.2 million.
	Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 8 for further information on derivative instruments.
	Pension Assets
	Pension assets are reported at fair value in the accompanying consolidated financial statements. At December 31, 2013, the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consist of (i) cash and cash equivalents and (ii) mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the Pension Plan at quarter end as provided by the third party administrator. See Note 12 for further information on pension assets.
	Liability Awards
	Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). The Liability Awards are categorized as Level 1 because the fair value of the Company’s Liability Awards are based on the Company’s quoted closing unit price as of each balance sheet date. See Note 11 for further information on Liability Awards.
	Renewable Identification Numbers Obligation
	The Company’s RINs Obligation represents a liability for the purchase of RINs to satisfy the EPA requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as of the balance sheet date. The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
	Hierarchy of Recurring Fair Value Measurements
	The Company’s recurring assets and liabilities measured at fair value at December 31, 2013 and December 31, 2012 were as follows (in millions):



		31-Dec-13																31-Dec-12
		Level 1				Level 2				Level 3				Total				Level 1			Level 2				Level 3				Total
	Assets:
	Derivative assets:
	Crude oil swaps	$	—			$	—			$	—			$	—			$	—		$	—			$	10.5			$	10.5

	Gasoline swaps	—				—				—				—				—			—				0.3				0.3

	Diesel swaps	—				—				—				—				—			—				(7.9		)		(7.9		)

	Jet fuel swaps	—				—				—				—				—			—				0.2				0.2

	Total derivative assets	—				—				—				—				—			—				3.1				3.1

	Pension plan investments	—				45.8				—				45.8				38.9			2.7				—				41.6

	Total recurring assets at fair value	$	—			$	45.8			$	—			$	45.8			$	38.9		$	2.7			$	3.1			$	44.7

	Liabilities:
	Derivative liabilities:
	Crude oil swaps	$	—			$	—			$	37			$	37			$	—		$	—			$	(35.8	)		$	(35.8	)

	Crude oil basis swaps	—				—				0.4				0.4				—			—				(3.4		)		(3.4		)

	Gasoline swaps	—				—				(28.1		)		(28.1		)		—			—				(0.1		)		(0.1		)

	Diesel swaps	—				—				(50.6		)		(50.6		)		—			—				(6.4		)		(6.4		)

	Jet fuel swaps	—				—				(12.4		)		(12.4		)		—			—				(2.3		)		(2.3		)

	Diesel crack spread collars	—				—				0.1				0.1				—			—				—				—

	Natural gas swaps	—				—				(1.2		)		(1.2		)		—			—				—				—

	Total derivative liabilities	—				—				(54.8		)		(54.8		)		—			—				(48.0		)		(48.0		)

	RINs Obligation	—				(5.3		)		—				(5.3		)		—			(0.8		)		—				(0.8		)

Liability Awards	(3.7		)		—				—				(3.7		)		(2.2		)	—				—				(2.2		)

Total recurring liabilities at fair value	$	(3.7	)		$	(5.3	)		$	(54.8	)		$	(63.8	)		$	(2.2	)	$	(0.8	)		$	(48.0	)		$	(51.0	)
The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the year ended December 31, 2013 and 2012 (in millions):


	Derivative Instruments, Net
	For the Year Ended December 31,
	2013				2012
Fair value at January 1,	$	(44.9	)		$	14.9

Realized (gain) loss on derivative instruments	4.7				(9.5		)

Unrealized gain (loss) on derivative instruments	25.7				(3.8		)

Change in fair value of cash flow hedges	(36.9		)		(215.1		)
Settlements	(3.4		)		168.6

Transfers in (out) of Level 3	—				—

Fair value at December 31,	$	(54.8	)		$	(44.9	)
Total gain (loss) included in net income attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of December 31,	$	25.7			$	(3.8	)

All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives and cost of sales for crude oil derivatives in the consolidated statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments are recorded in earnings in realized gain (loss) on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments in the consolidated statements of operations. See Note 8 for further information on derivative instruments.
Nonrecurring Fair Value Measurements
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. Refer to Note 3 for the fair values of assets acquired and liabilities assumed in connection with the Company’s acquisitions.
The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 5 for further information on goodwill.
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, indefinite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was required to measure and record such assets at fair value within its consolidated financial statements. See Note 2 and Note 5 for further information on long-lived assets.
Estimated Fair Value of Financial Instruments
Cash
The carrying value of cash is considered to be representative of its fair value.
Debt
The estimated fair value of long-term debt at December 31, 2013 and 2012 consists primarily of senior notes. The estimated aggregate fair value of the Company’s senior notes classified as Level 1 were based upon quoted market prices in an active market. The estimated aggregate fair value of the Company’s senior notes classified as Level 2 were based upon directly observable inputs. The carrying value of borrowings, if any, under the Company’s revolving credit facility and capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 7 for further information on long-term debt. The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at December 31, 2013 and December 31, 2012 were as follows (in millions):


			31-Dec-13								31-Dec-12
	Level		Fair Value				Carrying Value				Fair Value				Carrying Value
Financial Instrument:

Senior notes	1		$	863.6			$	761.2			$	658.8			$	587.6

Senior notes	2		$	353.9			$	344.8			$	301.8			$	270.4

Revolving credit facility	3		$	—			$	—			$	—			$	—

Capital lease obligations	3		$	4.8			$	4.8			$	5.5			$	5.5

Partners_Capital

Partners' Capital	12 Months Ended
Partners' Capital	Dec. 31, 2013
Equity [Abstract]	'
Partners' Capital	'
	Partners’ Capital
	Units Outstanding
	Of the 69,317,278 common units outstanding at December 31, 2013, 51,152,727 common units were held by the public, with the remaining 18,164,551 common units held by the Company’s affiliates.
	Significant information regarding rights of the limited partners includes the following:

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

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

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

	•	The Company may issue an unlimited number of limited partner interests without the approval of the limited partners.

	•	Limited partners may be required to sell their units to the general partner if at any time the general partner owns more than 80% of the issued and outstanding common units.
	Distributions and Incentive Distribution Rights
	The Company’s general partner is entitled to incentive distributions if the amount it distributes to unitholders with respect to any quarter exceeds specified target levels shown below:


		Total Quarterly		Marginal Percentage
		Distribution Per Common Unit		Interest in Distributions
		Target Amount		Unitholders			General Partner
	Minimum Quarterly Distribution	$0.45		98	%		2	%
	First Target Distribution	up to $0.495		98	%		2	%
	Second Target Distribution	above $0.495 up to $0.563		85	%		15	%
	Third Target Distribution	above $0.563 up to $0.675		75	%		25	%
	Thereafter	above $0.675		50	%		50	%
	The Company’s ability to make distributions is limited by its debt instruments. The revolving credit facility generally permits the Company to make cash distributions to unitholders as long as immediately after giving effect to such a cash distribution the Company has availability under the revolving credit facility at least equal to the greater of (i) 15% of the lesser of (a) the Borrowing Base (as defined in the revolving credit agreement) without giving effect to the LC Reserve (as defined in the revolving credit agreement) and (b) the revolving credit facility commitments then in effect and (ii) $45.0 million. The indentures governing the 2019 Notes, 2020 Notes and 2022 Notes provide that if the Company’s fixed charge coverage ratio (as defined in the indentures) for the most recently ended four full fiscal quarters is not less than 1.75 to 1.0, the Company will be permitted to pay distributions to its unitholders in an amount equal to available cash from operating surplus (each as defined in the Company’s partnership agreement) with respect to its preceding fiscal quarter, subject to certain customary adjustments described in the indentures. If the Company’s fixed charge coverage ratio is less than 1.75 to 1.0, the Company will be able to pay distributions to its unitholders up to an amount equal to (i) a $70.0 million basket for the 2019 Notes, (ii) a $120.0 million basket for the 2020 Notes and (iii) a $210.0 million basket for the 2022 Notes, subject to certain customary adjustments described in the indentures.
	The Company’s distribution policy is as defined in its partnership agreement. For the years ended December 31, 2013, 2012 and 2011, the Company made distributions of $201.6 million, $132.4 million and $82.7 million, respectively, to its partners. For the years ended December 31, 2013, 2012 and 2011, the general partner was allocated $14.7 million, $5.5 million and $0.2 million, respectively, in incentive distribution rights.
	Subordinated Unit Conversion
	In February 2011, the Company satisfied the last of the earnings and distributions tests contained in its partnership agreement for the automatic conversion of all 13,066,000 outstanding subordinated units into common units on a one-for-one basis. The last of these requirements was met upon payment of the quarterly distribution paid on February 14, 2011. Two days following this quarterly distribution to unitholders, or February 16, 2011, all of the outstanding subordinated units automatically converted to common units.
	Public Offerings of Common Units
	During 2013, 2012 and 2011, the Company completed the following public offerings of its common units (in millions except unit and per unit data):


	Closing Date		Number of Common Units Offered			Price per Unit			Net Proceeds (1)		General Partner Contribution (2)		Underwriting Discount		Use of Proceeds
	February 24, 2011		4,500,000			$	21.45		$	92.3	$	2	$	3.9	Net proceeds were used to repay borrowings under the revolving credit facility.
	February 24, 2011		4,500,000			$	21.45		$	92.3	$	2	$	3.9
	September 8, 2011		11,750,000		-3	$	18		$	202.4	$	4.3	$	8.4	Net proceeds were used to fund a portion of the purchase price of the Superior acquisition and repay borrowings under the revolving credit facility.
	September 8, 2011		11,750,000		-3	$	18		$	202.4	$	4.3	$	8.4
	May 8, 2012		6,000,000			$	25.5		$	146.6	$	3.1	$	6.2	Net proceeds were used to repay borrowings under the revolving credit facility.
	May 8, 2012		6,000,000			$	25.5		$	146.6	$	3.1	$	6.2
	January 8, 2013		5,750,000		-4	$	31.81		$	175.2	$	3.8	$	7.4	Net proceeds were used to repay borrowings under the revolving credit facility and for general partnership purposes.
	January 8, 2013		5,750,000		-4	$	31.81		$	175.2	$	3.8	$	7.4
	April 1, 2013		6,037,500		-5	$	37.5		$	217.3	$	4.6	$	9.1	Net proceeds were used for general partnership purposes.
	April 1, 2013		6,037,500		-5	$	37.5		$	217.3	$	4.6	$	9.1	Net proceeds were used for general partnership purposes.




	-1	Proceeds are net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution.

	-2	The Company’s general partner contributions were made to retain its 2% general partner interest.

	-3	Includes the partial exercise of the overallotment option of 750,000 common units which closed on October 13, 2011.

	-4	Includes the full exercise of the overallotment option of 750,000 common units which closed concurrently with the 5,000,000 firm units on January 8, 2013.

	-5	Includes the full exercise of the overallotment option of 787,500 common units which closed on April 4, 2013.

UnitBased_Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Unit-Based Compensation	'
	Unit-Based Compensation
	The Company’s general partner originally adopted a Long-Term Incentive Plan on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Long-Term Incentive Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Long-Term Incentive Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Long-Term Incentive Plan is administered by the compensation committee of the Company’s general partner’s board of directors.
	Non-employee directors of the Company’s general partner have been granted phantom units under the terms of the Long-Term Incentive Plan as part of their director compensation package related to fiscal years 2011, 2012 and 2013. These phantom units have a four year service period with one-quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
	For the year ended December 31, 2012, named executive officers and certain employees were awarded phantom units under the terms of the Long-Term Incentive Plan, as part of the Company’s achievement of specified levels of financial performance in the fiscal year. These phantom units are subject to time-vesting requirements whereby 25% of the units vest during the performance period, and the remainder will vest ratably over the next three years on each December 31. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
	The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and general and administrative expense in the consolidated statements of operations using the straight-line method over the service period, as it expects these units to fully vest.
	Liability Awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units. Phantom unit Liability Awards are recorded in accrued salaries, wages and benefits in the consolidated balance sheets based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense within general and administrative expense in the consolidated statements of operations.
	A summary of the Company’s nonvested phantom units as of December 31, 2013, and the changes during the years ended December 31, 2013, 2012 and 2011, are presented below:


		Number of		Weighted-Average
		Phantom Units		Grant Date
				Fair Value
	Non-vested at January 1, 2011	105,492		$	17.68

	Granted	640,875		20.26

	Vested	(183,671	)	20.29

	Forfeited	—		—

	Non-vested at December 31, 2011	562,696		$	19.77

	Granted	616,997		26.69

	Vested	(286,976	)	21.16

	Forfeited	(56,790	)	20

	Non-vested at December 31, 2012	835,927		$	27.57

	Granted	483,044		27.73

	Vested	(276,115	)	24.22

	Forfeited	(354,600	)	30.6

	Non-vested at December 31, 2013	688,256		$	23.7

	For the years ended December 31, 2013, 2012 and 2011, compensation expense of $4.8 million, $4.6 million and $3.0 million, respectively, was recognized in the consolidated statements of operations related to vested phantom unit grants, including $1.6 million and $2.2 million, attributable to Liability Awards for the years ended December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012, there was a total of $16.3 million and $23.0 million, respectively of unrecognized compensation costs related to nonvested phantom unit grants, including $12.4 million and $16.1 million, attributable to Liability Awards for the years ended December 31, 2013 and 2012, respectively. These costs are expected to be recognized over a weighted-average period of approximately two years. The total fair value of phantom units vested during the years ended December 31, 2013 and 2012, was $6.7 million and $6.1 million, respectively.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Employee Benefit Plans	'
	Employee Benefit Plans
	Defined Contribution Plan
	The Company has a domestic defined contribution plan administered by its general partner for (i) all full-time employees that are eligible to participate in the plan (“401(k) Plan”). Participants in the 401(k) Plan are allowed to contribute 1% to 70% of their pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% of eligible compensation contributed by the participant up to 4% and 50% of each additional 1% of eligible compensation contributed up to 6%, for a maximum contribution by the Company of 5% of eligible compensation contributed per participant. The plan also includes a profit-sharing component for eligible employees. Contributions under the profit-sharing component are determined by the board of directors of the Company’s general partner and are discretionary. The funding policy is consistent with funding requirements of applicable laws and regulations.
	The Company recorded the following 401(k) Plan matching contribution and profit sharing expenses in the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011 (in millions):


		Year Ended December 31,
		2013				2012				2011
	401(k) Plan matching contribution expense	$	4.1			$	3.2			$	2.3
	401(k) Plan matching contribution expense	$	4.1			$	3.2			$	2.3
	Profit sharing expense	0.9				2.5				1.4
	Profit sharing expense	0.9				2.5				1.4
	Defined Pension Plan
	The Company has domestic noncontributory defined benefit plans for those salaried employees as well as those employees represented by either the United Steelworkers (“USW”) or the International Union of Operating Engineers (“IUOE”); who (i) were formerly employees of Penreco and became employees of the Company as a result of the acquisition of Penreco on January 3, 2008 (“Penreco Pension Plan”), (ii) were formerly employees of Murphy Oil represented by the IUOE and who became employees of the Company as a result of the Superior Acquisition on September 30, 2011 (the “Superior Pension Plan”) or (iii) were formerly employees of Montana Refining and who became employees of the Company as a result of the Montana Acquisition on October 1, 2012 (the “Montana Pension Plan” and together with the Penreco Pension Plan and the Superior Pension Plan, the “Pension Plan”). During 2013, the Company made contributions of $3.4 million to its Pension Plan and expects to make contributions in 2014 of approximately $1.6 million to its Pension Plan.
	Under the Penreco Pension Plan, benefits are based primarily on years of service for USW and IUOE represented employees and the employee’s final 60 months’ average compensation for salaried employees. In 2009, the Company amended the Penreco Pension Plan, which curtailed Penreco employees from accumulating additional benefits subsequent to December 31, 2009.
	Under the Superior Pension Plan, benefits are based primarily on years of service for IUOE represented employees and the employee’s three highest consecutive calendar years within the last 10 years of service. Effective July 1, 2012, the Company amended the Superior Pension Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012. For the year ended December 31, 2012, the Company recorded a $0.2 million curtailment gain.
	Under the Montana Pension Plan, benefits are based primarily on years of service and the employees’ 36 months’ highest average compensation for salaried employees. Effective October 1, 2012, the date of the Montana Acquisition, the Company amended the Montana Pension Plan, which curtailed only the Montana salaried employees from accumulating additional benefits subsequent to October 31, 2012.
	Defined Benefit Other Plans
	The Company also has domestic contributory defined benefit post retirement medical plans and contributory life insurance plans for (i) those salaried employees, as well as those employees represented by either the International Brotherhood of Teamsters (“IBT”), USW or IUOE, who were formerly employees of Penreco and who became employees of the Company as a result of the acquisition of Penreco on January 3, 2008 (“Penreco Other Plan”) or (ii) employees represented by the IUOE, who were formerly employees of Murphy Oil and who became employees of the Company as a result of the Superior acquisition on September 30, 2011 (“Superior Other Plan” and together with the Penreco Other Plan, the “Other Plan”). The funding policy is consistent with funding requirements of applicable laws and regulations.
	Effective 2009, the Company amended the Penreco Other Plan, which curtailed employees from accumulating additional benefits subsequent to February 29, 2009. Effective July 1, 2012, the Company amended the Superior Other Plan, which curtailed Superior employees from accumulating additional benefits subsequent to December 31, 2012. For the year ended December 31, 2012, the Company recorded a $7.0 million curtailment gain.
	All information presented below has been adjusted for these curtailments for the Pension Plan and Other Plan. The change in the benefit obligations, change in the plan assets, funded status and amounts recognized in the consolidated balance sheets were as follows (in millions):


		Year Ended December 31,
		2013								2012
		Pension				Other Plan				Pension				Other Plan
		Plan				Other Plan				Plan				Other Plan
	Change in projected benefit obligation:
	Benefit obligation at beginning of year	$	65.3			$	0.3			$	55.3			$	7.7
	Benefit obligation at beginning of year	$	65.3			$	0.3			$	55.3			$	7.7
	Projected benefit obligation attributable to acquisitions	—				—				4.9				—
	Projected benefit obligation attributable to acquisitions	—				—				4.9				—
	Service cost	0.4				—				1.1				0.3
	Service cost	0.4				—				1.1				0.3
	Interest cost	2.4				—				2.4				0.2
	Interest cost	2.4				—				2.4				0.2
	Plan curtailments	—				—				(3.7		)		(7.9		)
	Plan curtailments	—				—				(3.7		)		(7.9		)
	Benefits paid	(2.3		)		—				(2.6		)		(0.1		)
	Benefits paid	(2.3		)		—				(2.6		)		(0.1		)
	Actuarial (gain) loss	(8.5		)		—				7.9				0.1
	Actuarial (gain) loss	(8.5		)		—				7.9				0.1
	Administrative expense	(0.1		)		—				—				—
	Administrative expense	(0.1		)		—				—				—
	Plan amendments	—				—				—				(0.1		)
	Plan amendments	—				—				—				(0.1		)
	Employee contributions	—				—				—				0.1
	Employee contributions	—				—				—				0.1
	Benefit obligation at end of year	$	57.2			$	0.3			$	65.3			$	0.3
	Benefit obligation at end of year	$	57.2			$	0.3			$	65.3			$	0.3
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	41.6			$	—			$	36			$	—
	Fair value of plan assets at beginning of year	$	41.6			$	—			$	36			$	—
	Fair value of pension assets attributable to acquisitions	—				—				3.2				—
	Fair value of pension assets attributable to acquisitions	—				—				3.2				—
	Benefit payments	(2.3		)		—				(2.6		)		(0.1		)
	Benefit payments	(2.3		)		—				(2.6		)		(0.1		)
	Actual return on assets	3.2				—				1.9				—
	Actual return on assets	3.2				—				1.9				—
	Administrative expense	(0.1		)		—				—				—
	Administrative expense	(0.1		)		—				—				—
	Employee contributions	—				—				—				0.1
	Employee contributions	—				—				—				0.1
Employer contribution	3.4				—				3.1				—
Employer contribution	3.4				—				3.1				—
Fair value of plan assets at end of year	$	45.8			$	—			$	41.6			$	—
Fair value of plan assets at end of year	$	45.8			$	—			$	41.6			$	—
Funded status — benefit obligation in excess of plan assets	$	(11.4	)		$	(0.3	)		$	(23.7	)		$	(0.3	)
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	$	(11.4	)		$	(0.3	)		$	(23.7	)		$	(0.3	)
Prior service credit	—				(0.2		)		—				(0.2		)
Prior service credit	—				(0.2		)		—				(0.2		)
Unrecognized net actuarial (gain) loss	2.3				(0.2		)		11.9				(0.2		)
Unrecognized net actuarial (gain) loss	2.3				(0.2		)		11.9				(0.2		)
Accumulated other comprehensive (income) loss	2.3				(0.4		)		11.9				(0.4		)
Accumulated other comprehensive (income) loss	2.3				(0.4		)		11.9				(0.4		)
Net amount recognized at end of year	$	(9.1	)		$	(0.7	)		$	(11.8	)		$	(0.7	)
The accumulated benefit obligation for the Pension Plan was $56.7 million and $63.4 million as of December 31, 2013 and 2012, respectively. Selected information for the Company’s pension plans with an accumulated benefit obligation in excess of plan assets were as follows (in millions):


	Year Ended December 31,
	2013				2012
Accumulated benefit obligation	$	52.9			$	63.4
Accumulated benefit obligation	$	52.9			$	63.4
Fair value of plan assets	41.8				41.6
Fair value of plan assets	41.8				41.6
Selected information for the Company’s Pension Plan with projected benefit obligation in excess of plan assets were as follows (in millions):


	Year Ended December 31,
	2013				2012
Projected benefit obligation	$	57.2			$	65.3
Projected benefit obligation	$	57.2			$	65.3
Fair value of plan assets	$	45.8			$	41.6
Fair value of plan assets	$	45.8			$	41.6
The components of net periodic pension cost and other post retirement benefits cost (income) for 2013, 2012 and 2011 were as follows (in millions):


	Pension Plan												Other Plan
	Year Ended December 31,												Year Ended December 31,
	2013				2012				2011				2013				2012			2011
Service cost	$	0.4			$	1.1			$	0.3			$	—			$	0.3		$	0.1
Service cost	$	0.4			$	1.1			$	0.3			$	—			$	0.3		$	0.1
Interest cost	2.4				2.4				1.6				—				0.2			0.1
Interest cost	2.4				2.4				1.6				—				0.2			0.1
Expected return on assets	(2.9		)		(1.7		)		(1.2		)		—				—			—
Expected return on assets	(2.9		)		(1.7		)		(1.2		)		—				—			—
Amortization of net loss	0.8				0.6				0.2				—				—			—
Amortization of net loss	0.8				0.6				0.2				—				—			—
Curtailment gain recognized	—				(0.2		)		—				—				(7.0		)	—
Curtailment gain recognized	—				(0.2		)		—				—				(7.0		)	—
Settlement gain recognized	—				—				—				—				(0.2		)	—
Settlement gain recognized	—				—				—				—				(0.2		)	—
Net periodic benefit cost (income)	$	0.7			$	2.2			$	0.9			$	—			$	(6.7	)	$	0.2
Net periodic benefit cost (income)	$	0.7			$	2.2			$	0.9			$	—			$	(6.7	)	$	0.2
The components of changes recognized in other comprehensive (income) loss for the Pension Plan and Other Plan for 2013, 2012 and 2011 were as follows (in millions):


	Pension Plan												Other Plan
	Year Ended December 31,												Year Ended December 31,
	2013				2012				2011				2013				2012			2011
Changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss	$	(8.8	)		$	4.3			$	3.3			$	—			$	0.1		$	0.6
Net (gain) loss	$	(8.8	)		$	4.3			$	3.3			$	—			$	0.1		$	0.6
New prior service cost	—				—				—				—				(0.1		)	—
New prior service cost	—				—				—				—				(0.1		)	—
Amounts recognized as a component of net periodic benefit cost:

Amortization or settlement recognition of net loss	(0.8		)		(0.6		)		(0.2		)		—				(0.8		)	—
Amortization or settlement recognition of net loss	(0.8		)		(0.6		)		(0.2		)		—				(0.8		)	—
Amortization or curtailment recognition of prior service credit	—				—				—				—				0.1			—
	—				—				—				—				0.1			—
Total recognized in other comprehensive (income) loss	$	(9.6	)		$	3.7			$	3.1			$	—			$	(0.7	)	$	0.6
Total recognized in other comprehensive (income) loss	$	(9.6	)		$	3.7			$	3.1			$	—			$	(0.7	)	$	0.6
The portion relating to the Pension Plan and Other Plan classified in accumulated other comprehensive loss is $1.9 million and $11.5 million as of December 31, 2013 and 2012, respectively. In 2014, the estimated amount that will be amortized from accumulated other comprehensive loss includes a net loss of $0.3 million for the Pension Plan.
All pension and other post retirement plans have a December 31 measurement date. The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2013 and 2012 were as follows:


	Benefit Obligations
	Assumptions
	2013			2012
Pension Plan:
Discount rate for Penreco Pension Plan	4.78	%		3.86	%
Discount rate for Superior Pension Plan	4.66	%		3.75	%
Discount rate for Montana Pension Plan	4.97	%		4.03	%
Rate of compensation increase for Montana Pension Plan	3	%		3	%
Other Plan:
Discount rate for Penreco Other Plan	4.29	%		3.33	%
Immediate trend rate for Penreco Other Plan (1)	7.5	%		7.7	%
Ultimate trend rate for Penreco Other Plan (1)	4.5	%		4.5	%
Year that the rate reaches ultimate trend rate for Penreco Other Plan (1)	2029			2029
	2029			2029




-1	For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% in 2029 for the Penreco Other Plan and remain at that level thereafter.
The significant weighted average assumptions used to determine the net periodic benefit cost (income) for the years ended December 31, 2013 and 2012 were as follows:


	Net Periodic Benefit Cost (Income)
	Assumptions
	2013			2012			2011
Pension Plan:
Discount rate for Penreco Pension Plan	3.86	%		4.63	%		5.5	%
Discount rate for Superior Pension Plan	3.75	%		4.55	%		4.71	%
Discount rate for Montana Pension Plan	4.03	%		3.89	%		N/A
Discount rate for Montana Pension Plan	4.03	%		3.89	%		N/A
Expected return on plan assets for Penreco Pension Plan (1)	6.75	%		6	%		6.5	%
Expected return on plan assets for Superior Pension Plan (1)	6.75	%		3	%		6.5	%
Expected return on plan assets for Montana Pension Plan (1)	6.75	%		6	%		N/A
Expected return on plan assets for Montana Pension Plan (1)	6.75	%		6	%		N/A
Rate of compensation increase for Superior Pension Plan	N/A			3.75	%		3.75	%
Rate of compensation increase for Superior Pension Plan	N/A			3.75	%		3.75	%
Rate of compensation increase for Montana Pension Plan	3	%		3	%		N/A
Rate of compensation increase for Montana Pension Plan	3	%		3	%		N/A
Other Plan:
Discount rate for Penreco Other Plan	3.33	%		4.04	%		4.54	%
Discount rate for Superior Other Plan	N/A			4.65	%		4.82	%
Discount rate for Superior Other Plan	N/A			4.65	%		4.82	%
Immediate trend rate (2)	7.7	%		8	%		8.2	%
Ultimate trend rate for Penreco Other Plan (2)	4.5	%		4.5	%		4.5	%
Ultimate trend rate for Superior Other Plan (2)	N/A			4.5	%		5	%
Ultimate trend rate for Superior Other Plan (2)	N/A			4.5	%		5	%
Year that the rate reaches ultimate trend rate for Penreco Other Plan (2)	2029			2029			2029
	2029			2029			2029
Year that the rate reaches ultimate trend rate for Superior Other Plan (2)	N/A			2029			2020
	N/A			2029			2020




-1	The Company considered the historical returns and the future expectation for returns for each asset class, as well as the target asset allocation of the Pension Plan portfolio which was developed in accordance with the Company’s Statement of Investment Policy, to develop the expected long-term rate of return on plan assets.

-2	For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% for 2029 for the Penreco Other Plan and remain at that level thereafter.
An increase or decrease by one percentage point in the assumed healthcare cost trend rates would have less than $0.1 million effect on the post retirement benefit obligation and service and interest cost components of benefit costs for the Other Plan as of December 31, 2013.
Investment Policy
The Defined Benefit Plan Investment Committee (the “Committee”) is responsible for the overall management of the Pension Plan assets, whose responsibilities encompass establishing the investment strategies and policies, monitoring the management of plan assets, reviewing the asset allocation mix on a regular basis, monitoring the performance of the Pension Plan assets to determine whether the investments objectives are met and guidelines followed and taking the appropriate action if objectives are not followed. The Company uses different investment managers with various asset management objectives to eliminate any significant concentration of risk. The Committee believes there are no significant concentrations of risks associated with the investment assets. The Company’s investment manager will assist in the continual assessment of assets and the potential reallocation of certain investments and will evaluate the selection of investment managers for the Pension Plan assets based on such factors as organizational stability, depth of resources, experience, investment strategy and process, performance expectations and fees.
Long-term strategic investment objectives utilize a diversified mix of equity and fixed income securities to preserve the funded status of the trusts, and balance risk and return in relationship to the respective liabilities. The primary investment strategy currently employed is a dynamic de-risking strategy that periodically rebalances among various investment categories depending on the current funded position and maximizes the effectiveness of the Pension Plan asset allocation strategy. This program is designed to actively move from return-seeking investments (such as equities) toward liability-hedging investments (such as fixed income) as funding levels improve.
Effective June 2013, all of the Pension Plan assets were invested in a Master Trust. Trust assets in the Pension Plan are invested subject to the policy restriction that the average quality of the fixed income portfolio must be rated at least investment grade by both Moody’s and S&P. These assets are invested in accordance with prudent expert standards as mandated by the Employee Retirement Income Security Act (“ERISA”). The Pension Plan’s target asset allocation is currently comprised of the following:


Asset Class	Range of		Target
Asset Class	Asset Allocation		Allocation
Domestic equities	0 — 50%		25	%
Foreign equities	0 — 50%		25	%
Fixed income	50 — 100%		50	%
Investment Fund Strategies
Domestic equities funds include funds that invest in U.S. common and preferred stocks. Foreign equity funds invest in securities issued by companies listed on international stock exchanges. Certain funds have value and growth objectives and managers may attempt to profit from security mispricing in equity markets to meet these objectives. Short term investments (including commercial paper, certificates of deposits and government repurchase agreements) and derivatives may be used for hedging purposes to limit exposure to various risk factors.
Fixed income funds invest in U.S. dollar-denominated, investment grade bonds, including U.S. Treasury and government agency securities, corporate bonds and mortgage and asset-backed securities. These funds may also invest in any combination of non-investment grade bonds, non-U.S. dollar denominated bonds and bonds issued by issuers in emerging capital markets. Short-term investments (including commercial paper, certificates of deposits and government repurchase agreements) and derivatives may be used for hedging purposes to limit exposure to various risk factors.
The Company’s Pension Plan asset allocations, as of December 31, 2013 and 2012 by asset category, are as follows:


	2013			2012
Cash and cash equivalents (1)	—	%		46	%
Domestic equities	23	%		14	%
Foreign equities	23	%		6	%
Fixed income	54	%		20	%
Commingled fund	—	%		7	%
Balanced fund	—	%		7	%
	100	%		100	%




-1	The Superior Pension Plan assets were included in cash and cash equivalents in 2012 and such assets were invested in 2013 based upon the current investment policy.
At December 31, 2013, the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consist of (i) cash and cash equivalents and (ii) mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the Pension Plan at quarter end as provided by the third party administrator. See Note 9 for the definition of Levels 1, 2 and 3. The Company’s Pension Plan assets measured at fair value at December 31, 2013 and 2012 were as follows (in millions):


	Fair Value of Pension Assets at December 31,
	2013								2012
	Level 1				Level 2				Level 1				Level 2
Cash and cash equivalents	$	—			$	—			$	19.3			$	—
Cash and cash equivalents	$	—			$	—			$	19.3			$	—
Domestic equities	—				10.6				5.9				—
Domestic equities	—				10.6				5.9				—
Foreign equities	—				10.6				2.3				—
Foreign equities	—				10.6				2.3				—
Fixed income	—				24.6				8.4				—
Fixed income	—				24.6				8.4				—
Commingled fund	—				—				—				2.7
Commingled fund	—				—				—				2.7
Balanced fund	—				—				3				—
Balanced fund	—				—				3				—
	$	—			$	45.8			$	38.9			$	2.7
	$	—			$	45.8			$	38.9			$	2.7
The following benefit payments for the Pension Plans, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2013 (in millions):


	Pension
	Benefits
2014	$	2.5
2014	$	2.5
2015	2.6
2015	2.6
2016	2.7
2016	2.7
2017	2.8
2017	2.8
2018	3
2018	3
2019 to 2023	17.1
2019 to 2023	17.1
Total	$	30.7
Total	$	30.7

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
Accumulated Other Comprehensive Income (Loss)	Dec. 31, 2013
Equity [Abstract]	'
Comprehensive Income (Loss) Note	'
	Accumulated Other Comprehensive Loss
	The table below sets forth a summary of changes in accumulated other comprehensive loss by component for the year ended December 31, 2013 (in millions):


		Derivatives				Defined Benefit Pension And Retiree Health Benefit Plans			Foreign Currency Translation Adjustment			Total
	Accumulated other comprehensive loss at December 31, 2012	$	(14.0	)		$	(11.5	)	$	—		$	(25.5	)
	Accumulated other comprehensive loss at December 31, 2012	$	(14.0	)		$	(11.5	)	$	—		$	(25.5	)
	Other comprehensive income (loss) before reclassifications	(36.9		)		8.8			(0.1		)	(28.2		)
	Other comprehensive income (loss) before reclassifications	(36.9		)		8.8			(0.1		)	(28.2		)
	Amounts reclassified from accumulated other comprehensive loss	(0.5		)		0.8			—			0.3
		(0.5		)		0.8			—			0.3
	Net current period other comprehensive income (loss)	(37.4		)		9.6			(0.1		)	(27.9		)
	Net current period other comprehensive income (loss)	(37.4		)		9.6			(0.1		)	(27.9		)
	Accumulated other comprehensive loss at December 31, 2013	$	(51.4	)		$	(1.9	)	$	(0.1	)	$	(53.4	)
	The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive loss in the Company’s consolidated statements of operations for the year ended December 31, 2013 (in millions):


	Components of Accumulated Other Comprehensive Loss		Amount Reclassified From Accumulated Other Comprehensive Loss				Location of Gain (Loss)
	Components of Accumulated Other Comprehensive Loss						Location of Gain (Loss)
	Derivative gains (losses) reflected in gross profit
			$	(3.1	)		Sales
			3.6				Cost of sales
			3.6				Cost of sales
			$	0.5			Total
			$	0.5			Total

	Amortization of defined benefit pension benefit plans:
	Amortization of net loss		$	(0.8	)		-1
			$	(0.8	)		Total
	________________________

	-1	This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 12 for additional information.

Earnings_Per_Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2013
Earnings Per Unit [Abstract]	'
Earnings Per Share [Text Block]	'
	Earnings per Unit
	The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended December 31, 2013, 2012 and 2011 (in millions, except unit and per unit data):


		Year Ended December 31,
		2013			2012		2011

	Numerator for basic and diluted earnings per limited partner unit:
	Net income	$	3.5		$	205.7	$	43

	Less:
	General partner’s interest in net income	0.1			4.1		0.9

	General partner’s incentive distribution rights	14.7			5.5		0.2

	Nonvested share based payments	0.2			1.1		—

	Net income (loss) available to limited partners	$	(11.5	)	$	195	$	41.9

	Denominator for basic and diluted earnings per limited partner unit:
	Basic weighted average limited partner units outstanding	67,938,784			55,559,183		42,598,876

	Effect of dilutive securities:

	Participating securities — phantom units	—			117,558		45,210

	Diluted weighted average limited partner units outstanding (1)	67,938,784			55,676,741		42,644,086

	Limited partners’ interest basic net income (loss) per unit	$	(0.17	)	$	3.51	$	0.98

	Limited partners’ interest diluted net income (loss) per unit	$	(0.17	)	$	3.5	$	0.98

	_____________
	(1) Total diluted weighted average limited partner units outstanding excludes 0.2 million potentially dilutive phantom units for the year ended December 31, 2013.

Transactions_with_Related_Part

Transactions with Related Parties	12 Months Ended
Transactions with Related Parties	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Transactions with Related Parties	'
	Transactions with Related Parties
	During the years ended December 31, 2013, 2012 and 2011, the Company had product sales to related parties owned by a limited partner of $9.7 million, $9.3 million and $16.5 million, respectively. Trade accounts and other receivables from related parties at December 31, 2013 and 2012 were $0.2 million and $0.1 million, respectively. The Company also had purchases from related parties owned by a limited partner, excluding crude purchases related to the Legacy Resources Co., L.P. (“Legacy Resources”) and director’s and officers’ liability insurance premiums discussed below, during the years ended December 31, 2013, 2012 and 2011 of $9.0 million, $7.2 million and $1.8 million, respectively. Accounts payable to related parties, excluding accounts payable related to the Legacy Resources agreements discussed below, at December 31, 2013 and 2012 were $4.3 million and $2.2 million, respectively.
	Legacy Resources is owned in part by one of the Company’s limited partners, an affiliate of the Company’s general partner, the Company’s chief executive officer and vice chairman of the board of the Company’s general partner, F. William Grube, and the Company’s president and chief operating officer, Jennifer G. Straumins.
	From May 2008 to May 2011, the Company purchased all of its crude oil requirements for its Princeton refinery on a just in time basis utilizing a market-based pricing mechanism from Legacy Resources (the “Legacy Princeton Agreement”). In addition, in January 2009, the Company entered into an agreement with Legacy Resources to begin purchasing certain of its crude oil requirements for its Shreveport refinery utilizing a market-based pricing mechanism from Legacy Resources (the “Master Crude Oil Purchase and Sale Agreement”). In September 2009, the Company entered into a crude oil supply agreement with Legacy Resources (the “Legacy Shreveport Agreement”). Under the Legacy Shreveport Agreement, Legacy Resources supplied the Company’s Shreveport refinery with a portion of its crude oil requirements on a just in time basis utilizing a market-based pricing mechanism.
	On May 31, 2011, the Company terminated the Legacy Princeton Agreement and the Legacy Shreveport Agreement and did not incur any material early termination penalties in connection with their termination. With the termination of these agreements, the Company has one remaining crude oil supply agreement with Legacy Resources, the Master Crude Oil Purchase and Sale Agreement. No crude oil is currently being purchased by the Company under this agreement. During the years ended December 31, 2013 and 2012 and 2011, the Company had crude oil purchases of $1.2 million, $1.1 million and $229.8 million, respectively, from Legacy Resources. Accounts payable to Legacy Resources at December 31, 2013 and 2012 were $0.1 million and $0.1 million, respectively.
	Nicholas J. Rutigliano, a member of the board of directors of the Company’s general partner, founded Tobias Insurance Group, Inc. (“Tobias”), a commercial insurance brokerage business, which was acquired by Assured Partners, LLC. Mr. Rutigliano continues to serve as president of Tobias. Tobias has historically placed the Company’s directors’ and officers’ liability insurance. The total premiums paid to Tobias by the Company for the years ended December 31, 2013, 2012 and 2011 were $0.7 million, $0.5 million and $0.6 million, respectively. With the exception of its directors’ and officers’ liability insurance which were placed with this commercial insurance brokerage company, the Company placed its insurance requirements with third parties during the years ended December 31, 2013, 2012 and 2011.

Segments_and_Related_Informati

Segments and Related Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segments and Related Information	'
	Segments and Related Information
	a. Segment Reporting
	The Company manages its business in multiple operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments:

	•	Specialty Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants and other products which are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. Specialty products also include synthetic lubricants used in manufacturing, mining and automotive applications.

	•	Fuel Products. The Fuel Products segment produces primarily gasoline, diesel fuel, jet fuel and asphalt which are primarily sold to customers located in PADD 2, PADD 3 and PADD 4 areas within the U.S.
	During the fourth quarter 2013, the Company realigned its reportable segments for financial reporting purposes as a result of significant growth in the Company. The change primarily represents reporting the operating results of asphalt produced at the Shreveport, Superior and Montana refineries within the fuel products segment. Prior to this change, asphalt was reported as part of the specialty products segment. While this reporting change did not impact the Company’s consolidated results, segment data for previous years has been restated and is consistent with the current year presentation throughout the financial statements and the accompanying notes.
	The accounting policies of the reporting segments are the same as those described in Note 2, except that the disaggregated financial results for the reporting segments have been prepared using a management approach, which is consistent with the basis and manner in which management internally disaggregates financial information for the purposes of assisting internal operating decisions. The Company evaluates performance based upon Adjusted EBITDA. The Company defines Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.
	Through September 30, 2013, the Company’s management believed that income from operations was a meaningful measure of performance and it was used by management to analyze the Company and stand-alone operating segment performance. During the fourth quarter 2013, the Company’s management determined that Adjusted EBITDA is the key performance measure for planning and forecasting purposes and discontinued the use of income from operations as a measure of performance. Segment Adjusted EBITDA should not be considered a substitute for results prepared in accordance with U.S. GAAP and should not be considered alternatives to net income, which is the most directly comparable financial measure to Adjusted EBITDA that is in accordance with U.S. GAAP. Segment Adjusted EBITDA, as determined and measured by the Company, should also not be compared to similarly titled measures reported by other companies.
	The Company manages its assets on a total company basis, not by segment. Therefore, management does not review any asset information by segment and, accordingly, the Company does not report asset information by segment.
	Reportable segment information is as follows (in millions):


	Year Ended December 31, 2013	Specialty				Fuel				Combined				Eliminations				Consolidated
		Products				Products				Segments								Total
	Sales:
	External customers	$	1,774.90			$	3,646.50			$	5,421.40			$	—			$	5,421.40

	Intersegment sales	—				77.3				77.3				(77.3		)		—

	Total sales	$	1,774.90			$	3,723.80			$	5,498.70			$	(77.3	)		$	5,421.40

	Adjusted EBITDA	$	194.5			$	47			$	241.5			—				$	241.5

	Reconciling items to net income:
	Depreciation and amortization	66.6				67.1				133.7				—				133.7

	Realized loss on derivatives, not reflected in net income	(0.5		)		(1.3		)		(1.8		)		—				(1.8		)

	Unrealized gain on derivatives																	(25.7		)
	Interest expense																	96.8

	Debt extinguishment costs																	14.6

	Non-cash equity based compensation and other non-cash items																	20

	Income tax expense																	0.4

	Net income																	$	3.5



	Year Ended December 31, 2012	Specialty				Fuel				Combined				Eliminations				Consolidated
		Products				Products				Segments								Total
	Sales:
	External customers	$	1,849.90			$	2,807.40			$	4,657.30			$	—			$	4,657.30

	Intersegment sales	—				50.2				50.2				(50.2		)		—

	Total sales	$	1,849.90			$	2,857.60			$	4,707.50			$	(50.2	)		$	4,657.30

	Adjusted EBITDA	$	283.2			$	121.4			$	404.6			—				$	404.6

	Reconciling items to net income:
	Depreciation and amortization	55.8				49.2				105				—				105

	Realized loss on derivatives, not reflected in net income	(1.9		)		(3.1		)		(5.0		)		—				(5.0		)

	Unrealized loss on derivatives																	3.8

	Interest expense																	85.6

Non-cash equity based compensation and other non-cash items																	8.7

Income tax expense																	0.8

Net income																	$	205.7



Year Ended December 31, 2011	Specialty				Fuel				Combined				Eliminations				Consolidated
	Products				Products				Segments								Total
Sales:
External customers	$	1,630.50			$	1,504.40			$	3,134.90			$	—			$	3,134.90

Intersegment sales	—				45.8				45.8				(45.8		)		—

Total sales	$	1,630.50			$	1,550.20			$	3,180.70			$	(45.8	)		$	3,134.90

Adjusted EBITDA	$	280.6			$	(69.6	)		$	211			$	—			$	211

Reconciling items to net income:
Depreciation and amortization	43.2				31.3				74.5				—				74.5

Realized gain on derivatives, not reflected in net income	2.5				8.4				10.9				—				10.9

Unrealized loss on derivatives																	10.4

Interest expense																	48.7

Debt extinguishment costs																	15.1

Non-cash equity based compensation and other non-cash items																	7.4

Income tax expense																	1

Net income																	$	43

b. Geographic Information
International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2013, 2012 and 2011. As of December 31, 2013 and 2012, substantially all of the Company’s long-lived assets are domestically located.
c. Product Information
The Company offers specialty products primarily in five general categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products and other. Fuel products categories primarily consist of gasoline, diesel, jet fuel, asphalt and heavy fuel oils and other. The following table sets forth the major product category sales (in millions):


	Year Ended December 31,
	2013							2012							2011
Specialty products:
Lubricating oils	$	848.8			15.7	%		$	1,007.90			21.6	%		$	947.8			30.2	%

Solvents	511.7				9.4	%		491.1				10.5	%		495.9				15.8	%

Waxes	141				2.6	%		142.8				3.1	%		143.1				4.6	%

Packaged and synthetic specialty products	233.6				4.3	%		161.7				3.5	%		—				—	%

Other	39.8				0.7	%		46.4				1	%		43.7				1.4	%

Total	1,774.90				32.7	%		1,849.90				39.7	%		1,630.50				52	%

Fuel products:
Gasoline	1,409.40				26	%		1,174.90				25.2	%		619.6				19.8	%

Diesel	1,259.20				23.3	%		941				20.2	%		513.3				16.4	%

Jet fuel	191.4				3.5	%		184				4	%		148				4.7	%

Asphalt, heavy fuel oils and other	786.5				14.5	%		507.5				10.9	%		223.5				7.1	%

Total	3,646.50				67.3	%		2,807.40				60.3	%		1,504.40				48	%

Consolidated sales	$	5,421.40			100	%		$	4,657.30			100	%		$	3,134.90			100	%

d. Major Customers
During the years ended December 31, 2013, 2012 and 2011, the Company had no customer that represented 10% or greater of consolidated sales.

e. Major Suppliers
During the years ended December 31, 2013, 2012 and 2011, the Company had two suppliers that supplied approximately 54.1%, 65.0% and 55.2%, respectively, of its crude oil supply.

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Data (Unaudited)	'
	Quarterly Financial Data (Unaudited)
	The table below sets forth selected quarterly financial data for each of the last two fiscal years (in millions, except unit and per unit data):


		First		Second		Third			Fourth			Total (1)
		Quarter		Quarter		Quarter			Quarter
	2013
	Sales	$	1,318.60	$	1,354.20	$	1,505.50		$	1,243.10		$	5,421.40

	Gross profit	134.4		101		62.1			112.5			410

	Net income (loss)	46		7.8		(34.8		)	(15.5		)	3.5

	Net income (loss) available to limited partners	41.7		3.8		(37.9		)	(19.0		)	(11.5		)

	Limited partners’ interest basic net income (loss) per unit	$	0.67	$	0.05	$	(0.54	)	$	(0.27	)	$	(0.17	)

	Limited partners’ interest diluted net income (loss) per unit	$	0.66	$	0.05	$	(0.54	)	$	(0.27	)	$	(0.17	)

	Weighted average limited partner units outstanding — basic	62,831,155		69,571,855		69,626,650			69,635,865

	Weighted average limited partner units outstanding — diluted	63,017,869		69,769,536		69,626,650			69,635,865



		First		Second		Third			Fourth			Total (1)
		Quarter		Quarter		Quarter			Quarter
	2012
	Sales	$	1,169.60	$	1,087.00	$	1,179.80		$	1,220.90		$	4,657.30

	Gross profit	84.2		128.8		158.4			141.8			513.2

	Net income	51.9		65.7		42.4			45.7			205.7

	Net income available to limited partners	50.1		62.9		39.7			42.3			195

	Limited partners’ interest basic net income per unit	$	0.97	$	1.14	$	0.69		$	0.73		$	3.51

	Limited partners’ diluted net income per unit	$	0.97	$	1.14	$	0.69		$	0.73		$	3.5

	Weighted average limited partner units outstanding — basic	51,684,741		55,027,786		57,745,806			57,745,881

	Weighted average limited partner units outstanding — diluted	51,736,396		55,074,265		57,825,603			57,898,207





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

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	Subsequent Events
	On January 24, 2014, the Company declared a quarterly cash distribution of $0.685 per unit on all outstanding common units, or approximately $52.6 million (including the general partner’s incentive distribution rights) in aggregate, for the quarter ended December 31, 2013. The distribution was paid on February 14, 2014 to unitholders of record as of the close of business on February 4, 2014. This quarterly distribution of $0.685 per unit equates to $2.74 per unit, or approximately $210.4 million (including the general partner’s incentive distribution rights) in aggregate on an annualized basis.
	The fair value of the Company’s derivatives increased by approximately $56.0 million subsequent to December 31, 2013 to a net asset of approximately $1.0 million. The fair value of the Company’s long-term debt, excluding capital leases, has increased by approximately $40.0 million subsequent to December 31, 2013.
	On February 28, 2014, the Company completed the acquisition of substantially all of the assets of United Petroleum, LLC, a marketer and distributor of high-performance lubricants, for aggregate consideration of approximately $10.4 million. United Petroleum, LLC markets and distributes an array of high-end specialty lubricants. The Company believes the acquisition increases its sales in the specialty lubricants market, expands its geographic reach and increases its asset diversity.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Consolidation	'
	The consolidated financial statements reflect the accounts of the Company and its wholly-owned and majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.
Reclassification, Policy	'
	Certain amounts in the prior years’ consolidated financial statements have been reclassified to conform to the current year presentation.
Use of Estimates	'
	The Company’s consolidated financial statements are prepared in conformity with U.S. generally accepted accounting (“U.S. GAAP”) principles which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents	'
	Cash and cash equivalents includes all highly liquid investments with a maturity of three months or less at the time of purchase.
Accounts Receivable	'
	The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are carried at their face amounts and are generally due within 30 days to 45 days from date of invoice for the specialty products segment and 10 days from date of invoice for the fuel products segment. The Company maintains an allowance for doubtful accounts for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay. Individual accounts are written off against the allowance for doubtful accounts after all reasonable collection efforts have been exhausted.
Inventories	'
	The cost of inventory is recorded using the last-in, first-out (LIFO) method. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. The replacement cost of these inventories, based on current market values, would have been $32.2 million and $38.3 million higher as of December 31, 2013 and 2012, respectively. At December 31, 2013 and 2012, the Company had $2.6 million and $2.3 million, respectively, of consigned inventory.
	Inventories consist of the following (in millions):


		December 31,
		2013		2012
	Raw materials	$	122.7	$	85.4

	Work in process	102.6		119.5

	Finished goods	342.1		348.7

		$	567.4	$	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. For each of the years ended December 31, 2013, 2012 and 2011, the Company recorded gains and (losses) of $4.2 million, $(4.2) million and $5.2 million, respectively, in cost of sales in the consolidated statements of operations due to the liquidation of inventory layers.
	In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. During the years ended December 31, 2013, 2012 and 2011 the Company recorded $6.0 million, $8.1 million and $2.0 million, respectively, of losses in cost of sales in the consolidated statements of operations due to the lower of cost or market valuation.
Derivatives	'
	The Company is exposed to fluctuations in the price of numerous commodities, such as crude oil (its principal raw material) and natural gas, as well as the sales prices of gasoline, diesel and jet fuel. Given the historical volatility of commodity prices, these fluctuations can significantly impact sales, gross profit and net income. Therefore, the Company utilizes derivative instruments primarily to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas and the sale of fuel products. The Company employs various hedging strategies and does not hold or issue derivative instruments for trading purposes. For further information, please refer to Note 8.
	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, collars and options to attempt to reduce the Company’s exposure with respect to:

	•	crude oil purchases and sales;

	•	fuel product sales and purchases;

	•	natural gas purchases; and

	•	fluctuations in the value of crude oil between geographic regions and in 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 9) as either current assets or current liabilities on the 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.
	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 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 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 has resulted, 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 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 consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. 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, crude oil sales 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 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 consolidated balance sheets, until the underlying transaction hedged is recognized in the 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 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 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.
Property, Plant and Equipment	'
	Property, plant and equipment are stated on the basis of cost. Depreciation is calculated generally on composite groups, using the straight-line method over the estimated useful lives of the respective groups. Assets under capital leases are amortized over the lesser of the useful life of the asset or the term of the lease.
Composite Depreciation Method	'
	Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related accumulated depreciation are retired, and any gain or loss is reflected in earnings
Capitalized Software	'
	The Company capitalizes the cost of computer software developed or obtained for internal use. Capitalized software is amortized using the straight-line method over five years.
Investment in Unconsolidated Affiliate	'
	The Company accounts for its ownership in its Dakota Prairie Refining, LLC joint venture in accordance with ASC 323, Investments — Equity Method and Joint Ventures. The joint venture’s refinery was not operational in 2013. The equity method of accounting is applied when the investor has an ownership interest of less than 50% and/or has significant influence over the operating or financial decisions of the investee. Under the equity method, the Company’s proportionate share of net income (loss) is reflected as a single-line item in the consolidated statements of operations and increases or decreases, as applicable, in the carrying value of the Company’s investment in the consolidated balance sheets. In addition, the proportionate share of net income (loss) is reflected as a non-cash activity in operating activities in the consolidated statements of cash flows. Contributions increase the carrying value of the investment and are reflected as an investing activity in the consolidated statements of cash flows.
	Equity method investments are assessed for other-than-temporary impairment when the investment generates net losses. No impairment was recognized in 2013 or 2012. For further information on investment in unconsolidated affiliate, refer to Note 4.
Goodwill	'
	Goodwill represents the excess of purchase price over fair value of the net assets acquired in various acquisitions. See Note 3 for more information. The Company reviews goodwill for impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable in accordance with ASC 350, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). In September 2011, the FASB amended ASU 2011-08 which amended the rules for testing for impairment. Under ASU 2011-08, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The Company early adopted ASU 2011-08 for the October 1, 2011 annual goodwill impairment test.
	In assessing the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company assesses relevant events and circumstances that may impact the fair value and the carrying amount of the reporting unit. The identification of relevant events and circumstances and how these may impact a reporting unit’s fair value or carrying amount involve significant judgment and assumptions. The judgment and assumptions include the identification of macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and Company specific events and making the assessment on whether each relevant factor will impact the impairment test positively or negatively and the magnitude of any such impact.
	If the Company’s qualitative assessment concludes that it is probable that an impairment exists or the Company skips the qualitative assessment then the Company needs to perform a quantitative assessment. In the first step of the quantitative assessment, the Company’s assets and liabilities, including existing goodwill and other intangible assets, are assigned to the identified reporting units to determine the carrying value of the reporting units. If the carrying value of a reporting unit is in excess of its fair value, an impairment may exist, and the Company must perform an impairment analysis, in which the implied fair value of the goodwill is compared to its carrying value to determine the impairment charge, if any.
	When performing the quantitative assessment, the fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation, and risks associated with the reporting unit.
Other Intangible Assets	'
	Other intangible assets consist of intangible assets associated with customer relationships, supplier agreements, tradenames, trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements that were acquired in various acquisitions. The majority of these assets are being amortized using discounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships are being amortized using the discounted estimated future cash flows method based upon assumed rates of annual customer attrition. For more information, refer to Note 5.
Deferred Debt Issuance Cost	'
	Deferred debt issuance costs were $29.7 million and $29.4 million as of December 31, 2013 and 2012, respectively, and are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $13.6 million and $6.6 million at December 31, 2013 and 2012, respectively.
Turnaround Costs	'
	Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $67.0 million and $14.3 million as of December 31, 2013 and 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 $25.7 million and $17.8 million at December 31, 2013 and 2012, respectively.
Impairment of Long-Lived Assets	'
	The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In such an event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair value of the long-lived asset. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.
Business Combinations Policy	'
	Assets and liabilities associated with business acquisitions are recorded at fair value, using the acquisition method of accounting. The Company allocates the purchase price of acquisitions based upon the fair value of each component, which may be derived from various observable or unobservable inputs and assumptions. The Company may utilize third-party valuation specialists to assist the Company in this allocation. Initial purchase price allocations are preliminary and subject to revision within the measurement period, not to exceed one year from the date of acquisition. 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 identifiable assets acquired and liabilities assumed.
	Business acquisition costs are expensed as incurred, and are reported as general and administrative expenses in the consolidated statements of operations. The Company defines these costs to include finder’s fees, advisory, legal, accounting, valuation, and other professional or consulting fees, as well as travel associated with the evaluation and effort to acquire specific businesses.
Revenue Recognition	'
	The Company recognizes revenue on orders received from its customers when there is persuasive evidence of an arrangement with the customer that is supportive of revenue recognition, the customer has made a fixed commitment to purchase the product for a fixed or determinable sales price, collection is reasonably assured under the Company’s normal billing and credit terms, all of the Company’s obligations related to product have been fulfilled and ownership and all risks of loss have been transferred to the buyer, which is primarily upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.
Concentrations of Credit Risk	'
	The Company performs periodic credit evaluations of its customers’ financial condition and in some instances requires cash in advance or letters of credit prior to shipment for domestic orders. For international orders, letters of credit are generally required and the Company maintains insurance policies which cover certain export orders. The Company maintains an allowance for doubtful customer accounts for estimated losses resulting from the inability of its customers to make required payments. The allowance for doubtful accounts is developed based on several factors including historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay, which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. In addition, from time to time the Company has significant derivative assets with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s ASC 820-10, Fair Value Measurements and Disclosures, valuations to determine the impact of the counterparty credit risk on the valuation of its derivative instruments.
Income Taxes	'
	The Company, as a partnership, is generally not liable for federal income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries. However, certain wholly-owned subsidiaries of the Company, are corporations and, as a result, are liable for income taxes on their earnings. Income taxes related to these subsidiaries were not significant in 2013, 2012 and 2011. Additionally, the Company is subject to franchise taxes which were not material for 2013, 2012 and 2011. Income taxes on the earnings of the Company, with the exception of the above mentioned items, are the responsibility of its partners, with earnings of the Company included in partners’ earnings.
	In the event that the Company’s taxable income did not meet certain qualification requirements, the Company would be taxed as a corporation. Interest and penalties related to income taxes, if any, would be recorded in income tax expense. Generally, tax returns remain subject to examination by taxing authorities for three years. The Company had no unrecognized tax benefits as of December 31, 2013 and 2012.
Excise and Sales Taxes	'
	The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of its products to non-exempt customers. Excise taxes and sales taxes assessed and collected from customers are recorded on a net basis within sales in the Company’s consolidated statements of operations.
Earnings Per Unit	'
	The Company calculates earnings per unit under ASC 260-10, Earnings per Share. The Company treats incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually obligated to receive IDRs. Also, the undistributed earnings are allocated to the partnership interests based on the allocation of earnings to the Company’s partners’ capital accounts as specified in the Company’s partnership agreement. When distributions exceed earnings, net income is reduced by the actual distributions with the resulting net loss being allocated to capital accounts as specified in the Company’s partnership agreement.
Unit Based Compensation	'
	For unit based compensation awards granted, compensation expense is recognized in the Company’s consolidated financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The unit based compensation awards vest over a period not exceeding four years. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.
	Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). Liability Awards are recorded in accrued salaries, wages and benefits based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense.
	The Company’s general partner originally adopted a Long-Term Incentive Plan on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Long-Term Incentive Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Long-Term Incentive Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Long-Term Incentive Plan is administered by the compensation committee of the Company’s general partner’s board of directors.
	Non-employee directors of the Company’s general partner have been granted phantom units under the terms of the Long-Term Incentive Plan as part of their director compensation package related to fiscal years 2011, 2012 and 2013. These phantom units have a four year service period with one-quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
	For the year ended December 31, 2012, named executive officers and certain employees were awarded phantom units under the terms of the Long-Term Incentive Plan, as part of the Company’s achievement of specified levels of financial performance in the fiscal year. These phantom units are subject to time-vesting requirements whereby 25% of the units vest during the performance period, and the remainder will vest ratably over the next three years on each December 31. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
	The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and general and administrative expense in the consolidated statements of operations using the straight-line method over the service period, as it expects these units to fully vest.
	Liability Awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units. Phantom unit Liability Awards are recorded in accrued salaries, wages and benefits in the consolidated balance sheets based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense within general and administrative expense in the consolidated statements of operations.
Shipping and Handling Costs	'
	The Company complies with ASC 605-45, Revenue Recognition — Principal Agent Considerations. ASC 605-45 requires the classification of shipping and handling costs billed to customers in sales and the classification of shipping and handling costs incurred in cost of sales, or to be disclosed if classified elsewhere.
Advertising Costs	'
	The Company expenses advertising costs as incurred
RINS Obligation	'
	The Company’s Renewable Identification Numbers obligation (“RINs Obligation”) represents a liability for the purchase of RINs to satisfy the U.S. Environmental Protection Agency (“EPA”) requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as of the balance sheet date. The Company uses the inventory model to account for RINs, measuring acquired RINs at weighted-average cost. The cost of RINs used each period is charged to cost of sales with cash inflows and outflows recorded in the operating cash flow section of the consolidated statements of cash flows. Excess RINs are classified as inventory in the consolidated balance sheets. The Company recognizes a liability at the end of each reporting period in which the Company does not have sufficient RINs to cover the RINs Obligation. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN spot price.
New 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 July 2012, the FASB issued ASU No. 2012-02, Intangibles (Topic 350)—Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). ASU 2012-02 permits an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is more than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset exceeds its carrying amount, quantitative impairment testing is not required. However, if an entity concludes otherwise, quantitative impairment testing is required. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The adoption of ASU 2012-02 did not have a material impact on the Company’s consolidated financial statements.
	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 in the consolidated statements 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.
	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.

Goodwill_and_Intangible_Assets1

Goodwill and Intangible Assets (Policies)	12 Months Ended
Goodwill and Intangible Assets (Policies)	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	'
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	Supplier agreements, tradenames (other than indefinite lived), trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements are being amortized to properly match expense with the discounted estimated future cash flows over the terms of the related agreements. Agreements with terms allowing for the potential extension of such agreements are being amortized based on the initial term only. Customer relationships are being amortized using discounted estimated future cash flows based upon assumed rates of annual customer attrition.

Derivatives_Policies

Derivatives (Policies)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivatives	'
	The Company is exposed to fluctuations in the price of numerous commodities, such as crude oil (its principal raw material) and natural gas, as well as the sales prices of gasoline, diesel and jet fuel. Given the historical volatility of commodity prices, these fluctuations can significantly impact sales, gross profit and net income. Therefore, the Company utilizes derivative instruments primarily to minimize its price risk and volatility of cash flows associated with the purchase of crude oil and natural gas and the sale of fuel products. The Company employs various hedging strategies and does not hold or issue derivative instruments for trading purposes. For further information, please refer to Note 8.
	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, collars and options to attempt to reduce the Company’s exposure with respect to:

	•	crude oil purchases and sales;

	•	fuel product sales and purchases;

	•	natural gas purchases; and

	•	fluctuations in the value of crude oil between geographic regions and in 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 9) as either current assets or current liabilities on the 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.
	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 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 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 has resulted, 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 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 consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. 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, crude oil sales 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 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 consolidated balance sheets, until the underlying transaction hedged is recognized in the 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 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 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.

Fair_Value_Measurements_Polici

Fair Value Measurements (Policies)	12 Months Ended
Fair Value Measurements (Policies)	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value of Financial Instruments, Policy	'
	The estimated fair value of long-term debt at December 31, 2013 and 2012 consists primarily of senior notes. The estimated aggregate fair value of the Company’s senior notes classified as Level 1 were based upon quoted market prices in an active market. The estimated aggregate fair value of the Company’s senior notes classified as Level 2 were based upon directly observable inputs. The carrying value of borrowings, if any, under the Company’s revolving credit facility and capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3.
	Pension assets are reported at fair value in the accompanying consolidated financial statements. At December 31, 2013, the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consist of (i) cash and cash equivalents and (ii) mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the Pension Plan at quarter end as provided by the third party administrator.
	All settlements from derivative instruments that are deemed “effective” and were designated as cash flow hedges are included in sales for gasoline, diesel and jet fuel derivatives and cost of sales for crude oil derivatives in the consolidated statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these derivative instruments are recorded in earnings in realized gain (loss) on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments not designated as cash flow hedges are recorded in realized gain (loss) on derivative instruments in the consolidated statements of operations.
	Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). The Liability Awards are categorized as Level 1 because the fair value of the Company’s Liability Awards are based on the Company’s quoted closing unit price as of each balance sheet date.
	The Company’s RINs Obligation represents a liability for the purchase of RINs to satisfy the EPA requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as of the balance sheet date. The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
	To estimate the fair values of the Company’s derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and credit worthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. As a result of applying the applicable CVA at December 31, 2013, the net liability of the Company was reduced by approximately $1.9 million. As a result of applying the CVA at December 31, 2012, the Company’s net asset was reduced by approximately $0.1 million and the net liability was reduced by approximately $0.2 million.
	Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were primarily based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds.
Fair Value Measurement, Policy	'
	Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. Refer to Note 3 for the fair values of assets acquired and liabilities assumed in connection with the Company’s acquisitions.
	The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 5 for further information on goodwill.
	The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets, indefinite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was required to measure and record such assets at fair value within its consolidated financial statements. See Note 2 and Note 5 for further information on long-lived assets.

UnitBased_Compensation_Policie

Unit-Based Compensation (Policies)	12 Months Ended
Unit-Based Compensation (Policies)	Dec. 31, 2013
Compensation Related Costs [Abstract]	'
Unit Based Compensation	'
	For unit based compensation awards granted, compensation expense is recognized in the Company’s consolidated financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The unit based compensation awards vest over a period not exceeding four years. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.
	Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). Liability Awards are recorded in accrued salaries, wages and benefits based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense.
	The Company’s general partner originally adopted a Long-Term Incentive Plan on January 24, 2006, which was amended and restated effective January 22, 2009, for its employees, consultants and directors and its affiliates who perform services for the Company. The Long-Term Incentive Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Subject to adjustment for certain events, an aggregate of 783,960 common units may be delivered pursuant to awards under the Long-Term Incentive Plan. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The Long-Term Incentive Plan is administered by the compensation committee of the Company’s general partner’s board of directors.
	Non-employee directors of the Company’s general partner have been granted phantom units under the terms of the Long-Term Incentive Plan as part of their director compensation package related to fiscal years 2011, 2012 and 2013. These phantom units have a four year service period with one-quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
	For the year ended December 31, 2012, named executive officers and certain employees were awarded phantom units under the terms of the Long-Term Incentive Plan, as part of the Company’s achievement of specified levels of financial performance in the fiscal year. These phantom units are subject to time-vesting requirements whereby 25% of the units vest during the performance period, and the remainder will vest ratably over the next three years on each December 31. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
	The Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital and general and administrative expense in the consolidated statements of operations using the straight-line method over the service period, as it expects these units to fully vest.
	Liability Awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units. Phantom unit Liability Awards are recorded in accrued salaries, wages and benefits in the consolidated balance sheets based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense within general and administrative expense in the consolidated statements of operations.

Segments_and_Related_Informati1

Segments and Related Information (Policies)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Reporting, Policy	'
	The Company manages its business in multiple operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments:

	•	Specialty Products. The Specialty Products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants and other products which are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. Specialty products also include synthetic lubricants used in manufacturing, mining and automotive applications.

	•	Fuel Products. The Fuel Products segment produces primarily gasoline, diesel fuel, jet fuel and asphalt which are primarily sold to customers located in PADD 2, PADD 3 and PADD 4 areas within the U.S.
	During the fourth quarter 2013, the Company realigned its reportable segments for financial reporting purposes as a result of significant growth in the Company. The change primarily represents reporting the operating results of asphalt produced at the Shreveport, Superior and Montana refineries within the fuel products segment. Prior to this change, asphalt was reported as part of the specialty products segment. While this reporting change did not impact the Company’s consolidated results, segment data for previous years has been restated and is consistent with the current year presentation throughout the financial statements and the accompanying notes.
	The accounting policies of the reporting segments are the same as those described in Note 2, except that the disaggregated financial results for the reporting segments have been prepared using a management approach, which is consistent with the basis and manner in which management internally disaggregates financial information for the purposes of assisting internal operating decisions. The Company evaluates performance based upon Adjusted EBITDA. The Company defines Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.
	Through September 30, 2013, the Company’s management believed that income from operations was a meaningful measure of performance and it was used by management to analyze the Company and stand-alone operating segment performance. During the fourth quarter 2013, the Company’s management determined that Adjusted EBITDA is the key performance measure for planning and forecasting purposes and discontinued the use of income from operations as a measure of performance. Segment Adjusted EBITDA should not be considered a substitute for results prepared in accordance with U.S. GAAP and should not be considered alternatives to net income, which is the most directly comparable financial measure to Adjusted EBITDA that is in accordance with U.S. GAAP. Segment Adjusted EBITDA, as determined and measured by the Company, should also not be compared to similarly titled measures reported by other companies.
	The Company manages its assets on a total company basis, not by segment. Therefore, management does not review any asset information by segment and, accordingly, the Company does not report asset information by segment.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Allowance for Doubtful Accounts Activity	'
	The activity in the allowance for doubtful accounts was as follows (in millions):


		December 31,
		2013			2012			2011
	Beginning balance	$	1.2		$	0.9		$	0.6

	Provision	0.1			—			0.4

	Recoveries	—			0.4			—

	Write-offs, net	(0.1		)	(0.1		)	(0.1		)
	Ending balance	$	1.2		$	1.2		$	0.9

Inventories	'
	Inventories consist of the following (in millions):


		December 31,
		2013			2012
	Raw materials	$	122.7		$	85.4

	Work in process	102.6			119.5

	Finished goods	342.1			348.7

		$	567.4		$	553.6

Property, Plant and Equipment	'
	Property, plant and equipment, including depreciable lives, consisted of the following (in millions):


		December 31,
		2013			2012
	Land	$	17.6		$	11.2

	Buildings and improvements (10 to 40 years)	39.1			28.1

	Machinery and equipment (10 to 20 years)	1,327.40			1,173.00

	Furniture and fixtures (5 to 10 years)	21.7			7.6

	Assets under capital leases (10 to 28 years)	11.1			11.1

	Construction-in-progress	121.5			53.8

		1,538.40			1,284.80

	Less accumulated depreciation	(378.0		)	(297.9		)
		$	1,160.40		$	986.9

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Purchase price allocation	'
	The Bel-Ray 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 assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. The assets and results of the operations from such assets acquired as a result of the Superior, Montana, San Antonio and Crude Oil Logistics Acquisitions have been included in the fuel products segments since the date of acquisition, September 30, 2011, October 1, 2012, January 2, 2013 and August 9, 2013, respectively. The assets and results of operations from such assets acquired as a result of the Missouri, Calumet Packaging, Royal Purple and Bel-Ray Acquisitions have been included in the specialty products segment since the date of acquisition, January 3, 2012, January 6, 2012, July 3, 2012 and December 10, 2013, respectively.
	The allocations of the aggregate purchase prices to assets acquired and liabilities assumed for acquisitions are as follows (in millions):


		2013 Acquisitions										2012 Acquisitions
		Bel-Ray			Crude Oil Logistics				San Antonio			Montana			Royal Purple			Calumet Packaging			Missouri
	Accounts receivable	$	4.3		$	—			$	—		$	29		$	15.2		$	5.2		$	—

	Inventories	11.1			—				17			43.7			19.3			8			2.7

	Prepaid expenses and other current assets	0.6			0.1				—			23.1			0.2			0.3			—

	Deposits	—			—				—			0.3			—			—			—

	Property, plant and equipment	6.5			0.9				100.7			125.4			10.6			17.7			10

	Goodwill	9.1			5.2				5.7			27.6			109.2			0.4			1.5

	Other intangible assets	41.4			—				—			—			183.4			2.6			5.4

	Other noncurrent assets, net	0.3			—				—			0.3			—			—			—

	Accounts payable	(3.9		)	—				—			(8.4		)	(3.8		)	(2.7		)	—

	Accrued salaries, wages and benefits	(1.3		)	—				(0.1		)	(1.4		)	(1.7		)	(0.2		)	—

	Deferred income tax liability	—			—				—			(27.6		)	—			—			—

	Accrued income taxes payable	—			—				—			(15.6		)	—			—			—

	Other taxes payable	(1.7		)	—				—			(3.0		)	(0.2		)	—			—

	Other current liabilities	(0.8		)	—				(5.4		)	(0.1		)	(1.0		)	(0.9		)	—

	Current portion of long-term debt	(11.9		)	—				—			—			—			—			—

	Long-term debt	—			—				—			—			—			(3.5		)	—

	Pension and postretirement benefit obligations	—			—				—			(1.7		)	—			—			—

	Other long-term liabilities	(0.1		)	—				—			—			—			—			—

	Total purchase price, net of cash acquired	$	53.6		$	6.2			$	117.9		$	191.6		$	331.2		$	26.9		$	19.6

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


		Bel-Ray					Royal Purple						Calumet Packaging					Missouri
		10-Dec-13					3-Jul-12						6-Jan-12					3-Jan-12
		Amount			Life (Years)		Amount				Life (Years)		Amount			Life (Years)		Amount			Life (Years)
	Customer relationships	$	28.6		30		$	118.7			20		$	1.8		16		$	5.4		20

	Trade names	—			Indefinite		14.8				Indefinite		—			Indefinite		—			Indefinite

	Trade names	4.2			18		5.7				10		0.7			9		—			—

	Trade secrets	8.5			18		44.2				12		—			—		—			—

	Non-competition agreements	0.1			3		—				—		0.1			2		—			—

	Totals	$	41.4				$	183.4					$	2.6				$	5.4

	Weighted average amortization period				26						18					14					20

Schedule of business acquisitions	'
	In connection with the respective acquisition, the Company incurred the following expenses, which are reflected in general and administrative expenses in the consolidated statements of operations for the years ended December 31, 2013 and 2012 (in millions):


		Year Ended December 31,
		2013			2012
	Bel-Ray Acquisition	$	0.4		$	—

	Crude Oil Logistics Acquisition	$	0.2		$	—

	San Antonio Acquisition	$	0.5		$	—

	Montana Acquisition	$	0.1		$	3.3

	Royal Purple Acquisition	$	—		$	0.4

	Calumet Packaging Acquisition	$	—		$	0.2

	Missouri Acquisition	$	—		$	0.5

	The Company recorded the following goodwill (in millions):


		Amount			Business Segment
	Bel-Ray Acquisition (1)	$	9.1		Specialty Products

	Crude Oil Logistics Acquisition (2)	$	5.2		Fuel Products

	San Antonio Acquisition (1)	$	5.7		Fuel Products

	Montana Acquisition (1)	$	27.6		Fuel Products

	Royal Purple Acquisition (1)	$	109.2		Specialty Products

	Calumet Packaging Acquisition (1)	$	0.4		Specialty Products

	Missouri Acquisition (1)	$	1.5		Specialty Products





	-1	Goodwill recognized relates primarily to enhancing the Company’s strategic platform for expansion in the respective business segment noted above.

	-2	Goodwill recognized relates primarily to enhancing the Company’s crude oil gathering operations to support the Superior refinery.
Unaudited pro forma financial information	'
	The following financial information reflects sales and operating income of the acquisitions of San Antonio and Bel-Ray in 2013, the acquisitions of Missouri, Calumet Packaging, Royal Purple and Montana in 2012 and the acquisition of Superior in 2011 that are included in the consolidated statements of operations (in millions):


		Year Ended December 31,
		2013			2012			2011
	Sales	$	480.1		$	266.1		$	341.2

	Operating income (loss)	$	(22.5	)	$	18.6		$	18

	Unaudited Pro Forma Financial Information
	The following unaudited pro forma financial information reflects the 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 per unit data):


		Year Ended December 31,
		2012
	Sales	$	5,626.10

	Net income	$	189.2

	Limited partners’ interest net income per unit — basic	$	2.61

	Limited partners’ interest net income per unit — diluted	$	2.6

Goodwill_and_Intangible_Assets2

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Schedule of Goodwill	'
	Changes in goodwill balances are as follows (in millions):


		Year Ended December 31,
		2013												2012
		Specialty				Fuel								Specialty				Fuel
		Products				Products				Total				Products				Products		Total
	Beginning balance:	$	159.4			$	27.6			$	187			$	48.3			$	—	$	48.3

	Acquisitions	9.1				10.9				20				111.1				27.6		138.7

	Accumulated impairment losses	—				—				—				—				—		—

	Ending balance:	$	168.5			$	38.5			$	207			$	159.4			$	27.6	$	187

Schedule of Other Intangible Assets	'
	Other intangible assets consist of the following (in millions):


		Weighted Average Life (Years)		31-Dec-13								31-Dec-12
				Gross Amount				Accumulated Amortization				Gross Amount				Accumulated Amortization
	Customer relationships	22		$	182.9			$	(40.3	)		$	154.3			$	(22.6	)

	Supplier agreements	4		21.5				(21.5		)		21.5				(21.5		)

	Tradenames	Indefinite		14.8				—				14.8				—

	Tradenames	13		10.6				(1.6		)		6.4				(0.6		)

	Trade secrets	13		52.7				(9.6		)		44.2				(3.1		)

	Patents	12		1.6				(1.2		)		1.6				(1.1		)

	Non-competition agreements	5		5.9				(5.8		)		5.8				(5.8		)

	Distributor agreements	3		2				(2.0		)		2				(2.0		)

	Royalty agreements	19		4.5				(1.6		)		4.5				(1.3		)

		18		$	296.5			$	(83.6	)		$	255.1			$	(58.0	)

Schedule of Estimated Future Amortization Expense	'
	The Company estimates that amortization of intangible assets for the next five years will be as follows (in millions):


	Year		Amortization Amount
	2014		$	29.4

	2015		$	26.8

	2016		$	24.4

	2017		$	21.4

	2018		$	18.2

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Operating Leases, Fiscal Year Maturity Schedule	'
	As of December 31, 2013, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows (in millions):


	Year	Operating
		Leases
	2014	$	30

	2015	26.8

	2016	22.4

	2017	19.6

	2018	16.7

	Thereafter	30.6

	Total	$	146.1

Purchase Commitment, Fiscal Year Maturity Schedule	'
	As of December 31, 2013, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows (in millions):


	Year	Commitment
	2014	$	867

	2015	3.1

	2016	0.8

	2017	0.3

	2018	—

	Thereafter	—

	Total	$	871.2

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Instrument [Line Items]	'
Summary of long-term debt	'
	Long-term debt consisted of the following (in millions):


		December 31,				December 31,
		2013				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 9.9% for the years ended December 31, 2013 and 2012	500				600

	Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the years ended December 31, 2013 and 2012	275				275

	Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 7.9% for the year ended December 31, 2013	350				—

	Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	4.8				5.5

	Less unamortized discounts	(19.0		)		(17.0		)
	Total long-term debt	1,110.80				863.5

	Less current portion of long-term debt	0.4				0.8

		$	1,110.40			$	862.7

Schedule of basis spread	'
	As of December 31, 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 as follows:


	Quarterly Average Availability Percentage		Margin on Base Rate		Margin on LIBOR
			Revolving Loans		Revolving Loans
	≥ 66%		1.00%		2.25%
	≥ 33% and < 66%		1.25%		2.50%
	< 33%		1.50%		2.75%
Maturities of long-term debt	'
	As of December 31, 2013, maturities of the Company’s long-term debt are as follows (in millions):


	Year		Maturity
	2014		$	0.4

	2015		0.4

	2016		0.3

	2017		0.4

	2018		0.4

	Thereafter		1,127.90

	Total		$	1,129.80

Summary of future minimum lease payments	'
	As of December 31, 2013, the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows (in millions):


	Year		Capital
			Leases
	2014		$	0.8

	2015		0.7

	2016		0.7

	2017		0.7

	2018		0.7

	Thereafter		4.1

	Total minimum lease payments		7.7

	Less amount representing interest		2.9

	Capital lease obligations		4.8

	Less obligations due within one year		0.4

	Long-term capital lease obligations		$	4.4

7 5/8% Senior Notes	'
Debt Instrument [Line Items]	'
Summary of redemption price during the period	'
	On and after January 15, 2018, the Company may on any one or more occasions redeem all or a part of the 2022 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2022 Notes, if redeemed during the twelve-month period beginning on January 15 of the years indicated below:


	Year		Percentage
	2018		103.813	%
	2019		101.906	%
	2020 and thereafter		100	%
9 5/8% Senior Notes	'
Debt Instrument [Line Items]	'
Summary of redemption price during the period	'
	On and after August 1, 2016, the Company may on any one or more occasions redeem all or a part of the 2020 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2020 Notes, if redeemed during the twelve-month period beginning on August 1 of the years indicated below:


	Year		Percentage
	2016		104.813	%
	2017		102.406	%
	2018 and at any time thereafter		100	%
9 3/8% Senior Notes	'
Debt Instrument [Line Items]	'
Summary of redemption price during the period	'
	On and after May 1, 2015, the Company may on any one or more occasions redeem all or a part of the 2019 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2019 Notes, if redeemed during the twelve-month period beginning on May 1 of the years indicated below:


	Year		Percentage
	2015		104.688	%
	2016		102.344	%
	2017 and at any time thereafter		100	%

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
Derivatives (Tables)	Dec. 31, 2013
Derivative [Line Items]	'
Offsetting Assets	'
	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 consolidated balance sheets as of December 31, 2013 and 2012 (in millions):


		31-Dec-13												December 31, 2012
		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts of Assets Presented in the Consolidated Balance Sheets				Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets

	Derivative instruments designated as hedges:
	Fuel products segment:
	Crude oil swaps	$	45.4			$	(45.4	)		$	—			$	24.9			$	(14.4	)	$	10.5
	Crude oil swaps	$	45.4			$	(45.4	)		$	—			$	24.9			$	(14.4	)	$	10.5
	Gasoline swaps	1				(1.0		)		—				5.2				(4.9		)	0.3
	Gasoline swaps	1				(1.0		)		—				5.2				(4.9		)	0.3
	Diesel swaps	3.5				(3.5		)		—				7				(14.9		)	(7.9		)
	Diesel swaps	3.5				(3.5		)		—				7				(14.9		)	(7.9		)
	Jet fuel swaps	0.1				(0.1		)		—				8				(7.8		)	0.2
	Jet fuel swaps	0.1				(0.1		)		—				8				(7.8		)	0.2
	Total derivative instruments designated as hedges	50				(50.0		)		—				45.1				(42.0		)	3.1
	Total derivative instruments designated as hedges	50				(50.0		)		—				45.1				(42.0		)	3.1
	Derivative instruments not designated as hedges:
	Fuel products segment:
	Crude oil swaps	6.3				(6.3		)		—				0.1				(0.1		)	—
	Crude oil swaps	6.3				(6.3		)		—				0.1				(0.1		)	—
	Crude oil basis swaps	1				(1.0		)		—				0.1				(0.1		)	—
	Crude oil basis swaps	1				(1.0		)		—				0.1				(0.1		)	—
	Gasoline swaps	—				—				—				—				—			—
	Gasoline swaps	—				—				—				—				—			—
	Diesel swaps	0.7				(0.7		)		—				5.1				(5.1		)	—
	Diesel swaps	0.7				(0.7		)		—				5.1				(5.1		)	—
	Jet fuel swaps	0.9				(0.9		)		—				—				—			—
	Jet fuel swaps	0.9				(0.9		)		—				—				—			—
	Diesel crack spread collars	0.3				(0.3		)		—				—				—			—
	Diesel crack spread collars	0.3				(0.3		)		—				—				—			—
	Specialty products segment:
	Crude oil swaps	—				—				—				1.6				(1.6		)	—
	Crude oil swaps	—				—				—				1.6				(1.6		)	—
	Natural gas swaps	0.4				(0.4		)		—				—				—			—
	Natural gas swaps	0.4				(0.4		)		—				—				—			—
	Total derivative instruments not designated as hedges	9.6				(9.6		)		—				6.9				(6.9		)	—
	Total derivative instruments not designated as hedges	9.6				(9.6		)		—				6.9				(6.9		)	—
	Total derivative instruments	$	59.6			$	(59.6	)		$	—			$	52			$	(48.9	)	$	3.1
	Total derivative instruments	$	59.6			$	(59.6	)		$	—			$	52			$	(48.9	)	$	3.1
Offsetting Liabilities	'


		31-Dec-13												31-Dec-12
		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts of Liabilities Presented in the Consolidated Balance Sheets				Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Liabilities Presented in the Consolidated Balance Sheets

	Derivative instruments designated as hedges:
	Fuel products segment:
	Crude oil swaps	$	(13.0	)		$	45.4			$	32.4			$	(41.1	)		$	14.4		$	(26.7	)
	Crude oil swaps	$	(13.0	)		$	45.4			$	32.4			$	(41.1	)		$	14.4		$	(26.7	)
	Gasoline swaps	(19.7		)		1				(18.7		)		(2.8		)		4.9			2.1
	Gasoline swaps	(19.7		)		1				(18.7		)		(2.8		)		4.9			2.1
	Diesel swaps	(51.3		)		3.5				(47.8		)		(25.2		)		14.9			(10.3		)
	Diesel swaps	(51.3		)		3.5				(47.8		)		(25.2		)		14.9			(10.3		)
	Jet fuel swaps	(13.4		)		0.1				(13.3		)		(10.1		)		7.8			(2.3		)
	Jet fuel swaps	(13.4		)		0.1				(13.3		)		(10.1		)		7.8			(2.3		)
	Total derivative instruments designated as hedges	(97.4		)		50				(47.4		)		(79.2		)		42			(37.2		)
	Total derivative instruments designated as hedges	(97.4		)		50				(47.4		)		(79.2		)		42			(37.2		)
	Derivative instruments not designated as hedges:
	Fuel products segment:
	Crude oil swaps	(1.7		)		6.3				4.6				(10.8		)		0.1			(10.7		)
	Crude oil swaps	(1.7		)		6.3				4.6				(10.8		)		0.1			(10.7		)
	Crude oil basis swaps	(0.6		)		1				0.4				(3.5		)		0.1			(3.4		)
	Crude oil basis swaps	(0.6		)		1				0.4				(3.5		)		0.1			(3.4		)
	Gasoline swaps	(9.4		)		—				(9.4		)		(2.2		)		—			(2.2		)
	Gasoline swaps	(9.4		)		—				(9.4		)		(2.2		)		—			(2.2		)
	Diesel swaps	(3.5		)		0.7				(2.8		)		(1.2		)		5.1			3.9
	Diesel swaps	(3.5		)		0.7				(2.8		)		(1.2		)		5.1			3.9
	Jet fuel swaps	—				0.9				0.9				—				—			—
	Jet fuel swaps	—				0.9				0.9				—				—			—
	Diesel crack spread collars	(0.2		)		0.3				0.1				—				—			—
	Diesel crack spread collars	(0.2		)		0.3				0.1				—				—			—
	Specialty products segment:
	Crude oil swaps	—				—				—				—				1.6			1.6
	Crude oil swaps	—				—				—				—				1.6			1.6
	Natural gas swaps	(1.6		)		0.4				(1.2		)		—				—			—
	Natural gas swaps	(1.6		)		0.4				(1.2		)		—				—			—
	Total derivative instruments not designated as hedges	(17.0		)		9.6				(7.4		)		(17.7		)		6.9			(10.8		)
	Total derivative instruments not designated as hedges	(17.0		)		9.6				(7.4		)		(17.7		)		6.9			(10.8		)
	Total derivative instruments	$	(114.4	)		$	59.6			$	(54.8	)		$	(96.9	)		$	48.9		$	(48.0	)
	Total derivative instruments	$	(114.4	)		$	59.6			$	(54.8	)		$	(96.9	)		$	48.9		$	(48.0	)
Schedule of Gains and Losses Due to the Discontinuance of Hedge Accounting	'


		Year Ended December 31,
		2013				2012
	Realized gain on derivative instruments	$	0.2			$	40.1
	Realized gain on derivative instruments	$	0.2			$	40.1
	Unrealized loss on derivative instruments	$	(3.9	)		$	(2.9	)
Derivative Instruments, Gain (Loss) by Hedging Relationship, by Income Statement Location, by Derivative Instrument Risk	'
	The Company recorded the following amounts in its consolidated balance sheets, consolidated statements of operations, consolidated statements of other comprehensive income (loss) and its consolidated statements of partners’ capital as of, and for the years ended December 31, 2013 and 2012 related to its derivative instruments that were designated as cash flow hedges (in millions):


		Amount of Gain (Loss)								Amount of Gain (Loss)										Amount of Gain (Loss) Recognized in Net
		Recognized in								Reclassified from										Income on Derivatives
		Accumulated Other								Accumulated Other										(Ineffective Portion)
		Comprehensive								Comprehensive Loss into
		Loss on Derivatives								Net Income (Effective Portion)
		(Effective Portion)
		Year Ended December 31,								Location of		Year Ended December 31,								Location of	Year Ended December 31,
	Type of Derivative	2013				2012				(Gain) Loss		2013				2012				Gain (Loss)	2013			2012
	Fuel products segment:
	Crude oil swaps	$	18.7			$	(100.0	)		Cost of sales		$	3.1			$	49.8			Unrealized/Realized	$	(3.0	)	$	99.7
	Crude oil swaps	$	18.7			$	(100.0	)		Cost of sales		$	3.1			$	49.8			Unrealized/Realized	$	(3.0	)	$	99.7
	Gasoline swaps	(19.5		)		(16.0		)		Sales		(0.4		)		(38.4		)		Unrealized/Realized	(1.7		)	(52.0		)
	Diesel swaps	(28.8		)		(59.3		)		Sales		(4.4		)		(63.0		)		Unrealized/Realized	(5.3		)	(10.5		)
	Jet fuel swaps	(7.3		)		(39.8		)		Sales		1.7				(104.4		)		Unrealized/Realized	5.1			(0.1		)
	Jet fuel swaps	(7.3		)		(39.8		)		Sales		1.7				(104.4		)		Unrealized/Realized	5.1			(0.1		)
	Specialty products segment:
	Crude oil swaps	—				—				Cost of sales		0.5				1.9				Unrealized/Realized	—			—
	Crude oil swaps	—				—				Cost of sales		0.5				1.9				Unrealized/Realized	—			—
	Total	$	(36.9	)		$	(215.1	)				$	0.5			$	(154.1	)			$	(4.9	)	$	37.1
	Total	$	(36.9	)		$	(215.1	)				$	0.5			$	(154.1	)			$	(4.9	)	$	37.1
	The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2013 and 2012 related to its derivative instruments not designated as cash flow hedges (in millions):


		Amount of Gain (Loss)								Amount of Gain (Loss)
		Recognized in								Recognized in Unrealized Gain
		Realized Gain (Loss) on								(Loss) on Derivatives
		Derivatives								Year Ended December 31,
		Year Ended December 31,
	Type of Derivative	2013				2012				2013				2012
	Fuel products segment:
	Crude oil swaps	$	(6.3	)		$	(30.5	)		$	46.3			$	(40.0	)
	Crude oil swaps	$	(6.3	)		$	(30.5	)		$	46.3			$	(40.0	)
	Crude oil basis swaps	(7.7		)		2.1				3.8				(3.4		)
	Crude oil basis swaps	(7.7		)		2.1				3.8				(3.4		)
	Gasoline swaps	3.2				22.1				(9.9		)		0.5
	Gasoline swaps	3.2				22.1				(9.9		)		0.5
	Diesel swaps	8.1				10.9				(11.7		)		8.9
	Diesel swaps	8.1				10.9				(11.7		)		8.9
	Jet fuel swaps	0.7				(1.7		)		0.9				—
	Jet fuel swaps	0.7				(1.7		)		0.9				—
	Diesel crack spread collars	—				—				0.1				—
	Diesel crack spread collars	—				—				0.1				—
	Specialty products segment:
	Crude oil swaps	1.8				—				(1.6		)		1.6
	Crude oil swaps	1.8				—				(1.6		)		1.6
	Natural gas swaps	(0.6		)		(5.4		)		(1.2		)		3.2
	Natural gas swaps	(0.6		)		(5.4		)		(1.2		)		3.2
	Interest rate swaps:	—				(0.7		)		—				1
	Interest rate swaps:	—				(0.7		)		—				1
	Total	$	(0.8	)		$	(3.2	)		$	26.7			$	(28.2	)
	Total	$	(0.8	)		$	(3.2	)		$	26.7			$	(28.2	)
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	'
	The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was $51.4 million and $14.0 million as of December 31, 2013 and 2012, respectively. Absent a change in the fair market value of the underlying transactions, the following other comprehensive loss at December 31, 2013 will be reclassified to earnings by December 31, 2016 with balances being recognized as follows (in millions):


	Year		Accumulated Other
	Year		Comprehensive Loss
	2014		$	(26.8	)
	2015		(22.3		)
	2016		(2.3		)
	Total		$	(51.4	)
Specialty Product \| Natural Gas Swap Contracts	'
Derivative [Line Items]	'
Schedule of Outstanding Derivative Positions	'
	At December 31, 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
	First Quarter 2014	750,000			$	4.14
	First Quarter 2014	750,000			$	4.14
	Second Quarter 2014	750,000			4.14
	Second Quarter 2014	750,000			4.14
	Third Quarter 2014	750,000			4.14
	Third Quarter 2014	750,000			4.14
	Fourth Quarter 2014	850,000			4.21
	Fourth Quarter 2014	850,000			4.21
	Calendar Year 2015	3,500,000			4.27
	Calendar Year 2015	3,500,000			4.27
	Calendar Year 2016	2,700,000			4.42
	Calendar Year 2016	2,700,000			4.42
	Calendar Year 2017	1,000,000			4.29
	Calendar Year 2017	1,000,000			4.29
	Total	10,300,000
	Total	10,300,000
	Average price				$	4.28
	Average price				$	4.28

	At December 31, 2012, the Company did not have any natural gas derivatives related to future natural gas purchases in its specialty products segment.
Fuel Product \| Crude Oil Swaps	'
Derivative [Line Items]	'
Schedule of Outstanding Derivative Positions	'
	At December 31, 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.


	Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased			BPD			Average Swap
	Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
	First Quarter 2014	2,520,000			28,000			$	92.06
	First Quarter 2014	2,520,000			28,000			$	92.06
	Second Quarter 2014	2,411,500			26,500			91.97
	Second Quarter 2014	2,411,500			26,500			91.97
	Third Quarter 2014	2,530,000			27,500			91.23
	Third Quarter 2014	2,530,000			27,500			91.23
	Fourth Quarter 2014	2,024,000			22,000			90.61
	Fourth Quarter 2014	2,024,000			22,000			90.61
	Calendar Year 2015	5,556,500			15,223			89.08
	Calendar Year 2015	5,556,500			15,223			89.08
	Calendar Year 2016	1,830,000			5,000			84.73
	Calendar Year 2016	1,830,000			5,000			84.73
	Total	16,872,000
	Total	16,872,000
	Average price							$	89.97
	Average price							$	89.97
	At December 31, 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
	Crude Oil Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
	First Quarter 2014	810,000			9,000			$	94.56
	First Quarter 2014	810,000			9,000			$	94.56
	Second Quarter 2014	591,500			6,500			94.37
	Second Quarter 2014	591,500			6,500			94.37
	Third Quarter 2014	874,000			9,500			92.92
	Third Quarter 2014	874,000			9,500			92.92
	Fourth Quarter 2014	184,000			2,000			94.62
	Fourth Quarter 2014	184,000			2,000			94.62
	Calendar Year 2015	1,004,000			2,751			89.28
	Calendar Year 2015	1,004,000			2,751			89.28
	Total	3,463,500
	Total	3,463,500
	Average price							$	92.59
	Average price							$	92.59
	At December 31, 2013, the Company had the following derivatives related to crude oil sales 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
	Crude Oil Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2014	45,000			500			$	96.9
	First Quarter 2014	45,000			500			$	96.9
	Second Quarter 2014	45,500			500			96.9
	Second Quarter 2014	45,500			500			96.9
	Third Quarter 2014	46,000			500			96.9
	Third Quarter 2014	46,000			500			96.9
	Fourth Quarter 2014	46,000			500			96.9
	Fourth Quarter 2014	46,000			500			96.9
	Total	182,500
	Total	182,500
	Average price							$	96.9
	Average price							$	96.9
	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			BPD			Average Swap
	Crude Oil Swap Contracts by Expiration Dates	Purchased			BPD			($/Bbl)
	First Quarter 2013	1,665,000			18,500			$	101.67
	First Quarter 2013	1,665,000			18,500			$	101.67
Second Quarter 2013	1,911,000			21,000			100.22
Second Quarter 2013	1,911,000			21,000			100.22
Third Quarter 2013	1,426,000			15,500			95.62
Third Quarter 2013	1,426,000			15,500			95.62
Fourth Quarter 2013	1,104,000			12,000			93.41
Fourth Quarter 2013	1,104,000			12,000			93.41
Calendar Year 2014	5,110,000			14,000			89.47
Calendar Year 2014	5,110,000			14,000			89.47
Calendar Year 2015	4,781,500			13,100			89.49
Calendar Year 2015	4,781,500			13,100			89.49
Total	15,997,500
Total	15,997,500
Average price							$	92.85
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.


Crude Oil Swap Contracts by Expiration Dates	Barrels			BPD			Average Swap
Crude Oil Swap Contracts by Expiration Dates	Purchased			BPD			($/Bbl)
First Quarter 2013	630,000			7,000			$	101.34
First Quarter 2013	630,000			7,000			$	101.34
Second Quarter 2013	455,000			5,000			98.56
Second Quarter 2013	455,000			5,000			98.56
Third Quarter 2013	368,000			4,000			96.58
Third Quarter 2013	368,000			4,000			96.58
Fourth Quarter 2013	368,000			4,000			96.58
Fourth Quarter 2013	368,000			4,000			96.58
Total	1,821,000
Total	1,821,000
Average price							$	98.72
Average price							$	98.72
Fuel Product \| Crude Oil Basis Swaps	'
Derivative [Line Items]	'
Schedule of Outstanding Derivative Positions	'
	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 crude oil, pricing differentials between LLS and NYMEX WTI and pricing differentials between MSW and NYMEX WTI. At December 31, 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
	Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
	First Quarter 2014	118,000			1,311			$	(28.50	)
	First Quarter 2014	118,000			1,311			$	(28.50	)
	Third Quarter 2014	184,000			2,000			(21.75		)
	Third Quarter 2014	184,000			2,000			(21.75		)
	Fourth Quarter 2014	184,000			2,000			(21.50		)
	Fourth Quarter 2014	184,000			2,000			(21.50		)
	Total	486,000
	Total	486,000
	Average differential							$	(23.29	)

	As of December 31, 2013, the Company had approximately 248,000 barrels of 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 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 loss of $0.6 million that has been recorded to unrealized gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2013. The net impact of these derivative instruments will be realized upon settlement in the first quarter of 2014 and will be recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations.
	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
	Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
	First Quarter 2013	180,000			2,000			$	(23.75	)
	First Quarter 2013	180,000			2,000			$	(23.75	)
	Second Quarter 2013	364,000			4,000			(27.38		)
	Second Quarter 2013	364,000			4,000			(27.38		)
	Third Quarter 2013	184,000			2,000			(23.75		)
	Third Quarter 2013	184,000			2,000			(23.75		)
	Fourth Quarter 2013	184,000			2,000			(23.75		)
	Fourth Quarter 2013	184,000			2,000			(23.75		)
	Total	912,000
	Total	912,000
	Average differential							$	(25.20	)

	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 Product \| Diesel Swaps	'
Derivative [Line Items]	'
Schedule of Outstanding Derivative Positions	'
	At December 31, 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.


	Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2014	1,125,000			12,500			$	117.54
	First Quarter 2014	1,125,000			12,500			$	117.54
	Second Quarter 2014	1,183,000			13,000			116.78
	Second Quarter 2014	1,183,000			13,000			116.78
	Third Quarter 2014	1,288,000			14,000			116.82
	Third Quarter 2014	1,288,000			14,000			116.82
	Fourth Quarter 2014	1,288,000			14,000			116.96
	Fourth Quarter 2014	1,288,000			14,000			116.96
	Calendar Year 2015	4,781,500			13,100			115.81
	Calendar Year 2015	4,781,500			13,100			115.81
	Calendar Year 2016	1,830,000			5,000			112
	Calendar Year 2016	1,830,000			5,000			112
	Total	11,495,500
	Total	11,495,500
	Average price							$	115.72
	Average price							$	115.72
	At December 31, 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			BPD			Average Swap
	Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2014	270,000			3,000			$	121.72
	First Quarter 2014	270,000			3,000			$	121.72
	Second Quarter 2014	182,000			2,000			123.22
	Second Quarter 2014	182,000			2,000			123.22
	Third Quarter 2014	230,000			2,500			121.74
	Third Quarter 2014	230,000			2,500			121.74
	Fourth Quarter 2014	184,000			2,000			123.02
	Fourth Quarter 2014	184,000			2,000			123.02
	Calendar Year 2015	1,004,000			2,751			117.15
	Calendar Year 2015	1,004,000			2,751			117.15
	Total	1,870,000
	Total	1,870,000
	Average price							$	119.54
	Average price							$	119.54
	At December 31, 2013, the Company had the following derivatives related to diesel purchases in its fuel products segment, none of which are designated as cash flow hedges.


	Diesel Swap Contracts by Expiration Dates	Barrels Purchased			BPD			Average Swap
	Diesel Swap Contracts by Expiration Dates	Barrels Purchased			BPD			($/Bbl)
	First Quarter 2014	45,000			500			$	121.8
	First Quarter 2014	45,000			500			$	121.8
	Second Quarter 2014	45,500			500			121.8
	Second Quarter 2014	45,500			500			121.8
	Third Quarter 2014	46,000			500			121.8
	Third Quarter 2014	46,000			500			121.8
	Fourth Quarter 2014	46,000			500			121.8
	Fourth Quarter 2014	46,000			500			121.8
	Total	182,500
	Total	182,500
	Average price							$	121.8
	Average price							$	121.8
	At December 31, 2012, the Company had the following derivatives related to diesel sales in its fuel products segment, all of which are designated as cash flow hedges.


	Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	Second Quarter 2013	546,000			6,000			$	122.74
	Second Quarter 2013	546,000			6,000			$	122.74
Third Quarter 2013	874,000			9,500			122.23
Third Quarter 2013	874,000			9,500			122.23
Fourth Quarter 2013	828,000			9,000			120.82
Fourth Quarter 2013	828,000			9,000			120.82
Calendar Year 2014	3,835,000			10,507			116
Calendar Year 2014	3,835,000			10,507			116
Calendar Year 2015	4,781,500			13,100			115.81
Calendar Year 2015	4,781,500			13,100			115.81
Total	10,864,500
Total	10,864,500
Average price							$	117.13
Average price							$	117.13
At December 31, 2012, 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			BPD			Average Swap
Diesel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
First Quarter 2013	540,000			6,000			$	130.57
First Quarter 2013	540,000			6,000			$	130.57
Second Quarter 2013	364,000			4,000			126.82
Second Quarter 2013	364,000			4,000			126.82
Third Quarter 2013	276,000			3,000			124.17
Third Quarter 2013	276,000			3,000			124.17
Fourth Quarter 2013	276,000			3,000			124.17
Fourth Quarter 2013	276,000			3,000			124.17
Total	1,456,000
Total	1,456,000
Average price							$	127.2
Average price							$	127.2
Fuel Product \| Jet Fuel Swap Contracts	'
Derivative [Line Items]	'
Schedule of Outstanding Derivative Positions	'
	At December 31, 2013, the Company had the following derivatives related to jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


	Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2014	450,000			5,000			$	117.5
	First Quarter 2014	450,000			5,000			$	117.5
	Second Quarter 2014	273,000			3,000			116.68
	Second Quarter 2014	273,000			3,000			116.68
	Third Quarter 2014	276,000			3,000			116.18
	Third Quarter 2014	276,000			3,000			116.18
	Fourth Quarter 2014	276,000			3,000			115.65
	Fourth Quarter 2014	276,000			3,000			115.65
	Calendar Year 2015	775,000			2,123			114.05
	Calendar Year 2015	775,000			2,123			114.05
	Total	2,050,000
	Total	2,050,000
	Average price							$	115.66
	Average price							$	115.66
	At December 31, 2013, the Company had the following derivatives to purchase jet fuel in its fuel products segment, none of which are designated as cash flow hedges:


	Jet Fuel Swap Contracts by Expiration Dates	Barrels Purchased			BPD			Average Swap ($/Bbl)
	First Quarter 2014	90,000			1,000			$	116.71
	First Quarter 2014	90,000			1,000			$	116.71
	Total	90,000
	Total	90,000
	Average price							$	116.71
	Average price							$	116.71
	At December 31, 2012, the Company had the following derivatives related to jet fuel sales in its fuel products segment, all of which are designated as cash flow hedges.


	Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Jet Fuel Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2013	1,035,000			11,500			$	127.39
	First Quarter 2013	1,035,000			11,500			$	127.39
	Second Quarter 2013	819,000			9,000			129.2
	Second Quarter 2013	819,000			9,000			129.2
	Third Quarter 2013	368,000			4,000			125.13
	Third Quarter 2013	368,000			4,000			125.13
	Fourth Quarter 2013	276,000			3,000			122.36
	Fourth Quarter 2013	276,000			3,000			122.36
	Calendar Year 2014	1,275,000			3,493			116.64
	Calendar Year 2014	1,275,000			3,493			116.64
	Total	3,773,000
	Total	3,773,000
	Average price							$	123.56
	Average price							$	123.56
Fuel Product \| Gasoline Swap Contracts	'
Derivative [Line Items]	'
Schedule of Outstanding Derivative Positions	'
	At December 31, 2013, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2014	945,000			10,500			$	104.39
	First Quarter 2014	945,000			10,500			$	104.39
	Second Quarter 2014	955,500			10,500			109.68
	Second Quarter 2014	955,500			10,500			109.68
	Third Quarter 2014	966,000			10,500			106.6
	Third Quarter 2014	966,000			10,500			106.6
	Fourth Quarter 2014	460,000			5,000			104.85
	Fourth Quarter 2014	460,000			5,000			104.85
	Total	3,326,500
	Total	3,326,500
	Average price							$	106.61
	Average price							$	106.61
	At December 31, 2013, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.


	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2014	630,000			7,000			$	105.67
	First Quarter 2014	630,000			7,000			$	105.67
	Second Quarter 2014	409,500			4,500			110.48
	Second Quarter 2014	409,500			4,500			110.48
	Third Quarter 2014	644,000			7,000			108.24
	Third Quarter 2014	644,000			7,000			108.24
	Total	1,683,500
	Total	1,683,500
	Average price							$	107.82
	Average price							$	107.82
	At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges.


	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2013	630,000			7,000			$	113.59
	First Quarter 2013	630,000			7,000			$	113.59
	Second Quarter 2013	546,000			6,000			116.32
	Second Quarter 2013	546,000			6,000			116.32
	Third Quarter 2013	184,000			2,000			114.73
	Third Quarter 2013	184,000			2,000			114.73
	Total	1,360,000
	Total	1,360,000
	Average price							$	114.84
	Average price							$	114.84
	At December 31, 2012, the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as cash flow hedges.


	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			Average Swap
	Gasoline Swap Contracts by Expiration Dates	Barrels Sold			BPD			($/Bbl)
	First Quarter 2013	90,000			1,000			$	105.5
	First Quarter 2013	90,000			1,000			$	105.5
	Second Quarter 2013	91,000			1,000			105.5
	Second Quarter 2013	91,000			1,000			105.5
	Third Quarter 2013	92,000			1,000			105.5
	Third Quarter 2013	92,000			1,000			105.5
	Fourth Quarter 2013	92,000			1,000			105.5
	Fourth Quarter 2013	92,000			1,000			105.5
	Total	365,000
	Total	365,000
	Average price							$	105.5
	Average price							$	105.5
Fuel Product \| Diesel Crack Spread Collars	'
Derivative [Line Items]	'
Schedule of Outstanding Derivative Positions	'
	At December 31, 2013, the Company had the following diesel crack spread collars related to diesel sales and crude oil purchases in its fuel products segment, none of which are designated as hedges.


	Diesel Crack Spread Collars by Expiration Dates	Barrels Purchased and Sold			BPD			Average Bought				Average Sold
	Diesel Crack Spread Collars by Expiration Dates	Barrels Purchased and Sold			BPD			Put ($/Bbl)				Call ($/Bbl)
	First Quarter 2014	90,000			1,000			$	26			$	35
	First Quarter 2014	90,000			1,000			$	26			$	35
	Second Quarter 2014	91,000			1,000			26				35
	Second Quarter 2014	91,000			1,000			26				35
	Third Quarter 2014	92,000			1,000			26				35
	Third Quarter 2014	92,000			1,000			26				35
	Fourth Quarter 2014	92,000			1,000			26				35
	Fourth Quarter 2014	92,000			1,000			26				35
	Total	365,000
	Total	365,000
	Average price							$	26			$	35
	Average price							$	26			$	35

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value, by Balance Sheet Grouping	'



				31-Dec-13								31-Dec-12
		Level		Fair Value				Carrying Value				Fair Value				Carrying Value
	Financial Instrument:

	Senior notes	1		$	863.6			$	761.2			$	658.8			$	587.6

	Senior notes	2		$	353.9			$	344.8			$	301.8			$	270.4

	Revolving credit facility	3		$	—			$	—			$	—			$	—

	Capital lease obligations	3		$	4.8			$	4.8			$	5.5			$	5.5

	The Company’s recurring assets and liabilities measured at fair value at December 31, 2013 and December 31, 2012 were as follows (in millions):



		31-Dec-13																31-Dec-12
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets:
	Derivative assets:
	Crude oil swaps	$	—			$	—			$	—			$	—			$	—		$	—		$	10.5		$	10.5

	Gasoline swaps	—				—				—				—				—			—			0.3			0.3

	Diesel swaps	—				—				—				—				—			—			(7.9		)	(7.9		)

	Jet fuel swaps	—				—				—				—				—			—			0.2			0.2

	Total derivative assets	—				—				—				—				—			—			3.1			3.1

	Pension plan investments	—				45.8				—				45.8				38.9			2.7			—			41.6

	Total recurring assets at fair value	$	—			$	45.8			$	—			$	45.8			$	38.9		$	2.7		$	3.1		$	44.7

	Liabilities:
	Derivative liabilities:
	Crude oil swaps	$	—			$	—			$	37			$	37			$	—		$	—		$	(35.8	)	$	(35.8	)

	Crude oil basis swaps	—				—				0.4				0.4				—			—			(3.4		)	(3.4		)

	Gasoline swaps	—				—				(28.1		)		(28.1		)		—			—			(0.1		)	(0.1		)

	Diesel swaps	—				—				(50.6		)		(50.6		)		—			—			(6.4		)	(6.4		)

	Jet fuel swaps	—				—				(12.4		)		(12.4		)		—			—			(2.3		)	(2.3		)

	Diesel crack spread collars	—				—				0.1				0.1				—			—			—			—

	Natural gas swaps	—				—				(1.2		)		(1.2		)		—			—			—			—

	Total derivative liabilities	—				—				(54.8		)		(54.8		)		—			—			(48.0		)	(48.0		)

	RINs Obligation	—				(5.3		)		—				(5.3		)		—			(0.8		)	—			(0.8		)

	Liability Awards	(3.7		)		—				—				(3.7		)		(2.2		)	—			—			(2.2		)

	Total recurring liabilities at fair value	$	(3.7	)		$	(5.3	)		$	(54.8	)		$	(63.8	)		$	(2.2	)	$	(0.8	)	$	(48.0	)	$	(51.0	)
Hierarchy of Recurring Fair Value Measurements	'
	The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the year ended December 31, 2013 and 2012 (in millions):


		Derivative Instruments, Net
		For the Year Ended December 31,
		2013				2012
	Fair value at January 1,	$	(44.9	)		$	14.9

	Realized (gain) loss on derivative instruments	4.7				(9.5		)

	Unrealized gain (loss) on derivative instruments	25.7				(3.8		)

	Change in fair value of cash flow hedges	(36.9		)		(215.1		)
	Settlements	(3.4		)		168.6

	Transfers in (out) of Level 3	—				—

	Fair value at December 31,	$	(54.8	)		$	(44.9	)
	Total gain (loss) included in net income attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of December 31,	$	25.7			$	(3.8	)

Partners_Capital_Partners_Capi

Partners' Capital Partner's Capital (Tables)	12 Months Ended
Partners' Capital Partner's Capital (Tables)	Dec. 31, 2013
Equity [Abstract]	'
Schedule of Incentive Distributions	'


		Total Quarterly		Marginal Percentage
		Distribution Per Common Unit		Interest in Distributions
		Target Amount		Unitholders			General Partner
	Minimum Quarterly Distribution	$0.45		98	%		2	%
	First Target Distribution	up to $0.495		98	%		2	%
	Second Target Distribution	above $0.495 up to $0.563		85	%		15	%
	Third Target Distribution	above $0.563 up to $0.675		75	%		25	%
	Thereafter	above $0.675		50	%		50	%
Public Offering of Common Units	'
	During 2013, 2012 and 2011, the Company completed the following public offerings of its common units (in millions except unit and per unit data):


	Closing Date		Number of Common Units Offered			Price per Unit			Net Proceeds (1)		General Partner Contribution (2)		Underwriting Discount		Use of Proceeds
	February 24, 2011		4,500,000			$	21.45		$	92.3	$	2	$	3.9	Net proceeds were used to repay borrowings under the revolving credit facility.
	February 24, 2011		4,500,000			$	21.45		$	92.3	$	2	$	3.9
	September 8, 2011		11,750,000		-3	$	18		$	202.4	$	4.3	$	8.4	Net proceeds were used to fund a portion of the purchase price of the Superior acquisition and repay borrowings under the revolving credit facility.
	September 8, 2011		11,750,000		-3	$	18		$	202.4	$	4.3	$	8.4
	May 8, 2012		6,000,000			$	25.5		$	146.6	$	3.1	$	6.2	Net proceeds were used to repay borrowings under the revolving credit facility.
	May 8, 2012		6,000,000			$	25.5		$	146.6	$	3.1	$	6.2
	January 8, 2013		5,750,000		-4	$	31.81		$	175.2	$	3.8	$	7.4	Net proceeds were used to repay borrowings under the revolving credit facility and for general partnership purposes.
	January 8, 2013		5,750,000		-4	$	31.81		$	175.2	$	3.8	$	7.4
	April 1, 2013		6,037,500		-5	$	37.5		$	217.3	$	4.6	$	9.1	Net proceeds were used for general partnership purposes.
	April 1, 2013		6,037,500		-5	$	37.5		$	217.3	$	4.6	$	9.1	Net proceeds were used for general partnership purposes.




	-1	Proceeds are net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution.

	-2	The Company’s general partner contributions were made to retain its 2% general partner interest.

	-3	Includes the partial exercise of the overallotment option of 750,000 common units which closed on October 13, 2011.

	-4	Includes the full exercise of the overallotment option of 750,000 common units which closed concurrently with the 5,000,000 firm units on January 8, 2013.

	-5	Includes the full exercise of the overallotment option of 787,500 common units which closed on April 4, 2013.

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Summary of the Company's nonvested phantom units	'
	A summary of the Company’s nonvested phantom units as of December 31, 2013, and the changes during the years ended December 31, 2013, 2012 and 2011, are presented below:


		Number of		Weighted-Average
		Phantom Units		Grant Date
				Fair Value
	Non-vested at January 1, 2011	105,492		$	17.68

	Granted	640,875		20.26

	Vested	(183,671	)	20.29

	Forfeited	—		—

	Non-vested at December 31, 2011	562,696		$	19.77

	Granted	616,997		26.69

	Vested	(286,976	)	21.16

	Forfeited	(56,790	)	20

	Non-vested at December 31, 2012	835,927		$	27.57

	Granted	483,044		27.73

	Vested	(276,115	)	24.22

	Forfeited	(354,600	)	30.6

	Non-vested at December 31, 2013	688,256		$	23.7

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
Employee Benefit Plans (Tables)	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Contribution Expenses	'


		Year Ended December 31,
		2013				2012				2011
	401(k) Plan matching contribution expense	$	4.1			$	3.2			$	2.3
	401(k) Plan matching contribution expense	$	4.1			$	3.2			$	2.3
	Profit sharing expense	0.9				2.5				1.4
	Profit sharing expense	0.9				2.5				1.4
Schedule of Changes in Projected Benefit Obligations	'
	The change in the benefit obligations, change in the plan assets, funded status and amounts recognized in the consolidated balance sheets were as follows (in millions):


		Year Ended December 31,
		2013								2012
		Pension				Other Plan				Pension			Other Plan
		Plan				Other Plan				Plan			Other Plan
	Change in projected benefit obligation:
	Benefit obligation at beginning of year	$	65.3			$	0.3			$	55.3		$	7.7
	Benefit obligation at beginning of year	$	65.3			$	0.3			$	55.3		$	7.7
	Projected benefit obligation attributable to acquisitions	—				—				4.9			—
	Projected benefit obligation attributable to acquisitions	—				—				4.9			—
	Service cost	0.4				—				1.1			0.3
	Service cost	0.4				—				1.1			0.3
	Interest cost	2.4				—				2.4			0.2
	Interest cost	2.4				—				2.4			0.2
	Plan curtailments	—				—				(3.7		)	(7.9		)
	Plan curtailments	—				—				(3.7		)	(7.9		)
	Benefits paid	(2.3		)		—				(2.6		)	(0.1		)
	Benefits paid	(2.3		)		—				(2.6		)	(0.1		)
	Actuarial (gain) loss	(8.5		)		—				7.9			0.1
	Actuarial (gain) loss	(8.5		)		—				7.9			0.1
	Administrative expense	(0.1		)		—				—			—
	Administrative expense	(0.1		)		—				—			—
	Plan amendments	—				—				—			(0.1		)
	Plan amendments	—				—				—			(0.1		)
	Employee contributions	—				—				—			0.1
	Employee contributions	—				—				—			0.1
	Benefit obligation at end of year	$	57.2			$	0.3			$	65.3		$	0.3
	Benefit obligation at end of year	$	57.2			$	0.3			$	65.3		$	0.3
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	41.6			$	—			$	36		$	—
	Fair value of plan assets at beginning of year	$	41.6			$	—			$	36		$	—
	Fair value of pension assets attributable to acquisitions	—				—				3.2			—
	Fair value of pension assets attributable to acquisitions	—				—				3.2			—
	Benefit payments	(2.3		)		—				(2.6		)	(0.1		)
	Benefit payments	(2.3		)		—				(2.6		)	(0.1		)
	Actual return on assets	3.2				—				1.9			—
	Actual return on assets	3.2				—				1.9			—
	Administrative expense	(0.1		)		—				—			—
	Administrative expense	(0.1		)		—				—			—
	Employee contributions	—				—				—			0.1
	Employee contributions	—				—				—			0.1
	Employer contribution	3.4				—				3.1			—
	Employer contribution	3.4				—				3.1			—
	Fair value of plan assets at end of year	$	45.8			$	—			$	41.6		$	—
	Fair value of plan assets at end of year	$	45.8			$	—			$	41.6		$	—
	Funded status — benefit obligation in excess of plan assets	$	(11.4	)		$	(0.3	)		$	(23.7	)	$	(0.3	)
	Reconciliation of amounts recognized in the consolidated balance sheets:
	Accrued benefit obligation, long-term	$	(11.4	)		$	(0.3	)		$	(23.7	)	$	(0.3	)
	Prior service credit	—				(0.2		)		—			(0.2		)
	Prior service credit	—				(0.2		)		—			(0.2		)
	Unrecognized net actuarial (gain) loss	2.3				(0.2		)		11.9			(0.2		)
	Unrecognized net actuarial (gain) loss	2.3				(0.2		)		11.9			(0.2		)
	Accumulated other comprehensive (income) loss	2.3				(0.4		)		11.9			(0.4		)
	Accumulated other comprehensive (income) loss	2.3				(0.4		)		11.9			(0.4		)
	Net amount recognized at end of year	$	(9.1	)		$	(0.7	)		$	(11.8	)	$	(0.7	)
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	'
	Selected information for the Company’s pension plans with an accumulated benefit obligation in excess of plan assets were as follows (in millions):


		Year Ended December 31,
		2013				2012
	Accumulated benefit obligation	$	52.9			$	63.4
	Accumulated benefit obligation	$	52.9			$	63.4
	Fair value of plan assets	41.8				41.6
	Fair value of plan assets	41.8				41.6
Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets	'
	Selected information for the Company’s Pension Plan with projected benefit obligation in excess of plan assets were as follows (in millions):


		Year Ended December 31,
		2013				2012
	Projected benefit obligation	$	57.2			$	65.3
	Projected benefit obligation	$	57.2			$	65.3
	Fair value of plan assets	$	45.8			$	41.6
	Fair value of plan assets	$	45.8			$	41.6
Components of Net Periodic Pension and Other Post Retirement Benefits Cost	'
	The components of net periodic pension cost and other post retirement benefits cost (income) for 2013, 2012 and 2011 were as follows (in millions):


		Pension Plan											Other Plan
		Year Ended December 31,											Year Ended December 31,
		2013				2012				2011			2013			2012			2011
	Service cost	$	0.4			$	1.1			$	0.3		$	—		$	0.3		$	0.1
	Service cost	$	0.4			$	1.1			$	0.3		$	—		$	0.3		$	0.1
	Interest cost	2.4				2.4				1.6			—			0.2			0.1
	Interest cost	2.4				2.4				1.6			—			0.2			0.1
	Expected return on assets	(2.9		)		(1.7		)		(1.2		)	—			—			—
	Expected return on assets	(2.9		)		(1.7		)		(1.2		)	—			—			—
	Amortization of net loss	0.8				0.6				0.2			—			—			—
	Amortization of net loss	0.8				0.6				0.2			—			—			—
	Curtailment gain recognized	—				(0.2		)		—			—			(7.0		)	—
	Curtailment gain recognized	—				(0.2		)		—			—			(7.0		)	—
	Settlement gain recognized	—				—				—			—			(0.2		)	—
	Settlement gain recognized	—				—				—			—			(0.2		)	—
	Net periodic benefit cost (income)	$	0.7			$	2.2			$	0.9		$	—		$	(6.7	)	$	0.2
	Net periodic benefit cost (income)	$	0.7			$	2.2			$	0.9		$	—		$	(6.7	)	$	0.2
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)	'
	The components of changes recognized in other comprehensive (income) loss for the Pension Plan and Other Plan for 2013, 2012 and 2011 were as follows (in millions):


		Pension Plan											Other Plan
		Year Ended December 31,											Year Ended December 31,
		2013				2012				2011			2013			2012			2011
	Changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
	Net (gain) loss	$	(8.8	)		$	4.3			$	3.3		$	—		$	0.1		$	0.6
	Net (gain) loss	$	(8.8	)		$	4.3			$	3.3		$	—		$	0.1		$	0.6
	New prior service cost	—				—				—			—			(0.1		)	—
	New prior service cost	—				—				—			—			(0.1		)	—
	Amounts recognized as a component of net periodic benefit cost:

	Amortization or settlement recognition of net loss	(0.8		)		(0.6		)		(0.2		)	—			(0.8		)	—
	Amortization or settlement recognition of net loss	(0.8		)		(0.6		)		(0.2		)	—			(0.8		)	—
	Amortization or curtailment recognition of prior service credit	—				—				—			—			0.1			—
		—				—				—			—			0.1			—
	Total recognized in other comprehensive (income) loss	$	(9.6	)		$	3.7			$	3.1		$	—		$	(0.7	)	$	0.6
	Total recognized in other comprehensive (income) loss	$	(9.6	)		$	3.7			$	3.1		$	—		$	(0.7	)	$	0.6
Schedule of Assumptions Used	'
	The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2013 and 2012 were as follows:


		Benefit Obligations
		Assumptions
		2013			2012
	Pension Plan:
	Discount rate for Penreco Pension Plan	4.78	%		3.86	%
	Discount rate for Superior Pension Plan	4.66	%		3.75	%
	Discount rate for Montana Pension Plan	4.97	%		4.03	%
	Rate of compensation increase for Montana Pension Plan	3	%		3	%
	Other Plan:
	Discount rate for Penreco Other Plan	4.29	%		3.33	%
	Immediate trend rate for Penreco Other Plan (1)	7.5	%		7.7	%
	Ultimate trend rate for Penreco Other Plan (1)	4.5	%		4.5	%
	Year that the rate reaches ultimate trend rate for Penreco Other Plan (1)	2029			2029
		2029			2029




	-1	For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% in 2029 for the Penreco Other Plan and remain at that level thereafter.
	The significant weighted average assumptions used to determine the net periodic benefit cost (income) for the years ended December 31, 2013 and 2012 were as follows:


		Net Periodic Benefit Cost (Income)
		Assumptions
		2013			2012			2011
	Pension Plan:
	Discount rate for Penreco Pension Plan	3.86	%		4.63	%		5.5	%
	Discount rate for Superior Pension Plan	3.75	%		4.55	%		4.71	%
	Discount rate for Montana Pension Plan	4.03	%		3.89	%		N/A
	Discount rate for Montana Pension Plan	4.03	%		3.89	%		N/A
	Expected return on plan assets for Penreco Pension Plan (1)	6.75	%		6	%		6.5	%
	Expected return on plan assets for Superior Pension Plan (1)	6.75	%		3	%		6.5	%
	Expected return on plan assets for Montana Pension Plan (1)	6.75	%		6	%		N/A
	Expected return on plan assets for Montana Pension Plan (1)	6.75	%		6	%		N/A
	Rate of compensation increase for Superior Pension Plan	N/A			3.75	%		3.75	%
	Rate of compensation increase for Superior Pension Plan	N/A			3.75	%		3.75	%
	Rate of compensation increase for Montana Pension Plan	3	%		3	%		N/A
	Rate of compensation increase for Montana Pension Plan	3	%		3	%		N/A
	Other Plan:
	Discount rate for Penreco Other Plan	3.33	%		4.04	%		4.54	%
	Discount rate for Superior Other Plan	N/A			4.65	%		4.82	%
	Discount rate for Superior Other Plan	N/A			4.65	%		4.82	%
	Immediate trend rate (2)	7.7	%		8	%		8.2	%
	Ultimate trend rate for Penreco Other Plan (2)	4.5	%		4.5	%		4.5	%
	Ultimate trend rate for Superior Other Plan (2)	N/A			4.5	%		5	%
	Ultimate trend rate for Superior Other Plan (2)	N/A			4.5	%		5	%
	Year that the rate reaches ultimate trend rate for Penreco Other Plan (2)	2029			2029			2029
		2029			2029			2029
	Year that the rate reaches ultimate trend rate for Superior Other Plan (2)	N/A			2029			2020
		N/A			2029			2020




	-1	The Company considered the historical returns and the future expectation for returns for each asset class, as well as the target asset allocation of the Pension Plan portfolio which was developed in accordance with the Company’s Statement of Investment Policy, to develop the expected long-term rate of return on plan assets.

	-2	For measurement purposes, an annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013. The rate was assumed to decrease by 0.20% per year for an ultimate rate of 4.50% for 2029 for the Penreco Other Plan and remain at that level thereafter.
Schedule of Allocation of Plan Assets	'
	The Pension Plan’s target asset allocation is currently comprised of the following:


	Asset Class	Range of		Target
	Asset Class	Asset Allocation		Allocation
	Domestic equities	0 — 50%		25	%
	Foreign equities	0 — 50%		25	%
	Fixed income	50 — 100%		50	%
	The Company’s Pension Plan asset allocations, as of December 31, 2013 and 2012 by asset category, are as follows:


		2013			2012
	Cash and cash equivalents (1)	—	%		46	%
	Domestic equities	23	%		14	%
	Foreign equities	23	%		6	%
	Fixed income	54	%		20	%
	Commingled fund	—	%		7	%
	Balanced fund	—	%		7	%
		100	%		100	%




	-1	The Superior Pension Plan assets were included in cash and cash equivalents in 2012 and such assets were invested in 2013 based upon the current investment policy.
Schedule of Pension Plan assets measured at fair value	'
	The Company’s Pension Plan assets measured at fair value at December 31, 2013 and 2012 were as follows (in millions):


		Fair Value of Pension Assets at December 31,
		2013								2012
		Level 1				Level 2				Level 1			Level 2
	Cash and cash equivalents	$	—			$	—			$	19.3		$	—
	Cash and cash equivalents	$	—			$	—			$	19.3		$	—
	Domestic equities	—				10.6				5.9			—
	Domestic equities	—				10.6				5.9			—
	Foreign equities	—				10.6				2.3			—
	Foreign equities	—				10.6				2.3			—
	Fixed income	—				24.6				8.4			—
	Fixed income	—				24.6				8.4			—
	Commingled fund	—				—				—			2.7
	Commingled fund	—				—				—			2.7
	Balanced fund	—				—				3			—
	Balanced fund	—				—				3			—
		$	—			$	45.8			$	38.9		$	2.7
		$	—			$	45.8			$	38.9		$	2.7
Schedule of Expected Benefit Payments	'
	The following benefit payments for the Pension Plans, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2013 (in millions):


		Pension
		Benefits
	2014	$	2.5
	2014	$	2.5
	2015	2.6
	2015	2.6
	2016	2.7
	2016	2.7
	2017	2.8
	2017	2.8
	2018	3
	2018	3
	2019 to 2023	17.1
	2019 to 2023	17.1
	Total	$	30.7
	Total	$	30.7

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
Accumulated Other Comprehensive Income (Loss) (Tables)	Dec. 31, 2013
Equity [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	The table below sets forth a summary of changes in accumulated other comprehensive loss by component for the year ended December 31, 2013 (in millions):


		Derivatives				Defined Benefit Pension And Retiree Health Benefit Plans			Foreign Currency Translation Adjustment			Total
	Accumulated other comprehensive loss at December 31, 2012	$	(14.0	)		$	(11.5	)	$	—		$	(25.5	)
	Accumulated other comprehensive loss at December 31, 2012	$	(14.0	)		$	(11.5	)	$	—		$	(25.5	)
	Other comprehensive income (loss) before reclassifications	(36.9		)		8.8			(0.1		)	(28.2		)
	Other comprehensive income (loss) before reclassifications	(36.9		)		8.8			(0.1		)	(28.2		)
	Amounts reclassified from accumulated other comprehensive loss	(0.5		)		0.8			—			0.3
		(0.5		)		0.8			—			0.3
	Net current period other comprehensive income (loss)	(37.4		)		9.6			(0.1		)	(27.9		)
	Net current period other comprehensive income (loss)	(37.4		)		9.6			(0.1		)	(27.9		)
	Accumulated other comprehensive loss at December 31, 2013	$	(51.4	)		$	(1.9	)	$	(0.1	)	$	(53.4	)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	'
	The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive loss in the Company’s consolidated statements of operations for the year ended December 31, 2013 (in millions):


	Components of Accumulated Other Comprehensive Loss		Amount Reclassified From Accumulated Other Comprehensive Loss				Location of Gain (Loss)
	Components of Accumulated Other Comprehensive Loss						Location of Gain (Loss)
	Derivative gains (losses) reflected in gross profit
			$	(3.1	)		Sales
			3.6				Cost of sales
			3.6				Cost of sales
			$	0.5			Total
			$	0.5			Total

	Amortization of defined benefit pension benefit plans:
	Amortization of net loss		$	(0.8	)		-1
			$	(0.8	)		Total
	________________________

	-1	This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 12 for additional information.

Earnings_Per_Unit_Tables

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Unit [Abstract]	'
Earnings per Unit	'
	The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended December 31, 2013, 2012 and 2011 (in millions, except unit and per unit data):


		Year Ended December 31,
		2013			2012		2011

	Numerator for basic and diluted earnings per limited partner unit:
	Net income	$	3.5		$	205.7	$	43

	Less:
	General partner’s interest in net income	0.1			4.1		0.9

	General partner’s incentive distribution rights	14.7			5.5		0.2

	Nonvested share based payments	0.2			1.1		—

	Net income (loss) available to limited partners	$	(11.5	)	$	195	$	41.9

	Denominator for basic and diluted earnings per limited partner unit:
	Basic weighted average limited partner units outstanding	67,938,784			55,559,183		42,598,876

	Effect of dilutive securities:

	Participating securities — phantom units	—			117,558		45,210

	Diluted weighted average limited partner units outstanding (1)	67,938,784			55,676,741		42,644,086

	Limited partners’ interest basic net income (loss) per unit	$	(0.17	)	$	3.51	$	0.98

	Limited partners’ interest diluted net income (loss) per unit	$	(0.17	)	$	3.5	$	0.98

	_____________
	(1) Total diluted weighted average limited partner units outstanding excludes 0.2 million potentially dilutive phantom units for the year ended December 31, 2013.

Segments_and_Related_Informati2

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Reportable segment information	'


	Year Ended December 31, 2013	Specialty				Fuel				Combined				Eliminations				Consolidated
		Products				Products				Segments								Total
	Sales:
	External customers	$	1,774.90			$	3,646.50			$	5,421.40			$	—			$	5,421.40

	Intersegment sales	—				77.3				77.3				(77.3		)		—

	Total sales	$	1,774.90			$	3,723.80			$	5,498.70			$	(77.3	)		$	5,421.40

	Adjusted EBITDA	$	194.5			$	47			$	241.5			—				$	241.5

	Reconciling items to net income:
	Depreciation and amortization	66.6				67.1				133.7				—				133.7

	Realized loss on derivatives, not reflected in net income	(0.5		)		(1.3		)		(1.8		)		—				(1.8		)

	Unrealized gain on derivatives																	(25.7		)
	Interest expense																	96.8

	Debt extinguishment costs																	14.6

	Non-cash equity based compensation and other non-cash items																	20

	Income tax expense																	0.4

	Net income																	$	3.5



	Year Ended December 31, 2012	Specialty				Fuel				Combined				Eliminations				Consolidated
		Products				Products				Segments								Total
	Sales:
	External customers	$	1,849.90			$	2,807.40			$	4,657.30			$	—			$	4,657.30

	Intersegment sales	—				50.2				50.2				(50.2		)		—

	Total sales	$	1,849.90			$	2,857.60			$	4,707.50			$	(50.2	)		$	4,657.30

	Adjusted EBITDA	$	283.2			$	121.4			$	404.6			—				$	404.6

	Reconciling items to net income:
	Depreciation and amortization	55.8				49.2				105				—				105

	Realized loss on derivatives, not reflected in net income	(1.9		)		(3.1		)		(5.0		)		—				(5.0		)

	Unrealized loss on derivatives																	3.8

	Interest expense																	85.6

	Non-cash equity based compensation and other non-cash items																	8.7

	Income tax expense																	0.8

	Net income																	$	205.7



	Year Ended December 31, 2011	Specialty				Fuel				Combined				Eliminations				Consolidated
		Products				Products				Segments								Total
	Sales:
	External customers	$	1,630.50			$	1,504.40			$	3,134.90			$	—			$	3,134.90

Intersegment sales	—				45.8				45.8				(45.8		)		—

Total sales	$	1,630.50			$	1,550.20			$	3,180.70			$	(45.8	)		$	3,134.90

Adjusted EBITDA	$	280.6			$	(69.6	)		$	211			$	—			$	211

Reconciling items to net income:
Depreciation and amortization	43.2				31.3				74.5				—				74.5

Realized gain on derivatives, not reflected in net income	2.5				8.4				10.9				—				10.9

Unrealized loss on derivatives																	10.4

Interest expense																	48.7

Debt extinguishment costs																	15.1

Non-cash equity based compensation and other non-cash items																	7.4

Income tax expense																	1

Net income																	$	43

Major product category sales	'
	The following table sets forth the major product category sales (in millions):


		Year Ended December 31,
		2013							2012							2011
	Specialty products:
	Lubricating oils	$	848.8			15.7	%		$	1,007.90			21.6	%		$	947.8			30.2	%

	Solvents	511.7				9.4	%		491.1				10.5	%		495.9				15.8	%

	Waxes	141				2.6	%		142.8				3.1	%		143.1				4.6	%

	Packaged and synthetic specialty products	233.6				4.3	%		161.7				3.5	%		—				—	%

	Other	39.8				0.7	%		46.4				1	%		43.7				1.4	%

	Total	1,774.90				32.7	%		1,849.90				39.7	%		1,630.50				52	%

	Fuel products:
	Gasoline	1,409.40				26	%		1,174.90				25.2	%		619.6				19.8	%

	Diesel	1,259.20				23.3	%		941				20.2	%		513.3				16.4	%

	Jet fuel	191.4				3.5	%		184				4	%		148				4.7	%

	Asphalt, heavy fuel oils and other	786.5				14.5	%		507.5				10.9	%		223.5				7.1	%

	Total	3,646.50				67.3	%		2,807.40				60.3	%		1,504.40				48	%

	Consolidated sales	$	5,421.40			100	%		$	4,657.30			100	%		$	3,134.90			100	%

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Quarterly Financial Data (Unaudited)	'
	The table below sets forth selected quarterly financial data for each of the last two fiscal years (in millions, except unit and per unit data):


		First		Second		Third			Fourth			Total (1)
		Quarter		Quarter		Quarter			Quarter
	2013
	Sales	$	1,318.60	$	1,354.20	$	1,505.50		$	1,243.10		$	5,421.40

	Gross profit	134.4		101		62.1			112.5			410

	Net income (loss)	46		7.8		(34.8		)	(15.5		)	3.5

	Net income (loss) available to limited partners	41.7		3.8		(37.9		)	(19.0		)	(11.5		)

	Limited partners’ interest basic net income (loss) per unit	$	0.67	$	0.05	$	(0.54	)	$	(0.27	)	$	(0.17	)

	Limited partners’ interest diluted net income (loss) per unit	$	0.66	$	0.05	$	(0.54	)	$	(0.27	)	$	(0.17	)

	Weighted average limited partner units outstanding — basic	62,831,155		69,571,855		69,626,650			69,635,865

	Weighted average limited partner units outstanding — diluted	63,017,869		69,769,536		69,626,650			69,635,865



		First		Second		Third			Fourth			Total (1)
		Quarter		Quarter		Quarter			Quarter
	2012
	Sales	$	1,169.60	$	1,087.00	$	1,179.80		$	1,220.90		$	4,657.30

	Gross profit	84.2		128.8		158.4			141.8			513.2

	Net income	51.9		65.7		42.4			45.7			205.7

	Net income available to limited partners	50.1		62.9		39.7			42.3			195

	Limited partners’ interest basic net income per unit	$	0.97	$	1.14	$	0.69		$	0.73		$	3.51

	Limited partners’ diluted net income per unit	$	0.97	$	1.14	$	0.69		$	0.73		$	3.5

	Weighted average limited partner units outstanding — basic	51,684,741		55,027,786		57,745,806			57,745,881

	Weighted average limited partner units outstanding — diluted	51,736,396		55,074,265		57,825,603			57,898,207





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

Description_of_the_Business_De

Description of the Business (Details)	12 Months Ended
Description of the Business (Details)	Dec. 31, 2013	Dec. 31, 2012
Limited Partners	'	'
Organization, Consolidation and Presentation of Financial Statements	'	'
Limited Partners' Capital Account, Units Outstanding	69,317,278	57,529,778
Incentive distribution rights	98.00%	'
General Partner	'	'
Organization, Consolidation and Presentation of Financial Statements	'	'
Number of units	1,414,638	'
Incentive distribution rights	2.00%	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Activity in Allowance for Doubtful Accounts	'	'	'
Beginning balance	$1.20	$0.90	$0.60
Provision	0.1	0	0.4
Recoveries	0	0.4	0
Write-offs, net	-0.1	-0.1	-0.1
Ending balance	$1.20	$1.20	$0.90
Specialty Product \| Minimum	'	'	'
Account Receivable	'	'	'
Accounts receivable due within	'30 days	'	'
Specialty Product \| Maximum	'	'	'
Account Receivable	'	'	'
Accounts receivable due within	'45 days	'	'
Fuel Product	'	'	'
Account Receivable	'	'	'
Accounts receivable due within	'10 days	'	'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Inventories	'	'	'
Raw materials	$122.70	$85.40	'
Work in process	102.6	119.5	'
Finished goods	342.1	348.7	'
Inventories total	567.4	553.6	'
Higher replacement cost of inventories, based on current market values	32.2	38.3	'
Gain (Loss) due to Liquidation of Inventory Layers	4.2	-4.2	5.2
Losses due to lower of cost or market valuation	-6	-8.1	-2
Cost of Inventories Determined	'last-in, first-out (LIFO)	'	'
Consignment inventory	$2.60	$2.30	'

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Details 2) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

In Millions, unless otherwise specified

Land

Building and improvements

Machinery and equipment

Furniture and fixtures

Assets under capital leases

Construction-in-progress

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment, Useful Life

'10 years

'40 years

'10 years

'20 years

'5 years

'10 years

'28 years

Property, Plant and Equipment, Net, by Type

Property, plant and equipment, gross

$1,538.40

$1,284.80

$17.60

$11.20

$39.10

$28.10

$1,327.40

$1,173

$21.70

$7.60

$11.10

$121.50

$53.80

Less accumulated depreciation

-378

-297.9

-5

-4.3

Property, plant and equipment, net

$1,160.40

$986.90

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized Interest Costs	'	'	'
Interest Costs Capitalized in PPE	$4.40	$0.70	$0.60
Interest Costs Incurred	101.2	86.3	49.3
Depreciation [Abstract]	'	'	'
Depreciation	92	74.3	55.5
Capitalized Computer Software [Abstract]	'	'	'
Capitalized Computer Software, Net	17.3	15	'
Assets under capital leases	'	'	'
Depreciation [Abstract]	'	'	'
Depreciation	0.7	1	1.1
Software developed or obtained	'	'	'
Depreciation [Abstract]	'	'	'
Property, Plant and Equipment, Useful Life	'5 years	'	'
Capitalized Computer Software [Abstract]	'	'	'
Amortization	$3.30	$1	$0.40

Summary_of_Significant_Account7

Summary of Significant Accounting Policies (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Reviews for goodwill impairment annually on	1-Oct-13	'	'
Goodwill impairment losses	$0	$0	$0
Impairment of Intangible Assets, Finite-lived	$0	$0	$0

Summary_of_Significant_Account8

Summary of Significant Accounting Policies (Details 5) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Deferred debt issuance costs	$29.70	$29.40
Accumulated amortization, deferred debt issuance costs	13.6	6.6
Capitalized major maintenance and repairs	67	14.3
Accumulated amortization, capitalized major maintenance and repairs	$25.70	$17.80

Summary_of_Significant_Account9

Summary of Significant Accounting Policies (Details 6) (Specialty Product, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Specialty Product	'	'
Accounting Policies [Line Items]	'	'
Impairment of long-lived assets held-for-use	$10.50	$1.60

Recovered_Sheet1

Summary of Significant Accounting Policies (Details 7) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Unrecognized Tax Benefits	$0	$0

Recovered_Sheet2

Summary of Significant Accounting Policies (Details 8) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Shipping and handling costs	$142.70	$107.90	$94.20

Recovered_Sheet3

Summary of Significant Accounting Policies (Details 9) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Advertising expense	$14.60	$8.20	$1.70

Acquisitions_Details

Acquisitions (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 10, 2013	Aug. 09, 2013	Jan. 02, 2013	Oct. 02, 2012	Jul. 03, 2012	Jan. 06, 2012	Jan. 03, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Bel-ray Acquisition	Crude Oil Logistics Acquisition	San Antonio Acquisition	Montana Acquisition	Royal Purple Acquisition	Calumet Packaging Acquisition	Missouri Acquisition
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'
Accounts receivable	'	'	'	$4.30	$0	$0	$29	$15.20	$5.20	$0
Inventories	'	'	'	11.1	0	17	43.7	19.3	8	2.7
Prepaid expenses and other current assets	'	'	'	0.6	0.1	0	23.1	0.2	0.3	0
Deposits	'	'	'	0	0	0	0.3	0	0	0
Property, plant and equipment	'	'	'	6.5	0.9	100.7	125.4	10.6	17.7	10
Goodwill	207	187	48.3	9.1	5.2	5.7	27.6	109.2	0.4	1.5
Other intangible assets	'	'	'	41.4	0	0	0	183.4	2.6	5.4
Other noncurrent assets, net	'	'	'	0.3	0	0	0.3	0	0	0
Accounts payable	'	'	'	-3.9	0	0	-8.4	-3.8	-2.7	0
Accrued salaries, wages and benefits	'	'	'	-1.3	0	-0.1	-1.4	-1.7	-0.2	0
Deferred income tax liability	'	'	'	0	0	0	-27.6	0	0	0
Accrued income taxes payable	'	'	'	0	0	0	-15.6	0	0	0
Other taxes payable	'	'	'	-1.7	0	0	-3	-0.2	0	0
Other current liabilities	'	'	'	-0.8	0	-5.4	-0.1	-1	-0.9	0
Current portion of long-term debt	'	'	'	-11.9	0	0	0	0	0	0
Long-term debt	'	'	'	0	0	0	0	0	-3.5	0
Pension and postretirement benefit obligations	'	'	'	0	0	0	-1.7	0	0	0
Other long-term liabilities	'	'	'	-0.1	0	0	0	0	0	0
Total purchase price, net of cash acquired	'	'	'	$53.60	$6.20	$117.90	$191.60	$331.20	$26.90	$19.60

Acquisitions_Details_1

Acquisitions (Details 1) (USD $)

0 Months Ended

In Millions, unless otherwise specified

Dec. 12, 2013

Dec. 10, 2013

Dec. 12, 2013

Dec. 10, 2013

Dec. 12, 2013

Dec. 10, 2013

Dec. 12, 2013

Dec. 10, 2013

Dec. 12, 2013

Dec. 10, 2013

Jul. 05, 2012

Jul. 03, 2012

Jul. 05, 2012

Jul. 03, 2012

Jul. 05, 2012

Jul. 03, 2012

Jul. 05, 2012

Jul. 03, 2012

Jan. 08, 2012

Jan. 06, 2012

Jan. 08, 2012

Jan. 06, 2012

Jan. 08, 2012

Jan. 06, 2012

Jan. 08, 2012

Jan. 06, 2012

Jan. 05, 2012

Jan. 03, 2012

Jan. 05, 2012

Jan. 03, 2012

Bel-ray Acquisition

Royal Purple Acquisition

Calumet Packaging Acquisition

Missouri Acquisition

Tradenames

Customer relationships

Tradenames

Trade secrets

Non-competition agreements

Tradenames

Customer relationships

Tradenames

Trade secrets

Non-competition agreements

Tradenames

Customer relationships

Tradenames

Trade secrets

Non-competition agreements

Tradenames

Customer relationships

Tradenames

Trade secrets

Non-competition agreements

Component of intangible asset

Amount

$41.40

$28.60

$4.20

$8.50

$0.10

$183.40

$14.80

$118.70

$5.70

$44.20

$2.60

$1.80

$0.70

$0.10

$5.40

Life

'26 years

'30 years

'18 years

'3 years

'18 years

'20 years

'10 years

'12 years

'14 years

'16 years

'9 years

'2 years

'20 years

Acquisitions_Details_2

Acquisitions (Details 2) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Result of sales and operating income	'	'	'
Sales	$480.10	$266.10	$341.20
Operating income	-22.5	18.6	18
Business Acquisition, Pro Forma Information [Abstract]	'	'	'
Pro Forma Sales	'	5,626.10	'
Pro Forma Net income	'	$189.20	'
Pro Forma Limited partnersâ€™ interest net income per unit â€” basic	'	$2.61	'
Pro Forma Limited partnersâ€™ interest net income per unit â€” diluted	'	$2.60	'

Acquisitions_Details_3

Acquisitions (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 10, 2013	Aug. 09, 2013	Jan. 02, 2013	Oct. 02, 2012	Jul. 03, 2012	Jan. 06, 2012	Jan. 03, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Bel-ray Acquisition	Crude Oil Logistics Acquisition	San Antonio Acquisition	Montana Acquisition	Royal Purple Acquisition	Calumet Packaging Acquisition	Missouri Acquisition
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'
Goodwill	$207	$187	$48.30	$9.10	$5.20	$5.70	$27.60	$109.20	$0.40	$1.50

Acquisitions_Details_4

Acquisitions (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Bel-ray Acquisition	'	'
Business Acquisition [Line Items]	'	'
Acquisition costs	$0.40	$0
Crude Oil Logistics Acquisition	'	'
Business Acquisition [Line Items]	'	'
Acquisition costs	0.2	0
San Antonio Acquisition	'	'
Business Acquisition [Line Items]	'	'
Acquisition costs	0.5	0
Montana Acquisition	'	'
Business Acquisition [Line Items]	'	'
Acquisition costs	0.1	3.3
Royal Purple Acquisition	'	'
Business Acquisition [Line Items]	'	'
Acquisition costs	0	0.4
Calumet Packaging Acquisition	'	'
Business Acquisition [Line Items]	'	'
Acquisition costs	0	0.2
Missouri Acquisition	'	'
Business Acquisition [Line Items]	'	'
Acquisition costs	$0	$0.50

Acquisition_Details_Textual

Acquisition (Details Textual) (USD $)	Jan. 02, 2013	Aug. 09, 2013	Nov. 26, 2013	Dec. 31, 2013	Dec. 31, 2012	Jun. 29, 2012	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	San Antonio Acquisition	Crude Oil Logistics Acquisition	7 5/8% Senior Notes	7 5/8% Senior Notes	7 5/8% Senior Notes	9 5/8% Senior Notes	9 5/8% Senior Notes	9 5/8% Senior Notes
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'
Senior Notes, Noncurrent	'	'	'	$350	$0	'	$275	$275
Senior Notes Proceeds, Net of Discount, Underwriters' Fees and Expenses	'	'	$337.40	'	'	$262.50	'	'
Debt Instrument, Maturity Date	'	'	15-Jan-22	'	'	1-Aug-20	'	'
Production Capacity	17,500	10,000	'	'	'	'	'	'

Investment_in_Unconsolidated_A1

Investment in Unconsolidated Affiliate (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Feb. 07, 2013	Feb. 07, 2013	Feb. 07, 2013	Feb. 07, 2013
In Millions, unless otherwise specified			Dakota Prairie Refining, LLC	Proceeds From Term Loan	MDU Resources Group Inc	Cash Contributions
				Dakota Prairie Refining, LLC	Dakota Prairie Refining, LLC	Dakota Prairie Refining, LLC
Schedule of Equity Method Investments [Line Items]	'	'	'	'	'	'
Diesel refinery construction cost	'	'	$300	'	'	'
Contribution amount funded	'	'	150	75	150	75
Investment in unconsolidated affiliate	$33.40	$1.90	'	'	'	'
Joint venture, profit sharing percentage	'	'	50.00%	'	'	'

Goodwill_and_Intangible_Assets3

Goodwill and Intangible Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill	'	'	'
Beginning balance:	$187	$48.30	'
Acquisitions	20	138.7	'
Accumulated impairment losses	0	0	0
Ending balance:	207	187	48.3
Specialty Product	'	'	'
Goodwill	'	'	'
Beginning balance:	159.4	48.3	'
Acquisitions	9.1	111.1	'
Accumulated impairment losses	0	0	'
Ending balance:	168.5	159.4	'
Fuel Product	'	'	'
Goodwill	'	'	'
Beginning balance:	27.6	0	'
Acquisitions	10.9	27.6	'
Accumulated impairment losses	0	0	'
Ending balance:	$38.50	$27.60	'

Goodwill_and_Intangible_Assets4

Goodwill and Intangible Assets (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'18 years	'
Gross Amount	$296.50	$255.10
Accumulated Amortization	-83.6	-58
Customer relationships	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'22 years	'
Gross Amount	182.9	154.3
Accumulated Amortization	-40.3	-22.6
Supplier agreements	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'4 years	'
Gross Amount	21.5	21.5
Accumulated Amortization	-21.5	-21.5
Tradenames	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'13 years	'
Gross Amount	10.6	6.4
Accumulated Amortization	-1.6	-0.6
Trade secrets	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'13 years	'
Gross Amount	52.7	44.2
Accumulated Amortization	-9.6	-3.1
Patents	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'12 years	'
Gross Amount	1.6	1.6
Accumulated Amortization	-1.2	-1.1
Non-competition agreements	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'5 years	'
Gross Amount	5.9	5.8
Accumulated Amortization	-5.8	-5.8
Distributor agreements	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'3 years	'
Gross Amount	2	2
Accumulated Amortization	-2	-2
Royalty agreements	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Weighted Average Life	'19 years	'
Gross Amount	4.5	4.5
Accumulated Amortization	-1.6	-1.3
Tradenames	'	'
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]	'	'
Accumulated Amortization	0	0
Indefinite-Lived Intangible Assets (Excluding Goodwill)	($14.80)	($14.80)

Goodwill_and_Intangible_Assets5

Goodwill and Intangible Assets (Details 2) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]	'
2014	$29.40
2015	26.8
2016	24.4
2017	21.4
2018	$18.20

Goodwill_and_Intangibles_Detai

Goodwill and Intangibles (Details Textual) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill and Intangible Assets Disclosure [Abstract]	'	'	'
Amortization of Intangible Assets	$25.60	$16.90	$7

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Abstract]	'	'	'
Operating leases, rent expense	$35.30	$26.90	$20.50
Operating Leases, Future Minimum Commitments	'	'	'
2014	30	'	'
2015	26.8	'	'
2016	22.4	'	'
2017	19.6	'	'
2018	16.7	'	'
Thereafter	30.6	'	'
Total	$146.10	'	'

Commitments_and_Contingencies_2

Commitments and Contingencies (Details 1) (USD $)	Dec. 31, 2013	Oct. 16, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Oct. 16, 2013
In Millions, unless otherwise specified			LVT Feedstock Agreement	Houston Refining	BP Purchase Agreement	BP Purchase Agreement	BP Purchase Agreement	Naphthenic Lubricating Oils	White Mineral Oil	Subsequent Event
						Minimum	Maximum	Houston Refining	Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]	'	'	'	'	'	'	'	'	'	'
Daily required commitment	'	'	'	'	'	35,000	45,000	3,100	800	'
Intial term	'	'	'10 years	'	'1 year	'	'	'	'	'
Automatic renewal term	'	'	'	'	'1 year	'	'	'	'	'
Termination notice	'	'	'	'	'90 days	'	'	'	'	'
Limited interest in collateral pledged	'	'	'	'	'	'	$100	'	'	'
TexStar pipeline capacity	'	'	'	'	'	'	'	'	'	30,000
TexStar contract period	'	15	'	'	'	'	'	'	'	'
Expected deliveries	'	10,000	'	'	'	'	'	'	'	'
Annual purchase amount	'	'	77	140.7	'	'	'	'	'	'
Purchase Obligation, Future Minimum Commitments	'	'	'	'	'	'	'	'	'	'
2014	867	'	'	'	'	'	'	'	'	'
2015	3.1	'	'	'	'	'	'	'	'	'
2016	0.8	'	'	'	'	'	'	'	'	'
2017	0.3	'	'	'	'	'	'	'	'	'
2018	0	'	'	'	'	'	'	'	'	'
Thereafter	0	'	'	'	'	'	'	'	'	'
Total	$871.20	'	'	'	'	'	'	'	'	'

Commitments_and_Contingencies_3

Commitments and Contingencies (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	employee	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]	'	'	'
Number of employees	1,400	'	'
Number of Employees Concentration Risk, Percentage	54.10%	65.00%	55.20%
Labor Force Concentration Risk \| Workforce Subject to Collective Bargaining Arrangements	'	'	'
Concentration Risk [Line Items]	'	'	'
Number of employees	570	'	'
Number of Employees Concentration Risk, Percentage	40.70%	'	'
Labor Force Concentration Risk \| Workforce Subject to Collective Bargaining Arrangements Expiring within One Year	'	'	'
Concentration Risk [Line Items]	'	'	'
Number of employees	80	'	'
Number of Employees Concentration Risk, Percentage	5.70%	'	'

Commitments_and_Contingencies_4

Commitments and Contingencies (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Abstract]	'	'	'
Insurance recoveries	$0	$0	$8.70
Proceeds from insurance settlement	$0	$0	$1.90

Commitments_and_Contingencies_5

Commitments and Contingencies (Details 4) (USD $)	12 Months Ended		0 Months Ended	12 Months Ended							12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Jun. 29, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Nov. 07, 2013	Dec. 31, 2013
	WDNR-Superior	WDNR-Superior	EPA	Superior Acquisition	LDEQ-Shreveport	LDEQ-Shreveport	LDEQ-Shreveport	LDEQ-Shreveport	Shreveport	Shreveport	Shreveport
							Maximum	Minimum			Maximum
Loss Contingencies [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Estimates costs of equipment upgrades and conduct other discrete	$1	'	'	'	'	'	'	'	'	'	'
Required minimum liability	'	'	'	6.6	'	'	'	'	'	'	'
Indemnification liability maximum	'	'	'	22	'	'	'	'	'	'	'
Environmental settlement	'	'	'	'	23-Dec-10	'	'	'	'	'	'
Settlement agreement with the LDEQ	'	'	'	'	31-Jan-12	'	'	'	'	'	'
Environmental remediation expense	1.9	2.4	'	'	4.9	4.2	8	6	'	'	'
Payments for Environmental Liabilities	'	'	0.1	'	'	'	'	'	'	'	'
Settlement agreement, environmental studies period	'	'	'	'	'2 years	'	'	'	'	'	'
EPA Penalty	'	'	'	'	'	'	'	'	'	0.3	'
Specified environmental liabilities first required to contribute up to	'	'	'	'	'	'	'	'	'	'	1
Specified environmental liabilities first	'	'	'	'	'	'	'	'	5	'	'
Weston Agreement Trust	'	'	'	'	'	'	'	'	$0.70	'	'

Commitments_and_Contingencies_6

Commitments and Contingencies (Details 5) (Occupational Safety and Health Administration, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Mar. 14, 2011
Loss Contingencies [Line Items]	'	'	'	'	'
Standard certification	'ISO-9001-2008	'	'	'	'
Environmental remediation expense	$3.20	$0.70	'	'	'
Occupational Health and Safety, Penalty Paid During Period	'	'	'	0.1	'
OSHA spending	'	'	'first quarter of 2011	'	'
Citation and notice of penalty	'	'	14-Mar-11	'	'
Expected Environmental Capital Expenditures	'	'	'	'	0.2
Maximum	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'
Expected environmental capital expenditures	$1	'	'	'	'

Commitments_and_Contingencies_7

Commitments and Contingencies (Details 6) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]	'	'
Letters of credit issued to a hedging counterparty	'	$25
Senior secured revolving credit facility	'	'
Loss Contingencies [Line Items]	'	'
Letters of credit outstanding amount	95.2	222.4
Availability to issue letters of credit	472.4	355.1
Maximum \| Senior secured revolving credit facility	'	'
Debt Disclosure [Abstract]	'	'
Letter of credit sublimit percentage	80.00%	'
Letter of credit sublimit	680	'
Minimum \| Senior secured revolving credit facility	'	'
Debt Disclosure [Abstract]	'	'
Letter of credit sublimit	$400	'

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Lease Expiration Date	1-Jan-27	'
Summary of Long-term debt	'	'
Total long-term debt	$1,110.80	$863.50
Less current portion of long-term debt	0.4	0.8
Long-term Debt, Excluding Current Maturities	1,110.40	862.7
Senior secured revolving credit facility	'	'
Summary of Long-term debt	'	'
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments monthly, borrowings due June 2016	0	0
Borrowings under 2019 Notes, interest at a fixed rate of 9.375%, interest payments semiannually, borrowings due May 2019, effective interest rate of 9.9% for the years ended December 31, 2013 and 2012	'	'
Debt Instrument [Line Items]	'	'
Stated Interest Rate Percentage	9.38%	9.38%
Effective Interest Rate Percentage	9.90%	9.90%
Summary of Long-term debt	'	'
Borrowings under Senior Notes	500	600
Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.0% for the years ended December 31, 2013 and 2012	'	'
Debt Instrument [Line Items]	'	'
Stated Interest Rate Percentage	9.63%	9.63%
Effective Interest Rate Percentage	10.00%	10.00%
Summary of Long-term debt	'	'
Borrowings under Senior Notes	275	275
Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 7.9% for the year ended December 31, 2013	'	'
Debt Instrument [Line Items]	'	'
Stated Interest Rate Percentage	7.63%	'
Effective Interest Rate Percentage	7.90%	'
Summary of Long-term debt	'	'
Borrowings under Senior Notes	350	0
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	'	'
Summary of Long-term debt	'	'
Capital lease obligations, at various interest rates, interest and principal payments monthly through January 2027	4.8	5.5
Less unamortized discounts	'	'
Summary of Long-term debt	'	'
Less unamortized discounts	($19)	($17)

LongTerm_Debt_Details_1

Long-Term Debt (Details 1)	0 Months Ended
	Nov. 26, 2013	Nov. 26, 2013	Nov. 26, 2013	Jun. 29, 2012	Jun. 29, 2012	Jun. 29, 2012	Sep. 19, 2011	Sep. 19, 2011	Sep. 19, 2011
	7 5/8% Senior Notes	7 5/8% Senior Notes	7 5/8% Senior Notes	9 5/8% Senior Notes	9 5/8% Senior Notes	9 5/8% Senior Notes	9 3/8% Senior Notes	9 3/8% Senior Notes	9 3/8% Senior Notes
	January 15, 2018 through January 14, 2019	January 15, 2019 through January 14, 2020	After January 15, 2020	August 1, 2016 through July 30, 2017	August 1, 2016 through July 30, 2017	After August 1, 2018	May 1, 2015 through April 30, 2016	May 1, 2016 through April 30, 2017	After May 1, 2017
Summary of Redemption Price During Period	'	'	'	'	'	'	'	'	'
Percentage of redemption price	103.81%	101.91%	100.00%	104.81%	102.41%	100.00%	104.69%	102.34%	100.00%

LongTerm_Debt_Details_2

Long-Term Debt (Details 2) (Senior secured revolving credit facility)	12 Months Ended
	Dec. 31, 2013
Prime \| Greater than 66%	'
Debt Instrument [Line Items]	'
Margin basis point	1.00%
Prime \| Between 33% and 66%	'
Debt Instrument [Line Items]	'
Margin basis point	1.25%
Prime \| Less than 33%	'
Debt Instrument [Line Items]	'
Margin basis point	1.50%
Libor \| Greater than 66%	'
Debt Instrument [Line Items]	'
Margin basis point	2.25%
Libor \| Between 33% and 66%	'
Debt Instrument [Line Items]	'
Margin basis point	2.50%
Libor \| Less than 33%	'
Debt Instrument [Line Items]	'
Margin basis point	2.75%
Minimum \| Greater than 66%	'
Debt Instrument [Line Items]	'
Debt Instrument, Quarterly Average Availability Percentage	66.00%
Minimum \| Between 33% and 66%	'
Debt Instrument [Line Items]	'
Debt Instrument, Quarterly Average Availability Percentage	33.00%
Maximum \| Between 33% and 66%	'
Debt Instrument [Line Items]	'
Debt Instrument, Quarterly Average Availability Percentage	66.00%
Maximum \| Less than 33%	'
Debt Instrument [Line Items]	'
Debt Instrument, Quarterly Average Availability Percentage	33.00%

LongTerm_Debt_Details_3

Long-Term Debt (Details 3) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Maturities of long-term debt	'
2014	$0.40
2015	0.4
2016	0.3
2017	0.4
2018	0.4
Thereafter	1,127.90
Total	$1,129.80

LongTerm_Debt_Details_4

Long-Term Debt (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]	'	'
Capital Lease Obligations Incurred	'	$5.80
Lease Expiration Date	1-Jan-27	'
Property, plant and equipment, gross	1,538.40	1,284.80
Accumulated depreciation	378	297.9
Capital Leases, Future Minimum Payments	'	'
2014	0.8	'
2015	0.7	'
2016	0.7	'
2017	0.7	'
2018	0.7	'
Thereafter	4.1	'
Total minimum lease payments	7.7	'
Less amount representing interest	2.9	'
Capital lease obligations	4.8	'
Less obligations due within one year	0.4	'
Long-term capital lease obligations	4.4	'
Assets under capital leases	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	11.1	11.1
Accumulated depreciation	$5	$4.30

LongTerm_Debt_Details_Textual

Long-Term Debt (Details Textual) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 26, 2013

Jun. 29, 2012

Sep. 19, 2011

Apr. 21, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

7 5/8% Senior Notes

9 5/8% Senior Notes

9 3/8% Senior Notes

Senior secured revolving credit facility

Prime Rate

London Interbank Offered Rate (LIBOR)

Maximum

Minimum

Senior secured revolving credit facility

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

100.00%

225.00%

Interest and principal payments of debt instruments

'semiannually

'monthly

Senior Notes (Textual) [Abstract]

Gains (Losses) on Extinguishment of Debt

($14.60)

($15.10)

Notes redemption proceeds

111.2

Notes redemption amount

-26

-74

Debt Instrument, Maturity Date

15-Jan-22

1-Aug-20

1-May-19

24-Jun-16

Senior Notes Issued, Gross

350

275

200

400

Senior Notes, Issuance Date

26-Nov-13

29-Jun-12

19-Sep-11

21-Apr-11

Debt Instrument Percentage of Discount Price

98.49%

98.25%

93.00%

100.00%

Senior Notes Proceeds, Net of Discount, Underwriters' Fees and Expenses

337.4

262.5

180.3

389

Redemption Percentage

35.00%

Redemption Price

107.63%

109.63%

109.38%

Minimum Percentage of Senior Notes Outstanding After Redemption Date

65.00%

Holder of the Senior Notes Will Have the Right to Require That The Company Repurchase All or Portion In Cash Purchase Price Equal To In Percentage of the Principle, Plus Any Accrued and Unpaid Interest

101.00%

Redemption occurs within days of the date of the closing of such public or private equity offering

'180 days

'120 days

Repayments of borrowings â€” senior notes

-100

Line of Credit Facility [Abstract]

Current interest rate of senior secured revolving credit facility

'prime plus a basis points margin or LIBOR plus a basis points margin

Line of Credit Facility, Amount Outstanding

Line of Credit Facility, Current Borrowing Capacity

567.6

Senior secured revolving credit facility

850

Fixed charge coverage ratio

2.39

Financial covenant availability under the revolving credit facility falls below the greater

'greater of (i)12.5% of the lesser of (a)Â 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)Â the credit agreement commitments then in effect and (ii)Â $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.

Covenant compliance required cash available

46.4

Percentage of lesser of the borrowing agreement

12.50%

Unutilized commitments fee to the lender under the revolving credit facility

0.50%

0.38%

Customary letter of credit fee, including a fronting fee per annum on the stated amount of each outstanding letter of credit

0.13%

Collateral Trust Agreement limit to which forward purchase contracts for physical commodities are covered by

$100

Derivatives_Details

Derivatives (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	$59.60	$52
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-59.6	-48.9
Derivative Asset	0	3.1
Designated as Hedging Instrument	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	50	45.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-50	-42
Derivative Asset	0	3.1
Designated as Hedging Instrument \| Fuel Product \| Crude Oil Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	45.4	24.9
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-45.4	-14.4
Derivative Asset	0	10.5
Designated as Hedging Instrument \| Fuel Product \| Gasoline swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	1	5.2
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-1	-4.9
Derivative Asset	0	0.3
Designated as Hedging Instrument \| Fuel Product \| Diesel Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	3.5	7
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-3.5	-14.9
Derivative Asset	0	-7.9
Designated as Hedging Instrument \| Fuel Product \| Jet Fuel Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0.1	8
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-0.1	-7.8
Derivative Asset	0	0.2
Not Designated as Hedging Instrument	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	9.6	6.9
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-9.6	-6.9
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Fuel Product \| Crude Oil Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	6.3	0.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-6.3	-0.1
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Fuel Product \| Gasoline swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Fuel Product \| Diesel Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0.7	5.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-0.7	-5.1
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Fuel Product \| Jet Fuel Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0.9	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-0.9	0
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Fuel Product \| Diesel Crack Spread Collars	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0.3	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-0.3	0
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Fuel Product \| Crude Oil Basis Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	1	0.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-1	-0.1
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Specialty Product \| Crude Oil Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0	1.6
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	-1.6
Derivative Asset	0	0
Not Designated as Hedging Instrument \| Specialty Product \| Natural Gas Swaps	'	'
Offsetting Assets [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0.4	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	-0.4	0
Derivative Asset	$0	$0

Derivatives_Details_1

Derivatives (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	($114.40)	($96.90)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	59.6	48.9
Derivative Liability	-54.8	-48
Designated as Hedging Instrument	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-97.4	-79.2
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	50	42
Derivative Liability	-47.4	-37.2
Designated as Hedging Instrument \| Fuel Product \| Crude Oil Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-13	-41.1
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	45.4	14.4
Derivative Liability	32.4	-26.7
Designated as Hedging Instrument \| Fuel Product \| Gasoline swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-19.7	-2.8
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	1	4.9
Derivative Liability	-18.7	2.1
Designated as Hedging Instrument \| Fuel Product \| Diesel Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-51.3	-25.2
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	3.5	14.9
Derivative Liability	-47.8	-10.3
Designated as Hedging Instrument \| Fuel Product \| Jet Fuel Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-13.4	-10.1
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.1	7.8
Derivative Liability	-13.3	-2.3
Not Designated as Hedging Instrument	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-17	-17.7
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	9.6	6.9
Derivative Liability	-7.4	-10.8
Not Designated as Hedging Instrument \| Fuel Product \| Crude Oil Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-1.7	-10.8
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	6.3	0.1
Derivative Liability	4.6	-10.7
Not Designated as Hedging Instrument \| Fuel Product \| Crude Oil Basis Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-0.6	-3.5
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	1	0.1
Derivative Liability	0.4	-3.4
Not Designated as Hedging Instrument \| Fuel Product \| Gasoline swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-9.4	-2.2
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	-9.4	-2.2
Not Designated as Hedging Instrument \| Fuel Product \| Diesel Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-3.5	-1.2
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.7	5.1
Derivative Liability	-2.8	3.9
Not Designated as Hedging Instrument \| Fuel Product \| Jet Fuel Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	0	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.9	0
Derivative Liability	0.9	0
Not Designated as Hedging Instrument \| Fuel Product \| Diesel Crack Spread Collars	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-0.2	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.3	0
Derivative Liability	0.1	0
Not Designated as Hedging Instrument \| Specialty Product \| Natural Gas Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	-1.6	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.4	0
Derivative Liability	-1.2	0
Not Designated as Hedging Instrument \| Specialty Product \| Crude Oil Swaps	'	'
Offsetting Liabilities [Line Items]	'	'
Derivative Liability, Fair Value, Gross Liability	0	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	1.6
Derivative Liability	$0	$1.60

Derivatives_Details_2

Derivatives (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Unrealized Gain (Loss)	'	'
Derivative [Line Items]	'	'
Discontinuation Cash Flow Hedge Accounting	($3.90)	($2.90)
Realized Gain (Loss)	'	'
Derivative [Line Items]	'	'
Discontinuation Cash Flow Hedge Accounting	$0.20	$40.10

Derivatives_Details_3

Derivatives (Details 3) (Designated as Hedging Instrument, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	($36.90)	($215.10)
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Effective Portion)	0.5	-154.1
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	-4.9	37.1
Fuel Product \| Crude Oil Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	18.7	-100
Fuel Product \| Gasoline swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	-19.5	-16
Fuel Product \| Diesel Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	-28.8	-59.3
Fuel Product \| Jet Fuel Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	-7.3	-39.8
Fuel Product \| Sales \| Gasoline swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Effective Portion)	-0.4	-38.4
Fuel Product \| Sales \| Diesel Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Effective Portion)	-4.4	-63
Fuel Product \| Sales \| Jet Fuel Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Effective Portion)	1.7	-104.4
Fuel Product \| Cost of Sales \| Crude Oil Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Effective Portion)	3.1	49.8
Fuel Product \| Unrealized Realized \| Crude Oil Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	-3	99.7
Fuel Product \| Unrealized Realized \| Gasoline swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	-1.7	-52
Fuel Product \| Unrealized Realized \| Diesel Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	-5.3	-10.5
Fuel Product \| Unrealized Realized \| Jet Fuel Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	5.1	-0.1
Specialty Product \| Crude Oil Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	0	0
Specialty Product \| Cost of Sales \| Crude Oil Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Effective Portion)	0.5	1.9
Specialty Product \| Unrealized Realized \| Crude Oil Swaps	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Net Income on Derivatives (Ineffective Portion)	$0	$0

Derivatives_Details_4

Derivatives (Details 4) (Not Designated as Hedging Instrument, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Realized Gain (Loss)	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	($0.80)	($3.20)
Unrealized Gain (Loss)	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	26.7	-28.2
Fuel Product \| Realized Gain (Loss) \| Crude Oil Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-6.3	-30.5
Fuel Product \| Realized Gain (Loss) \| Crude Oil Basis Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-7.7	2.1
Fuel Product \| Realized Gain (Loss) \| Gasoline swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3.2	22.1
Fuel Product \| Realized Gain (Loss) \| Diesel Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	8.1	10.9
Fuel Product \| Realized Gain (Loss) \| Jet Fuel Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0.7	-1.7
Fuel Product \| Realized Gain (Loss) \| Diesel Crack Spread Collars	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Fuel Product \| Unrealized Gain (Loss) \| Crude Oil Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	46.3	-40
Fuel Product \| Unrealized Gain (Loss) \| Crude Oil Basis Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3.8	-3.4
Fuel Product \| Unrealized Gain (Loss) \| Gasoline swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-9.9	0.5
Fuel Product \| Unrealized Gain (Loss) \| Diesel Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-11.7	8.9
Fuel Product \| Unrealized Gain (Loss) \| Jet Fuel Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0.9	0
Fuel Product \| Unrealized Gain (Loss) \| Diesel Crack Spread Collars	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0.1	0
Specialty Product \| Realized Gain (Loss) \| Crude Oil Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1.8	0
Specialty Product \| Realized Gain (Loss) \| Natural Gas Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-0.6	-5.4
Specialty Product \| Realized Gain (Loss) \| Interest rate swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	-0.7
Specialty Product \| Unrealized Gain (Loss) \| Crude Oil Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-1.6	1.6
Specialty Product \| Unrealized Gain (Loss) \| Natural Gas Swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-1.2	3.2
Specialty Product \| Unrealized Gain (Loss) \| Interest rate swaps	'	'
Derivative instruments not designated as cash flow hedges	'	'
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$0	$1

Derivatives_Details_5

Derivatives (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	($51.40)	($14)
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	-26.8	'
2014	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	-26.8	'
2015	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	-22.3	'
2016	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	($2.30)	'

Derivatives_Details_6

Derivatives (Details 6) (Natural Gas Swaps, Specialty Product, Not Designated as Hedging Instrument)	Dec. 31, 2013
	bbl
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	10,300,000
$/MMBtu	4.28
First Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	750,000
$/MMBtu	4.14
Second Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	750,000
$/MMBtu	4.14
Third Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	750,000
$/MMBtu	4.14
Fourth Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	850,000
$/MMBtu	4.21
Calendar Year 2015	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	3,500,000
$/MMBtu	4.27
Calendar Year 2016	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,700,000
$/MMBtu	4.42
Calendar Year 2017	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,000,000
$/MMBtu	4.29

Derivatives_Details_7

Derivatives (Details 7) (Crude Oil Swap Purchases, Fuel Product)	Dec. 31, 2013	Dec. 31, 2012
	bbl	bbl
Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	16,872,000	15,997,500
Average Swap ($/Bbl)	89.97	92.85
Designated as Hedging Instrument \| First Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	1,665,000
Barrels per Day Purchased	'	18,500
Average Swap ($/Bbl)	'	101.67
Designated as Hedging Instrument \| Second Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	1,911,000
Barrels per Day Purchased	'	21,000
Average Swap ($/Bbl)	'	100.22
Designated as Hedging Instrument \| Third Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	1,426,000
Barrels per Day Purchased	'	15,500
Average Swap ($/Bbl)	'	95.62
Designated as Hedging Instrument \| Fourth Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	1,104,000
Barrels per Day Purchased	'	12,000
Average Swap ($/Bbl)	'	93.41
Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	2,520,000	'
Barrels per Day Purchased	28,000	'
Average Swap ($/Bbl)	92.06	'
Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	2,411,500	'
Barrels per Day Purchased	26,500	'
Average Swap ($/Bbl)	91.97	'
Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	2,530,000	'
Barrels per Day Purchased	27,500	'
Average Swap ($/Bbl)	91.23	'
Designated as Hedging Instrument \| Fourth Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	2,024,000	'
Barrels per Day Purchased	22,000	'
Average Swap ($/Bbl)	90.61	'
Designated as Hedging Instrument \| Calendar Year 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	5,110,000
Barrels per Day Purchased	'	14,000
Average Swap ($/Bbl)	'	89.47
Designated as Hedging Instrument \| Calendar Year 2015	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	5,556,500	4,781,500
Barrels per Day Purchased	15,223	13,100
Average Swap ($/Bbl)	89.08	89.49
Designated as Hedging Instrument \| Calendar Year 2016	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,830,000	'
Barrels per Day Purchased	5,000	'
Average Swap ($/Bbl)	84.73	'
Not Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	3,463,500	1,821,000
Average Swap ($/Bbl)	92.59	98.72
Not Designated as Hedging Instrument \| First Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	630,000
Barrels per Day Purchased	'	7,000
Average Swap ($/Bbl)	'	101.34
Not Designated as Hedging Instrument \| Second Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	455,000
Barrels per Day Purchased	'	5,000
Average Swap ($/Bbl)	'	98.56
Not Designated as Hedging Instrument \| Third Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	368,000
Barrels per Day Purchased	'	4,000
Average Swap ($/Bbl)	'	96.58
Not Designated as Hedging Instrument \| Fourth Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	368,000
Barrels per Day Purchased	'	4,000
Average Swap ($/Bbl)	'	96.58
Not Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	810,000	'
Barrels per Day Purchased	9,000	'
Average Swap ($/Bbl)	94.56	'
Not Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	591,500	'
Barrels per Day Purchased	6,500	'
Average Swap ($/Bbl)	94.37	'
Not Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	874,000	'
Barrels per Day Purchased	9,500	'
Average Swap ($/Bbl)	92.92	'
Not Designated as Hedging Instrument \| Fourth Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	184,000	'
Barrels per Day Purchased	2,000	'
Average Swap ($/Bbl)	94.62	'
Not Designated as Hedging Instrument \| Calendar Year 2015	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,004,000	'
Barrels per Day Purchased	2,751	'
Average Swap ($/Bbl)	89.28	'

Derivatives_Details_8

Derivatives (Details 8) (Crude Oil Basis Swaps Purchased, Fuel Product, Not Designated as Hedging Instrument, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified	bbl	bbl	Realized Gain (Loss)	First Quarter 2013	Second Quarter 2013	Third Quarter 2013	Fourth Quarter 2013	Fourth Quarter 2013	First Quarter 2014	Third Quarter 2014	Fourth Quarter 2014
				bbl	bbl	bbl	bbl	bbl	bbl	bbl	bbl
Derivative [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Derivative, Nonmonetary Notional Amount	486,000	912,000	'	180,000	364,000	184,000	248,000	184,000	118,000	184,000	184,000
Barrels per Day Purchased	'	'	'	2,000	4,000	2,000	'	2,000	1,311	2,000	2,000
Derivative, Average Swap Differential to Publicly Traded Future	-23.29	-25.2	'	-23.75	-27.38	-23.75	'	-23.75	-28.5	-21.75	-21.5
Derivative, Gain on Derivative	'	'	($0.60)	'	'	'	'	'	'	'	'

Derivative_Details_9

Derivative (Details 9) (Fuel Product)	Dec. 31, 2013	Dec. 31, 2012
Derivative (Details 9) (Fuel Product)	bbl	bbl
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	11,495,500	10,864,500
Average Swap ($/Bbl)	115.72	117.13
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Second Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	546,000
Barrels per Day Sold	'	6,000
Average Swap ($/Bbl)	'	122.74
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Third Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	874,000
Barrels per Day Sold	'	9,500
Average Swap ($/Bbl)	'	122.23
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Fourth Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	828,000
Barrels per Day Sold	'	9,000
Average Swap ($/Bbl)	'	120.82
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Calendar Year 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	3,835,000
Barrels per Day Sold	'	10,507
Average Swap ($/Bbl)	'	116
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,125,000	'
Barrels per Day Sold	12,500	'
Average Swap ($/Bbl)	117.54	'
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,183,000	'
Barrels per Day Sold	13,000	'
Average Swap ($/Bbl)	116.78	'
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,288,000	'
Barrels per Day Sold	14,000	'
Average Swap ($/Bbl)	116.82	'
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Fourth Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,288,000	'
Barrels per Day Sold	14,000	'
Average Swap ($/Bbl)	116.96	'
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Calendar Year 2015	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	4,781,500	4,781,500
Barrels per Day Sold	13,100	13,100
Average Swap ($/Bbl)	115.81	115.81
Diesel Swaps Sold [Member] \| Designated as Hedging Instrument \| Calendar Year 2016	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,830,000	'
Barrels per Day Sold	5,000	'
Average Swap ($/Bbl)	112	'
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,870,000	1,456,000
Average Swap ($/Bbl)	119.54	127.2
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| First Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	540,000
Barrels per Day Sold	'	6,000
Average Swap ($/Bbl)	'	130.57
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| Second Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	364,000
Barrels per Day Sold	'	4,000
Average Swap ($/Bbl)	'	126.82
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| Third Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	276,000
Barrels per Day Sold	'	3,000
Average Swap ($/Bbl)	'	124.17
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| Fourth Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	276,000
Barrels per Day Sold	'	3,000
Average Swap ($/Bbl)	'	124.17
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	270,000	'
Barrels per Day Sold	3,000	'
Average Swap ($/Bbl)	121.72	'
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	182,000	'
Barrels per Day Sold	2,000	'
Average Swap ($/Bbl)	123.22	'
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	230,000	'
Barrels per Day Sold	2,500	'
Average Swap ($/Bbl)	121.74	'
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| Fourth Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	184,000	'
Barrels per Day Sold	2,000	'
Average Swap ($/Bbl)	123.02	'
Diesel Swaps Sold [Member] \| Not Designated as Hedging Instrument \| Calendar Year 2015	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,004,000	'
Barrels per Day Sold	2,751	'
Average Swap ($/Bbl)	117.15	'
Diesel Swaps Sold \| Not Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	182,500	'
Average Swap ($/Bbl)	121.8	'
Diesel Swaps Sold \| Not Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	45,000	'
Barrels per Day Purchased	500	'
Average Swap ($/Bbl)	121.8	'
Diesel Swaps Sold \| Not Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	45,500	'
Barrels per Day Purchased	500	'
Average Swap ($/Bbl)	121.8	'
Diesel Swaps Sold \| Not Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	46,000	'
Barrels per Day Purchased	500	'
Average Swap ($/Bbl)	121.8	'
Diesel Swaps Sold \| Not Designated as Hedging Instrument \| Fourth Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	46,000	'
Barrels per Day Purchased	500	'
Average Swap ($/Bbl)	121.8	'

Derivative_Details_10

Derivative (Details 10) (Fuel Product)	Dec. 31, 2013	Dec. 31, 2012
Derivative (Details 10) (Fuel Product)	bbl	bbl
Jet Fuel Swaps Purchased \| Not Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	90,000	'
Average Swap ($/Bbl)	116.71	'
Jet Fuel Swaps Purchased \| Not Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	90,000	'
Barrels per Day Purchased	1,000	'
Average Swap ($/Bbl)	116.71	'
Jet Fuel Swaps Sold \| Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	2,050,000	3,773,000
Average Swap ($/Bbl)	115.66	123.56
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| First Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	1,035,000
Barrels per Day Sold	'	11,500
Average Swap ($/Bbl)	'	127.39
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Second Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	819,000
Barrels per Day Sold	'	9,000
Average Swap ($/Bbl)	'	129.2
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Third Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	368,000
Barrels per Day Sold	'	4,000
Average Swap ($/Bbl)	'	125.13
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Fourth Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	276,000
Barrels per Day Sold	'	3,000
Average Swap ($/Bbl)	'	122.36
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Calendar Year 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	1,275,000
Barrels per Day Sold	'	3,493
Average Swap ($/Bbl)	'	116.64
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	450,000	'
Barrels per Day Sold	5,000	'
Average Swap ($/Bbl)	117.5	'
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	273,000	'
Barrels per Day Sold	3,000	'
Average Swap ($/Bbl)	116.68	'
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	276,000	'
Barrels per Day Sold	3,000	'
Average Swap ($/Bbl)	116.18	'
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Fourth Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	276,000	'
Barrels per Day Sold	3,000	'
Average Swap ($/Bbl)	115.65	'
Jet Fuel Swaps Sold \| Designated as Hedging Instrument \| Calendar Year 2015	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	775,000	'
Barrels per Day Sold	2,123	'
Average Swap ($/Bbl)	114.05	'

Derivative_Details_11

Derivative (Details 11) (Gasoline Swaps Sold, Fuel Product)	Dec. 31, 2013	Dec. 31, 2012
Derivative (Details 11) (Gasoline Swaps Sold, Fuel Product)	bbl	bbl
Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	3,326,500	1,360,000
Average Swap ($/Bbl)	106.61	114.84
Designated as Hedging Instrument \| First Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	630,000
Barrels per Day Sold	'	7,000
Average Swap ($/Bbl)	'	113.59
Designated as Hedging Instrument \| Second Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	546,000
Barrels per Day Sold	'	6,000
Average Swap ($/Bbl)	'	116.32
Designated as Hedging Instrument \| Third Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	184,000
Barrels per Day Sold	'	2,000
Average Swap ($/Bbl)	'	114.73
Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	945,000	'
Barrels per Day Sold	10,500	'
Average Swap ($/Bbl)	104.39	'
Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	955,500	'
Barrels per Day Sold	10,500	'
Average Swap ($/Bbl)	109.68	'
Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	966,000	'
Barrels per Day Sold	10,500	'
Average Swap ($/Bbl)	106.6	'
Designated as Hedging Instrument \| Fourth Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	460,000	'
Barrels per Day Sold	5,000	'
Average Swap ($/Bbl)	104.85	'
Not Designated as Hedging Instrument	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	1,683,500	365,000
Average Swap ($/Bbl)	107.82	105.5
Not Designated as Hedging Instrument \| First Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	90,000
Barrels per Day Sold	'	1,000
Average Swap ($/Bbl)	'	105.5
Not Designated as Hedging Instrument \| Second Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	91,000
Barrels per Day Sold	'	1,000
Average Swap ($/Bbl)	'	105.5
Not Designated as Hedging Instrument \| Third Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	92,000
Barrels per Day Sold	'	1,000
Average Swap ($/Bbl)	'	105.5
Not Designated as Hedging Instrument \| Fourth Quarter 2013	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	'	92,000
Barrels per Day Sold	'	1,000
Average Swap ($/Bbl)	'	105.5
Not Designated as Hedging Instrument \| First Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	630,000	'
Barrels per Day Sold	7,000	'
Average Swap ($/Bbl)	105.67	'
Not Designated as Hedging Instrument \| Second Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	409,500	'
Barrels per Day Sold	4,500	'
Average Swap ($/Bbl)	110.48	'
Not Designated as Hedging Instrument \| Third Quarter 2014	'	'
Derivative [Line Items]	'	'
Derivative, Nonmonetary Notional Amount	644,000	'
Barrels per Day Sold	7,000	'
Average Swap ($/Bbl)	108.24	'

Derivative_Details_12

Derivative (Details 12) (Diesel Crack Spread Collars, Fuel Product, Not Designated as Hedging Instrument)	Dec. 31, 2013
	bbl
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	365,000
Average Sold Call ($/Bbl)	35
Average Bought Put ($/Bbl)	26
First Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	90,000
Barrels per Day	1,000
Average Sold Call ($/Bbl)	35
Average Bought Put ($/Bbl)	26
Second Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	91,000
Barrels per Day	1,000
Average Sold Call ($/Bbl)	35
Average Bought Put ($/Bbl)	26
Third Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	92,000
Barrels per Day	1,000
Average Sold Call ($/Bbl)	35
Average Bought Put ($/Bbl)	26
Fourth Quarter 2014	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	92,000
Barrels per Day	1,000
Average Sold Call ($/Bbl)	35
Average Bought Put ($/Bbl)	26

Derivatives_Details_Textual

Derivatives (Details Textual) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012
In Millions, unless otherwise specified	contract	contract	Jet Fuel [Member]	Not Designated as Hedging Instrument	First Quarter 2013
				Unrealized Gain (Loss)	Not Designated as Hedging Instrument
				Specialty Product	Specialty Product
				Crude Oil Swap Purchases	Crude Oil Swap Purchases
					bbl
Derivative [Line Items]	'	'	'	'	'
Derivative, Nonmonetary Notional Amount	'	'	'	'	200,000
Derivative, Gain on Derivative	'	'	'	$1.60	'
Number of Credit Risk Counterparties, Held in Asset Position	0	2	'	'	'
Credit Risk Derivative Assets, at Fair Value	'	3.1	'	'	'
Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring	'	'	1.7	'	'
Letter Of Credit Issued To Hedging Counterparty	'	25	'	'	'
Credit Risk Derivatives, at Fair Value, Net	$0	($7.50)	'	'	'

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative assets:	'	'
Total derivative assets	$0	$3.10
Derivative liabilities:	'	'
Total derivative liabilities	-54.8	-48
Level 1	'	'
Derivative assets:	'	'
Pension plan investments	0	38.9
Level 2	'	'
Derivative assets:	'	'
Pension plan investments	45.8	2.7
Recurring \| Level 1	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Pension plan investments	0	38.9
Total recurring assets at fair value	0	38.9
Derivative liabilities:	'	'
Total derivative liabilities	0	0
RINS Obligation	0	0
Liability Awards	-3.7	-2.2
Total recurring liabilities at fair value	-3.7	-2.2
Recurring \| Level 2	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Pension plan investments	45.8	2.7
Total recurring assets at fair value	45.8	2.7
Derivative liabilities:	'	'
Total derivative liabilities	0	0
RINS Obligation	-5.3	-0.8
Liability Awards	0	0
Total recurring liabilities at fair value	-5.3	-0.8
Recurring \| Level 3	'	'
Derivative assets:	'	'
Total derivative assets	0	3.1
Pension plan investments	0	0
Total recurring assets at fair value	0	3.1
Derivative liabilities:	'	'
Total derivative liabilities	-54.8	-48
RINS Obligation	0	0
Liability Awards	0	0
Total recurring liabilities at fair value	-54.8	-48
Recurring \| Total	'	'
Derivative assets:	'	'
Total derivative assets	0	3.1
Pension plan investments	45.8	41.6
Total recurring assets at fair value	45.8	44.7
Derivative liabilities:	'	'
Total derivative liabilities	-54.8	-48
RINS Obligation	-5.3	-0.8
Liability Awards	-3.7	-2.2
Total recurring liabilities at fair value	-63.8	-51
Recurring \| Crude Oil Swaps \| Level 1	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Crude Oil Swaps \| Level 2	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Crude Oil Swaps \| Level 3	'	'
Derivative assets:	'	'
Total derivative assets	0	10.5
Derivative liabilities:	'	'
Total derivative liabilities	37	-35.8
Recurring \| Crude Oil Swaps \| Total	'	'
Derivative assets:	'	'
Total derivative assets	0	10.5
Derivative liabilities:	'	'
Total derivative liabilities	37	-35.8
Recurring \| Crude Oil Basis Swaps \| Level 1	'	'
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Crude Oil Basis Swaps \| Level 2	'	'
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Crude Oil Basis Swaps \| Level 3	'	'
Derivative liabilities:	'	'
Total derivative liabilities	0.4	-3.4
Recurring \| Crude Oil Basis Swaps \| Total	'	'
Derivative liabilities:	'	'
Total derivative liabilities	0.4	-3.4
Recurring \| Gasoline swaps \| Level 1	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Gasoline swaps \| Level 2	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Gasoline swaps \| Level 3	'	'
Derivative assets:	'	'
Total derivative assets	0	0.3
Derivative liabilities:	'	'
Total derivative liabilities	-28.1	-0.1
Recurring \| Gasoline swaps \| Total	'	'
Derivative assets:	'	'
Total derivative assets	0	0.3
Derivative liabilities:	'	'
Total derivative liabilities	-28.1	-0.1
Recurring \| Diesel Swaps \| Level 1	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Diesel Swaps \| Level 2	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Diesel Swaps \| Level 3	'	'
Derivative assets:	'	'
Total derivative assets	0	-7.9
Derivative liabilities:	'	'
Total derivative liabilities	-50.6	-6.4
Recurring \| Diesel Swaps \| Total	'	'
Derivative assets:	'	'
Total derivative assets	0	-7.9
Derivative liabilities:	'	'
Total derivative liabilities	-50.6	-6.4
Recurring \| Jet Fuel Swaps \| Level 1	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Jet Fuel Swaps \| Level 2	'	'
Derivative assets:	'	'
Total derivative assets	0	0
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Jet Fuel Swaps \| Level 3	'	'
Derivative assets:	'	'
Total derivative assets	0	0.2
Derivative liabilities:	'	'
Total derivative liabilities	-12.4	-2.3
Recurring \| Jet Fuel Swaps \| Total	'	'
Derivative assets:	'	'
Total derivative assets	0	0.2
Derivative liabilities:	'	'
Total derivative liabilities	-12.4	-2.3
Recurring \| Natural Gas Swaps \| Level 1	'	'
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Natural Gas Swaps \| Level 2	'	'
Derivative liabilities:	'	'
Total derivative liabilities	0	0
Recurring \| Natural Gas Swaps \| Level 3	'	'
Derivative liabilities:	'	'
Total derivative liabilities	-1.2	0
Recurring \| Natural Gas Swaps \| Total	'	'
Derivative liabilities:	'	'
Total derivative liabilities	($1.20)	$0

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of net changes in fair value of the company's level 3 financial assets and liabilities	'	'	'
Realized Gain Loss on Derivative Instruments	($4.70)	$9.50	($7.90)
Unrealized loss on derivative instruments	25.7	-3.8	'
Change in fair value of cash flow hedges	-36.9	-215.1	-34.2
Level 3	'	'	'
Summary of net changes in fair value of the company's level 3 financial assets and liabilities	'	'	'
Fair value at January 1,	-44.9	14.9	'
Realized Gain Loss on Derivative Instruments	4.7	-9.5	'
Unrealized loss on derivative instruments	25.7	-3.8	'
Change in fair value of cash flow hedges	-36.9	-215.1	'
Settlements	-3.4	168.6	'
Transfers in (out) of Level 3	0	0	'
Fair value at December 31,	($54.80)	($44.90)	'

Fair_Value_Measurements_Detail2

Fair Value Measurements (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Level 1 \| Fair Value	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Notes Payable, Fair Value Disclosure	$863.60	$658.80
Level 1 \| Reported Value Measurement	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Notes Payable, Fair Value Disclosure	761.2	587.6
Level 2 \| Fair Value	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Notes Payable, Fair Value Disclosure	353.9	301.8
Level 2 \| Reported Value Measurement	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Notes Payable, Fair Value Disclosure	344.8	270.4
Level 3	'	'
Financial Instrument:	'	'
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments monthly, borrowings due June 2016	0	0
Level 3 \| Fair Value	'	'
Financial Instrument:	'	'
Capital Leased Assets, Noncurrent, Fair Value Disclosure	4.8	5.5
Level 3 \| Reported Value Measurement	'	'
Financial Instrument:	'	'
Capital Leased Assets, Noncurrent, Fair Value Disclosure	$4.80	$5.50

Fair_Value_Measurements_Detail3

Fair Value Measurements (Details Textual) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements (Textual) [Abstract]	'	'
Asset was reduced result of applying the applicable credit default spread	'	$0.10
Liabilities was reduced result of applying the applicable credit default spread	$1.90	$0.20
Reviews for goodwill impairment annually on	1-Oct-13	'

Partners_Capital_Details

Partner's Capital (Details) (USD $)

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

In Millions, except Share data, unless otherwise specified

Apr. 02, 2013

Jan. 08, 2013

8-May-12

Sep. 08, 2011

Feb. 24, 2011

Feb. 28, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 02, 2013

Jan. 08, 2013

Oct. 14, 2011

Jan. 08, 2013

Overallotment Option

Firm Units [Member]

Public Offering of Common Units [Line Items]

Payments of Capital Distribution

$201.60

$132.40

$82.70

Partners' Capital Account, Units, Converted

13,066,000

Partners' Capital Account, Units, Conversion Ratio

Common units sold in public offering

6,037,500

5,750,000

6,000,000

11,750,000

4,500,000

787,500

750,000

5,000,000

Stock Price, Offering Price Per Share

$37.50

$31.81

$25.50

$18

$21.45

Proceeds from public offerings of common units, net

217.3

175.2

146.6

202.4

92.3

392.5

146.6

294.7

Underwriting discounts

9.1

7.4

6.2

8.4

3.9

General partner contributed capital

$4.60

$3.80

$3.10

$4.30

General partner ownership

2.00%

Partners_Capital_Partners_Capi1

Partners' Capital Partner's Capital (Details 1) (USD $)	12 Months Ended
Partners' Capital Partner's Capital (Details 1) (USD $)	Dec. 31, 2013
Minimum Quarterly Distribution \| Minimum	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Incentive Distribution, Distribution Per Unit	$0.45
Minimum Quarterly Distribution \| Limited Partners	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	98.00%
Minimum Quarterly Distribution \| General Partner	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	2.00%
First Target Distribution \| Maximum	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Incentive Distribution, Distribution Per Unit	$0.50
First Target Distribution \| Limited Partners	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	98.00%
First Target Distribution \| General Partner	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	2.00%
Second Target Distribution \| Minimum	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Incentive Distribution, Distribution Per Unit	$0.50
Second Target Distribution \| Maximum	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Incentive Distribution, Distribution Per Unit	$0.56
Second Target Distribution \| Limited Partners	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	85.00%
Second Target Distribution \| General Partner	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	15.00%
Third Target Distribution \| Minimum	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Incentive Distribution, Distribution Per Unit	$0.56
Third Target Distribution \| Maximum	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Incentive Distribution, Distribution Per Unit	$0.68
Third Target Distribution \| Limited Partners	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	75.00%
Third Target Distribution \| General Partner	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	25.00%
After Target Distributions \| Minimum	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Incentive Distribution, Distribution Per Unit	$0.68
After Target Distributions \| Limited Partners	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	50.00%
After Target Distributions \| General Partner	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal percentage interest in distributions	50.00%

Partners_Capital_Partners_Capi2

Partners' Capital Partner's Capital (Details 2) (USD $)	0 Months Ended					12 Months Ended
In Millions, except Share data, unless otherwise specified	Apr. 02, 2013	Jan. 08, 2013	8-May-12	Sep. 08, 2011	Feb. 24, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital Account, Units, Sold in Public Offering	6,037,500	5,750,000	6,000,000	11,750,000	4,500,000	'	'	'
Limited Partners' Minimum Vote Required for Removal of General Partner	'	'	'	'	'	66.67%	'	'
Payments of Capital Distribution	'	'	'	'	'	$201.60	$132.40	$82.70
Limited Partners' Cash Distributions Rights Period	'	'	'	'	'	'45 days	'	'
Limited Partners' Ownership Percentage Threshold, Event of Voting Exclusion	'	'	'	'	'	20.00%	'	'
General Partners' Ownership Percentage Threshold, Event of Units Sale by Limited Parnters to General Parnters	'	'	'	'	'	80.00%	'	'
General Partners Incentive Distribution Rights	'	'	'	'	'	-14.7	-5.5	-0.2
Partners' Capital, After Distribution Required Cash Amount	'	'	'	'	'	45	'	'
Partners' Capital, Distribution, Fixed Charge Coverage Ratio Threshold	'	'	'	'	'	1.75	'	'
Stock Price, Offering Price Per Share	$37.50	$31.81	$25.50	$18	$21.45	'	'	'
Proceeds from Issuance of Common Limited Partners Units	217.3	175.2	146.6	202.4	92.3	392.5	146.6	294.7
General Partners' Contributed Capital	4.6	3.8	3.1	4.3	2	'	'	'
Offering Costs, Partnership Interests	9.1	7.4	6.2	8.4	3.9	'	'	'
Investor [Member]	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital Account, Units	'	'	'	'	'	51,152,727	'	'
Affiliated Entity [Member]	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital Account, Units	'	'	'	'	'	18,164,551	'	'
Limited Partners	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Limited Partners' Capital Account, Units Outstanding	'	'	'	'	'	69,317,278	57,529,778	'
Maximum \| 9 3/8% Senior Notes	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital, Distribution Amount, Below Fixed Charge Coverage Ratio Threshold	'	'	'	'	'	70	'	'
Maximum \| 9 5/8% Senior Notes	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital, Distribution Amount, Below Fixed Charge Coverage Ratio Threshold	'	'	'	'	'	120	'	'
Maximum \| 7 5/8% Senior Notes	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital, Distribution Amount, Below Fixed Charge Coverage Ratio Threshold	'	'	'	'	'	$210	'	'
Lesser of Borrowing Base [Member]	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital, After Distribution Required Threshold Percentage	'	'	'	'	'	15.00%	'	'
Lesser of Credit Facility Commitments [Member]	'	'	'	'	'	'	'	'
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Partners' Capital, After Distribution Required Threshold Percentage	'	'	'	'	'	15.00%	'	'

UnitBased_Compensation_Details

Unit-Based Compensation (Details) (Nonvested Phantom Units, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Nonvested Phantom Units	'	'	'
Number of Phantom Units	'	'	'
Nonvested at beginning of period	835,927	562,696	105,492
Granted	483,044	616,997	640,875
Vested	-276,115	-286,976	-183,671
Forfeited	-354,600	-56,790	0
Nonvested at end of period	688,256	835,927	562,696
Weighted-Average Grant Date Fair Value	'	'	'
Nonvested at beginning of period	$27.57	$19.77	$17.68
Granted	$27.73	$26.69	$20.26
Vested	$24.22	$21.16	$20.29
Forfeited	$30.60	$20	$0
Nonvested at end of period	$23.70	$27.57	$19.77

UnitBased_Compensation_Details1

Unit-Based Compensation (Details Textual) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares authorized for grant under the Plan	783,960	'	'
Vested phantom unit grants	'	'	'
Unit-Based Compensation (Textual) [Abstract]	'	'	'
Compensation expense related to vested phantom unit grants	$4.80	$4.60	$3
Vested phantom unit grants, liability awards	'	'	'
Unit-Based Compensation (Textual) [Abstract]	'	'	'
Compensation expense related to vested phantom unit grants	1.6	2.2	'
Nonvested phantom units	'	'	'
Unit-Based Compensation (Textual) [Abstract]	'	'	'
Unrecognized compensation costs related to nonvested phantom unit grants	16.3	23	'
Unit-Based Compensation nonvested phantom compensation costs are expected to be recognized over a weighted-average period	'2 years	'	'
Fair value of phantom units vested during the period	6.7	6.1	'
Nonvested phantom units, liability awards [Member]	'	'	'
Unit-Based Compensation (Textual) [Abstract]	'	'	'
Compensation expense related to vested phantom unit grants	$12.40	$16.10	'
Long-Term Incentive Plan \| Phantom Share Units (PSUs) [Member]	'	'	'
Unit-Based Compensation (Textual) [Abstract]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'3 years	'	'
Annual Vesting \| Director Compensation Package \| Phantom Share Units (PSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Award vesting percentage	25.00%	'	'
Director \| Long-Term Incentive Plan \| Phantom Share Units (PSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Service period	'4 years	'4 years	'4 years
Management \| Vested at Grant \| Long-Term Incentive Plan \| Phantom Share Units (PSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Award vesting percentage	25.00%	'	'

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (Calumet 401k Plan [Member])	12 Months Ended
	Dec. 31, 2013
Defined Contribution Plan [Line Items]	'
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	5.00%
Minimum	'
Defined Contribution Plan [Line Items]	'
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	1.00%
Maximum	'
Defined Contribution Plan [Line Items]	'
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	70.00%
Defined Contribution Plan, Range 1 [Member]	'
Defined Contribution Plan [Line Items]	'
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	4.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Incremental Percentage Point	1.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Defined Contribution Plan, Range 2 [Member]	'
Defined Contribution Plan [Line Items]	'
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	6.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Incremental Percentage Point	1.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	50.00%

Employee_Benefit_Plans_Details1

Employee Benefit Plans (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Postemployment Benefits [Abstract]	'	'	'
Defined Contribution Plan, Cost Recognized	$4.10	$3.20	$2.30
Employer discretionary contribution amount	$0.90	$2.50	$1.40

Employee_Benefit_Plans_Details2

Employee Benefit Plans (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Curtailment gain recognized	'	$0	$0.20	$0
Employer contribution	'	3.4	3.1	'
Estimated future employer contributions in next fiscal year	1.6	'	'	'
Other Postretirement Benefit Plans, Defined Benefit	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Curtailment gain recognized	'	0	7	0
Employer contribution	'	0	0	'
Montana Plan \| Domestic Pension Plan	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	'	'36 months	'	'
Penreco Plan \| Domestic Pension Plan	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	'	'60 months	'	'
Superior Plan \| Pension Plans, Defined Benefit	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Curtailment gain recognized	'	'	0.2	'
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	'	'3 years	'	'
Superior Plan \| Other Postretirement Benefit Plans, Defined Benefit	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Curtailment gain recognized	'	'	$7	'
Maximum \| Superior Plan \| Pension Plans, Defined Benefit	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	'	'10 years	'	'

Employee_Benefit_Plans_Details3

Employee Benefit Plans (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of amounts recognized in the consolidated balance sheets:	'	'	'
Accumulated other comprehensive (income) loss	($1.90)	($11.50)	'
Pension Plans, Defined Benefit	'	'	'
Change in projected benefit obligation:	'	'	'
Benefit obligation at beginning of year	65.3	55.3	'
Projected benefit obligation attributable to acquisitions	0	4.9	'
Service cost	0.4	1.1	0.3
Interest cost	2.4	2.4	1.6
Plan curtailments	0	-3.7	'
Benefits paid	-2.3	-2.6	'
Actuarial (gain) loss	-8.5	7.9	'
Administrative expense	-0.1	0	'
Plan amendments	0	0	'
Employee contributions	0	0	'
Benefit obligation at end of year	57.2	65.3	55.3
Change in plan assets:	'	'	'
Fair value of plan assets at beginning of year	41.6	36	'
Fair value of pension assets attributable to acquisitions	0	3.2	'
Benefit payments	-2.3	-2.6	'
Actual return on assets	3.2	1.9	'
Administrative expense	-0.1	0	'
Employee contributions	0	0	'
Employer contribution	3.4	3.1	'
Fair value of plan assets at end of year	45.8	41.6	36
Funded status â€” benefit obligation in excess of plan assets	-11.4	-23.7	'
Reconciliation of amounts recognized in the consolidated balance sheets:	'	'	'
Accrued benefit obligation, long-term	-11.4	-23.7	'
Prior service credit	0	0	'
Unrecognized net actuarial (gain) loss	2.3	11.9	'
Accumulated other comprehensive (income) loss	2.3	11.9	'
Net amount recognized at end of year	-9.1	-11.8	'
Other Postretirement Benefit Plans, Defined Benefit	'	'	'
Change in projected benefit obligation:	'	'	'
Benefit obligation at beginning of year	0.3	7.7	'
Projected benefit obligation attributable to acquisitions	0	0	'
Service cost	0	0.3	0.1
Interest cost	0	0.2	0.1
Plan curtailments	0	-7.9	'
Benefits paid	0	-0.1	'
Actuarial (gain) loss	0	0.1	'
Administrative expense	0	0	'
Plan amendments	0	-0.1	'
Employee contributions	0	0.1	'
Benefit obligation at end of year	0.3	0.3	7.7
Change in plan assets:	'	'	'
Fair value of plan assets at beginning of year	0	0	'
Fair value of pension assets attributable to acquisitions	0	0	'
Benefit payments	0	-0.1	'
Actual return on assets	0	0	'
Administrative expense	0	0	'
Employee contributions	0	0.1	'
Employer contribution	0	0	'
Fair value of plan assets at end of year	0	0	0
Funded status â€” benefit obligation in excess of plan assets	-0.3	-0.3	'
Reconciliation of amounts recognized in the consolidated balance sheets:	'	'	'
Accrued benefit obligation, long-term	-0.3	-0.3	'
Prior service credit	-0.2	-0.2	'
Unrecognized net actuarial (gain) loss	-0.2	-0.2	'
Accumulated other comprehensive (income) loss	-0.4	-0.4	'
Net amount recognized at end of year	($0.70)	($0.70)	'

Employee_Benefit_Plans_Details4

Employee Benefit Plans (Details 4) (Pension Plans, Defined Benefit, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Accumulated benefit obligation	$56.70	$63.40
Accumulated benefit obligation in excess of fair value of plan assets, accumulated benefit obligation	52.9	63.4
Accumulated benefit obligation in excess of fair value of plan assets, fair value of plan assets	$41.80	$41.60

Employee_Benefit_Plans_Details5

Employee Benefit Plans (Details 5) (Pension Plans, Defined Benefit, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Plans with Benefit Obligations in Excess of Plan Assets, Aggregate Benefit Obligation	$57.20	$65.30
Defined Benefit Plan, Plans with Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	$45.80	$41.60

Employee_Benefit_Plans_Details6

Employee Benefit Plans (Details 6) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit	'	'	'
Components of net periodic pension and other post retirement benefits cost	'	'	'
Service cost	$0.40	$1.10	$0.30
Interest cost	2.4	2.4	1.6
Expected return on assets	-2.9	-1.7	-1.2
Amortization of net loss	0.8	0.6	0.2
Curtailment gain recognized	0	-0.2	0
Settlement gain recognized	0	0	0
Net periodic benefit cost (income)	0.7	2.2	0.9
Other Post Retirement Employee Benefits	'	'	'
Components of net periodic pension and other post retirement benefits cost	'	'	'
Service cost	0	0.3	0.1
Interest cost	0	0.2	0.1
Expected return on assets	0	0	0
Amortization of net loss	0	0	0
Curtailment gain recognized	0	-7	0
Settlement gain recognized	0	-0.2	0
Net periodic benefit cost (income)	$0	($6.70)	$0.20

Employee_Benefit_Plans_Details7

Employee Benefit Plans (Details 7) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]	'	'	'
Total recognized in other comprehensive (income) loss	($9.60)	$3	$3.70
Classified in accumulated other comprehensive loss	-1.9	-11.5	'
Amounts that will be amortized from accumulated other comprehensive income in next fiscal year	0.3	'	'
Pension Plans, Defined Benefit	'	'	'
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]	'	'	'
Net (gain) loss	-8.8	4.3	3.3
New prior service cost	0	0	0
Amortization or settlement recognition of net loss	-0.8	-0.6	-0.2
Amortization or curtailment recognition of prior service credit	0	0	0
Total recognized in other comprehensive (income) loss	-9.6	3.7	3.1
Classified in accumulated other comprehensive loss	2.3	11.9	'
Other Postretirement Benefit Plans, Defined Benefit	'	'	'
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]	'	'	'
Net (gain) loss	0	0.1	0.6
New prior service cost	0	-0.1	0
Amortization or settlement recognition of net loss	0	-0.8	0
Amortization or curtailment recognition of prior service credit	0	0.1	0
Total recognized in other comprehensive (income) loss	0	-0.7	0.6
Classified in accumulated other comprehensive loss	($0.40)	($0.40)	'

Employee_Benefit_Plans_Details8

Employee Benefit Plans (Details 8)	12 Months Ended
Employee Benefit Plans (Details 8)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Postretirement Benefit Plans, Defined Benefit	'	'	'
Assumed Trend Rates	'	'	'
Immediate trend rate	7.70%	8.00%	8.20%
Superior Plan \| Pension Plans, Defined Benefit	'	'	'
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations	'	'	'
Discount rate	4.66%	3.75%	'
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount rate	3.75%	4.55%	4.71%
Expected return on plan assets	6.75%	3.00%	6.50%
Rate of compensation increase	'	3.75%	3.75%
Superior Plan \| Other Postretirement Benefit Plans, Defined Benefit	'	'	'
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount rate	'	4.65%	4.82%
Assumed Trend Rates	'	'	'
Net periodic cost ultimate trend rate	'	4.50%	5.00%
Net periodic cost year that rate reaches ultimate trend rate	'	'2029	'2020
Montana Plan \| Pension Plans, Defined Benefit	'	'	'
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations	'	'	'
Discount rate	4.97%	4.03%	'
Rate of compensation increase	3.00%	3.00%	'
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount rate	4.03%	3.89%	'
Expected return on plan assets	6.75%	6.00%	'
Rate of compensation increase	3.00%	3.00%	'
Penreco Plan \| Pension Plans, Defined Benefit	'	'	'
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations	'	'	'
Discount rate	4.78%	3.86%	'
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount rate	3.86%	4.63%	5.50%
Expected return on plan assets	6.75%	6.00%	6.50%
Penreco Plan \| Other Postretirement Benefit Plans, Defined Benefit	'	'	'
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations	'	'	'
Discount rate	4.29%	3.33%	'
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	'	'	'
Discount rate	3.33%	4.04%	4.54%
Assumed Trend Rates	'	'	'
Immediate trend rate	7.50%	7.70%	'
Benefit obligation ultimate trend rate	4.50%	4.50%	'
Net periodic cost ultimate trend rate	4.50%	4.50%	4.50%
Benefit obligation year that rate reaches ultimate trend rate	'2029	'2029	'
Net periodic cost year that rate reaches ultimate trend rate	'2029	'2029	'2029
Assumed annual percentage change for trend rate	-0.20%	'	'

Employee_Benefit_Plans_Details9

Employee Benefit Plans (Details 9) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]	'
1% Point Increase or decrease, effect on postretirement benefit obligation	$0.10
Penreco Plan \| Other Postretirement Benefit Plans, Defined Benefit	'
Defined Benefit Plan Disclosure [Line Items]	'
1% Increase or decrease, effect on service and interest cost	$0.10

Recovered_Sheet4

Employee Benefit Plans (Details 10)	12 Months Ended
Employee Benefit Plans (Details 10)	Dec. 31, 2013
Equity funds	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'
Target Allocation Minimum	0.00%
Target Allocation Maximum	50.00%
Target Allocation	25.00%
Foreign equities	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'
Target Allocation Minimum	0.00%
Target Allocation Maximum	50.00%
Target Allocation	25.00%
Fixed income	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'
Target Allocation Minimum	50.00%
Target Allocation Maximum	100.00%
Target Allocation	50.00%

Recovered_Sheet5

Employee Benefit Plans (Details 11) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Level 1	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	38.9
Level 2	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	45.8	2.7
Cash and cash equivalents	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	46.00%
Cash and cash equivalents \| Level 1	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	19.3
Cash and cash equivalents \| Level 2	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	0
Equity funds	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	23.00%	14.00%
Equity funds \| Level 1	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	5.9
Equity funds \| Level 2	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	10.6	0
Foreign equities	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	23.00%	6.00%
Foreign equities \| Level 1	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	2.3
Foreign equities \| Level 2	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	10.6	0
Fixed income	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	54.00%	20.00%
Fixed income \| Level 1	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	8.4
Fixed income \| Level 2	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	24.6	0
Commingled fund	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	7.00%
Commingled fund \| Level 1	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	0
Commingled fund \| Level 2	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	2.7
Balanced fund	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	7.00%
Balanced fund \| Level 1	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	3
Balanced fund \| Level 2	'	'
Schedule of Pension Plan assets measured at fair value	'	'
Fair value of plan assets	0	0

Recovered_Sheet6

Employee Benefit Plans (Details 12) (Pension Plans, Defined Benefit, USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Pension Plans, Defined Benefit	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	$2.50
2015	2.6
2016	2.7
2017	2.8
2018	3
2019 to 2023	17.1
Total	$30.70

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Beginning balance: Accumulated other comprehensive loss	($25.50)	'	'
Other comprehensive income (loss) before reclassifications	-28.2	'	'
Amounts reclassified from accumulated other comprehensive loss	0.3	'	'
Total other comprehensive income (loss)	-27.9	-64	66.1
Ending balance: Accumulated other comprehensive loss	-53.4	-25.5	'
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges	'	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Beginning balance: Accumulated other comprehensive loss	-14	'	'
Other comprehensive income (loss) before reclassifications	-36.9	'	'
Amounts reclassified from accumulated other comprehensive loss	-0.5	'	'
Total other comprehensive income (loss)	-37.4	'	'
Ending balance: Accumulated other comprehensive loss	-51.4	'	'
Accumulated Defined Benefit Plans Adjustment	'	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Beginning balance: Accumulated other comprehensive loss	-11.5	'	'
Other comprehensive income (loss) before reclassifications	8.8	'	'
Amounts reclassified from accumulated other comprehensive loss	0.8	'	'
Total other comprehensive income (loss)	9.6	'	'
Ending balance: Accumulated other comprehensive loss	-1.9	'	'
Accumulated Translation Adjustment	'	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Beginning balance: Accumulated other comprehensive loss	0	'	'
Other comprehensive income (loss) before reclassifications	-0.1	'	'
Amounts reclassified from accumulated other comprehensive loss	0	'	'
Total other comprehensive income (loss)	-0.1	'	'
Ending balance: Accumulated other comprehensive loss	($0.10)	'	'

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Loss) (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'	'	'
Total other comprehensive income (loss)	($27.90)	($64)	$66.10
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges	'	'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'	'	'
Total other comprehensive income (loss)	-37.4	'	'
Accumulated Defined Benefit Plans Adjustment	'	'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'	'	'
Total other comprehensive income (loss)	9.6	'	'
Reclassification out of Accumulated Other Comprehensive Income \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges	'	'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'	'	'
Sales	-3.1	'	'
Cost of Goods Sold	3.6	'	'
Total other comprehensive income (loss)	0.5	'	'
Reclassification out of Accumulated Other Comprehensive Income \| Accumulated Defined Benefit Plans Adjustment	'	'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'	'	'
Other Income	-0.8	'	'
Total other comprehensive income (loss)	($0.80)	'	'

Earnings_Per_Unit_Details

Earnings Per Unit (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Numerator for basic and diluted earnings per limited partner unit:	'	'	'	'	'	'	'	'	'	'	'
Net income	($15.50)	($34.80)	$7.80	$46	$45.70	$42.40	$65.70	$51.90	$3.50	$205.70	$43
General partnerâ€™s interest in net income	'	'	'	'	'	'	'	'	-0.1	-4.1	-0.9
General partnerâ€™s incentive distribution rights	'	'	'	'	'	'	'	'	-14.7	-5.5	-0.2
Nonvested share based payments	'	'	'	'	'	'	'	'	-0.2	-1.1	0
Net income (loss) available to limited partners	($19)	($37.90)	$3.80	$41.70	$42.30	$39.70	$62.90	$50.10	($11.50)	$195	$41.90
Denominator for basic and diluted earnings per limited partner unit:	'	'	'	'	'	'	'	'	'	'	'
Weighted average limited partner units outstanding â€” basic	69,635,865	69,626,650	69,571,855	62,831,155	57,745,881	57,745,806	55,027,786	51,684,741	67,938,784	55,559,183	42,598,876
Participating securities â€” phantom units	'	'	'	'	'	'	'	'	0	117,558	45,210
Weighted average limited partner units outstanding â€” diluted	69,635,865	69,626,650	69,769,536	63,017,869	57,898,207	57,825,603	55,074,265	51,736,396	67,938,784	55,676,741	42,644,086
Limited partnersâ€™ interest basic net income (loss) per unit	($0.27)	($0.54)	$0.05	$0.67	$0.73	$0.69	$1.14	$0.97	($0.17)	$3.51	$0.98
Limited partnersâ€™ interest diluted net income (loss) per unit	($0.27)	($0.54)	$0.05	$0.66	$0.73	$0.69	$1.14	$0.97	($0.17)	$3.50	$0.98
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	'	'	'	'	'	'	'	200,000	'	'

Transactions_with_Related_Part1

Transactions with Related Parties Transactions with Related Parties (Details Textual) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Number of crude oil supply agreement with related party	1	'	'
Limited Partners	'	'	'
Related Party Transaction [Line Items]	'	'	'
Product sales to related parties	$9.70	$9.30	$16.50
Trade accounts and other receivables	0.2	0.1	'
Excluding Legacy Resources	'	'	'
Related Party Transaction [Line Items]	'	'	'
Purchases from related party	9	7.2	1.8
Accounts payable from related parties	4.3	2.2	'
Legacy Resources	'	'	'
Related Party Transaction [Line Items]	'	'	'
Purchases from related party	1.2	1.1	229.8
Accounts payable from related parties	0.1	0.1	'
Tobias Insurance Group, Inc	'	'	'
Related Party Transaction [Line Items]	'	'	'
Purchases from related party	$0.70	$0.50	$0.60

Segments_and_Related_Informati3

Segments and Related Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	$1,243.10	$1,505.50	$1,354.20	$1,318.60	$1,220.90	$1,179.80	$1,087	$1,169.60	$5,421.40	$4,657.30	$3,134.90
Adjusted EBITDA	'	'	'	'	'	'	'	'	241.5	404.6	211
Reconciling items to net income:	'	'	'	'	'	'	'	'	'	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	133.7	105	74.5
Realized gain (loss) on derivatives, not reflected in net income (loss)	'	'	'	'	'	'	'	'	-1.8	-5	10.9
Unrealized (gain) loss on derivatives	'	'	'	'	'	'	'	'	-25.7	3.8	10.4
Interest expense	'	'	'	'	'	'	'	'	96.8	85.6	48.7
Debt extinguishment costs	'	'	'	'	'	'	'	'	14.6	0	15.1
Non-cash equity based compensation and other non-cash items	'	'	'	'	'	'	'	'	20	8.7	7.4
Income tax expense	'	'	'	'	'	'	'	'	0.4	0.8	1
Net income	-15.5	-34.8	7.8	46	45.7	42.4	65.7	51.9	3.5	205.7	43
Sales Revenue, Segment	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	5,421.40	4,657.30	3,134.90
Intersubsegment Eliminations	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	0	0	0
Intersegment Eliminations	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	-77.3	-50.2	-45.8
Adjusted EBITDA	'	'	'	'	'	'	'	'	0	0	0
Reconciling items to net income:	'	'	'	'	'	'	'	'	'	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	0	0	'
Realized gain (loss) on derivatives, not reflected in net income (loss)	'	'	'	'	'	'	'	'	0	0	0
Intersegment Eliminations \| Sales Revenue, Segment	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	0	0	0
Intersegment Eliminations \| Intersubsegment Eliminations	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	-77.3	-50.2	-45.8
Specialty Product \| Operating Segments	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	1,774.90	1,849.90	1,630.50
Adjusted EBITDA	'	'	'	'	'	'	'	'	194.5	283.2	280.6
Reconciling items to net income:	'	'	'	'	'	'	'	'	'	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	66.6	55.8	43.2
Realized gain (loss) on derivatives, not reflected in net income (loss)	'	'	'	'	'	'	'	'	-0.5	-1.9	2.5
Specialty Product \| Operating Segments \| Sales Revenue, Segment	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	1,774.90	1,849.90	1,630.50
Specialty Product \| Operating Segments \| Intersubsegment Eliminations	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	0	0	0
Fuel Product \| Operating Segments	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	3,723.80	2,857.60	1,550.20
Adjusted EBITDA	'	'	'	'	'	'	'	'	47	121.4	-69.6
Reconciling items to net income:	'	'	'	'	'	'	'	'	'	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	67.1	49.2	31.3
Realized gain (loss) on derivatives, not reflected in net income (loss)	'	'	'	'	'	'	'	'	-1.3	-3.1	8.4
Fuel Product \| Operating Segments \| Sales Revenue, Segment	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	3,646.50	2,807.40	1,504.40
Fuel Product \| Operating Segments \| Intersubsegment Eliminations	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	77.3	50.2	45.8
Combined Segments \| Operating Segments	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	5,498.70	4,707.50	3,180.70
Adjusted EBITDA	'	'	'	'	'	'	'	'	241.5	404.6	211
Reconciling items to net income:	'	'	'	'	'	'	'	'	'	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	133.7	105	74.5
Realized gain (loss) on derivatives, not reflected in net income (loss)	'	'	'	'	'	'	'	'	-1.8	-5	10.9
Combined Segments \| Operating Segments \| Sales Revenue, Segment	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	5,421.40	4,657.30	3,134.90
Combined Segments \| Operating Segments \| Intersubsegment Eliminations	'	'	'	'	'	'	'	'	'	'	'
Reportable segment information	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	77.3	50.2	45.8
Eliminations	'	'	'	'	'	'	'	'	'	'	'
Reconciling items to net income:	'	'	'	'	'	'	'	'	'	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	'	'	$0

Segments_and_Related_Informati4

Segments and Related Information (Details 1) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	$1,243.10	$1,505.50	$1,354.20	$1,318.60	$1,220.90	$1,179.80	$1,087	$1,169.60	$5,421.40	$4,657.30	$3,134.90
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	54.10%	65.00%	55.20%
Specialty Product	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Number of products	'	'	'	'	'	'	'	'	5	'	'
Product Concentration Risk	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	5,421.40	4,657.30	3,134.90
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	100.00%	100.00%	100.00%
Product Concentration Risk \| Specialty Product	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	1,774.90	1,849.90	1,630.50
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	32.70%	39.70%	52.00%
Product Concentration Risk \| Specialty Product \| Lubricating oils	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	848.8	1,007.90	947.8
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	15.70%	21.60%	30.20%
Product Concentration Risk \| Specialty Product \| Solvents	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	511.7	491.1	495.9
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	9.40%	10.50%	15.80%
Product Concentration Risk \| Specialty Product \| Waxes	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	141	142.8	143.1
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	2.60%	3.10%	4.60%
Product Concentration Risk \| Specialty Product \| Packaged and synthetic specialty products	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	233.6	161.7	0
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	4.30%	3.50%	0.00%
Product Concentration Risk \| Specialty Product \| Other	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	39.8	46.4	43.7
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	0.70%	1.00%	1.40%
Product Concentration Risk \| Fuel Product	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	3,646.50	2,807.40	1,504.40
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	67.30%	60.30%	48.00%
Product Concentration Risk \| Fuel Product \| Gasoline	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	1,409.40	1,174.90	619.6
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	26.00%	25.20%	19.80%
Product Concentration Risk \| Fuel Product \| Diesel	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	1,259.20	941	513.3
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	23.30%	20.20%	16.40%
Product Concentration Risk \| Fuel Product \| Jet fuel	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	191.4	184	148
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	3.50%	4.00%	4.70%
Product Concentration Risk \| Fuel Product \| Asphalt, heavy fuel oils and other	'	'	'	'	'	'	'	'	'	'	'
Major product category sales	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	$786.50	$507.50	$223.50
Concentration Risk, Percentage	'	'	'	'	'	'	'	'	14.50%	10.90%	7.10%

Segments_and_Related_Informati5

Segments and Related Information (Details 2)	12 Months Ended
Segments and Related Information (Details 2)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting [Abstract]	'	'	'
Concentration Risk, Percentage	54.10%	65.00%	55.20%

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Sales	$1,243.10	$1,505.50	$1,354.20	$1,318.60	$1,220.90	$1,179.80	$1,087	$1,169.60	$5,421.40	$4,657.30	$3,134.90
Gross profit	112.5	62.1	101	134.4	141.8	158.4	128.8	84.2	410	513.2	274.1
Net income (loss)	-15.5	-34.8	7.8	46	45.7	42.4	65.7	51.9	3.5	205.7	43
Net income (loss) available to limited partners	($19)	($37.90)	$3.80	$41.70	$42.30	$39.70	$62.90	$50.10	($11.50)	$195	$41.90
Limited partnersâ€™ interest basic net income (loss) per unit	($0.27)	($0.54)	$0.05	$0.67	$0.73	$0.69	$1.14	$0.97	($0.17)	$3.51	$0.98
Limited partnersâ€™ interest diluted net income (loss) per unit	($0.27)	($0.54)	$0.05	$0.66	$0.73	$0.69	$1.14	$0.97	($0.17)	$3.50	$0.98
Weighted average limited partner units outstanding â€” basic	69,635,865	69,626,650	69,571,855	62,831,155	57,745,881	57,745,806	55,027,786	51,684,741	67,938,784	55,559,183	42,598,876
Weighted average limited partner units outstanding â€” diluted	69,635,865	69,626,650	69,769,536	63,017,869	57,898,207	57,825,603	55,074,265	51,736,396	67,938,784	55,676,741	42,644,086

Subsequent_Events_Details

Subsequent Events (Details) (Subsequent Event, USD $)	12 Months Ended	3 Months Ended		0 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Feb. 28, 2014
	Dec. 31, 2013	Dividend Declared	Dividend Paid	United Acquisition [Member]
Partners' Capital Account, Distributions [Abstract]	'	'	'	'
Cash distribution per unit	'	$0.69	$2.74	'
Dividends Payable	'	$52.60	$210.40	'
Aggregate quarterly distribution	'	24-Jan-14	'	'
Distribution paid date	'	'	14-Feb-14	'
Record date for the close of business	'	'	4-Feb-14	'
Fair Value Disclosures [Abstract]	'	'	'	'
Derivative decrease to fair value	-56	'	'	'
Fair of value net liability	1	'	'	'
Long-term debt increase to fair value	40	'	'	'
Business Combination, Consideration Transferred	'	'	'	$10.40