Calumet Specialty Products Partners (CLMT) 10-K 29 Feb 16 2014 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 29, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Calumet Specialty Products Partners, L.P.
Entity Central Index Key	1,340,122
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,014
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			$ 1,514.9
Entity Common Stock, Shares Outstanding		75,884,400

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 5.6	$ 8.5
Accounts receivable:
Trade, less allowance for doubtful accounts of $2.0 million and $1.6 million, respectively	195.3	326
Other	15.4	23.8
Total accounts receivable	210.7	349.8
Inventories	384.4	513.5
Derivative assets	0	23.2
Prepaid expenses and other current assets	8.3	9.2
Total current assets	609	904.2
Property, plant and equipment, net	1,719.2	1,464.4
Investment in unconsolidated affiliates	126	137.3
Goodwill	212	245.8
Other intangible assets, net	214.1	257.5
Deferred Tax Assets, Net, Noncurrent	0	2.3
Other noncurrent assets, net	64.4	73.6
Total assets	2,944.7	3,085.1
Current liabilities:
Accounts payable	316.6	419.9
Accrued interest payable	31.1	37.6
Accrued salaries, wages and benefits	32.9	21.9
Other taxes payable	17.9	17.9
Other current liabilities	119	40
Current portion of long-term debt	1.7	0.6
Notes Payable, Related Parties, Current	73.5	0
Derivative liabilities	33.9	5.6
Total current liabilities	626.6	543.5
Deferred income taxes	2.1	32.3
Pension and postretirement benefit obligations	13	20
Other long-term liabilities	0.9	0.9
Long-term debt, less current portion	1,698.2	1,678.2
Total liabilities	$ 2,340.8	$ 2,274.9
Commitments and contingencies
Partners’ capital:
Limited partners’ interest (75,884,400 units and 69,452,233 units, issued and outstanding at December 31, 2015 and 2014, respectively)	$ 578	$ 765.9
General partner’s interest	27.5	30.6
Accumulated other comprehensive income (loss)	(1.6)	13.7
Total partners’ capital	603.9	810.2
Total liabilities and partners’ capital	$ 2,944.7	$ 3,085.1

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Allowance for doubtful accounts	$ 2	$ 1.6
Limited Partners
Limited Partners' Capital Account, Units Issued	75,884,400	69,452,233
Limited Partners' Capital Account, Units Outstanding	75,884,400	69,452,233

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Income Statement [Abstract]
Net Income (Loss), Net of Tax, Per Outstanding Limited Partnership Unit, Diluted		$ (2.05)		$ (1.80)		$ (0.17)
Sales		$ 4,212.8		$ 5,791.1		$ 5,421.4
Cost of sales		3,618.2		5,261.4		5,011.4
Gross profit		594.6	[1]	529.7	[1]	410
Operating costs and expenses:
Selling		146		149.6		62.6
General and administrative		135.5		98.3		82.1
Transportation		175.5		171.4		142.7
Taxes other than income taxes		17.7		13.4		14.2
Goodwill and Intangible Asset Impairment		33.8		36		10.5
Other		11.1		14.2		6.3
Operating income		75		46.8		91.6
Other income (expense):
Interest expense		(104.9)		(110.8)		(96.8)
Debt extinguishment costs		(46.6)		(89.9)		(14.6)
Gain (Loss) on Derivative Instruments, Net, Pretax		8.1		43.8		(4.7)
Unrealized gain (loss) on derivative instruments		(39.5)		(0.6)		25.7
Income (Loss) from Equity Method Investments		(61.5)		(3.4)		(0.3)
Other		1.6		1.1		3
Total other expense		(242.8)		(159.8)		(87.7)
Net income (loss) before income taxes		(167.8)		(113)		3.9
Income tax expense (benefit)		(28.4)		(0.8)		0.4
Allocation of net income (loss):
Net income (loss)		(139.4)	[1]	(112.2)	[1]	3.5
Less:
General partner’s interest in net income (loss)		(2.8)		(2.2)		0.1
General partner's incentive distribution rights		16.8		15.4		14.7
Non-vested share based payments		0		0		0.2
Net loss available to limited partners		$ (153.4)	[1]	$ (125.4)	[1]	$ (11.5)
Weighted average limited partner units outstanding:
Basic		74,896,096		69,671,827		67,938,784
Diluted	[2]	74,896,096		69,671,827		67,938,784
Limited partners’ interest basic net income (loss) per unit		$ (2.05)		$ (1.80)		$ (0.17)
Cash distributions declared per limited partner unit		$ 2.74		$ 2.74		$ 2.70
[1]	(1) The sum of the four quarters may not equal the total year due to rounding.
[2]	(1) Total diluted weighted average limited partner units outstanding excludes 0.4 million, 0.2 million and 0.2 million potentially dilutive phantom units for the years ended December 31, 2015, 2014 and 2013, respectively.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (139.4)	[1]	$ (112.2)	[1]	$ 3.5
Cash flow hedges:
Cash flow hedge gain reclassified to net income (loss)	(12.1)		(37)		(0.5)
Change in fair value of cash flow hedges	(7.3)		114.2		(36.9)
Defined benefit pension and retiree health benefit plans	4.7		(9.6)		9.6
Foreign currency translation adjustment	(0.6)		(0.5)		(0.1)
Total other comprehensive income (loss)	(15.3)		67.1		(27.9)
Comprehensive loss attributable to partners’ capital	$ (154.7)		$ (45.1)		$ (24.4)
[1]	(1) The sum of the four quarters may not equal the total year due to rounding.

Consolidated Statements of Part

Consolidated Statements of Partners' Capital - USD ($) $ in Millions	Total		Accumulated Other Comprehensive Income (Loss)	General Partner	Limited Partners
Beginning balance at Dec. 31, 2012	$ 889.8		$ (25.5)	$ 30.5	$ 884.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	(27.9)		(27.9)	0	0
Net income (loss)	3.5		0	14.8	(11.3)
Common units repurchased for phantom unit grants	(5)		0	0	(5)
Stock Issued During Period, Value, Share-based Compensation, Gross	(0.3)		0	0	(0.3)
Cash settlement of unit based compensation	0
Amortization of vested phantom units	3.2		0	0	3.2
Proceeds from public offerings of common units, net	392.5		0	0	392.5
Contributions from Calumet GP, LLC	8.4		0	8.4	0
Distributions to partners	(201.4)		0	(17.1)	(184.3)
Ending balance at Dec. 31, 2013	1,062.8		(53.4)	36.6	1,079.6
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	67.1		67.1	0	0
Net income (loss)	(112.2)	[1]	0	13.2	(125.4)
Common units repurchased for phantom unit grants	(2.2)		0	0	(2.2)
Stock Issued During Period, Value, Share-based Compensation, Gross	(1.2)		0	0	(1.2)
Cash settlement of unit based compensation	(0.9)		0	0	(0.9)
Amortization of vested phantom units	3		0	0	3
Proceeds from public offerings of common units, net	3.6		0	0	3.6
Contributions from Calumet GP, LLC	0.1		0	0.1	0
Distributions to partners	(209.9)		0	(19.3)	(190.6)
Ending balance at Dec. 31, 2014	810.2		13.7	30.6	765.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	(15.3)		(15.3)	0	0
Net income (loss)	(139.4)	[1]	0	14	(153.4)
Common units repurchased for phantom unit grants	(3.6)		0	0	(3.6)
Stock Issued During Period, Value, Share-based Compensation, Gross	(1.5)		0	0	(1.5)
Reclassification of Liability Awards to Equity	7.9		0	0	7.9
Cash settlement of unit based compensation	0
Amortization of vested phantom units	2.4		0	0	2.4
Proceeds from public offerings of common units, net	164.1		0	0	164.1
Contributions from Calumet GP, LLC	3.5		0	3.5	0
Distributions to partners	(224.4)		0	(20.6)	(203.8)
Ending balance at Dec. 31, 2015	$ 603.9		$ (1.6)	$ 27.5	$ 578
[1]	(1) The sum of the four quarters may not equal the total year due to rounding.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Operating activities
Net income (loss)	$ (139.4)	[1]	$ (112.2)	[1]	$ 3.5
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	145.4		138.6		117.8
Amortization of turnaround costs	29		24.5		15.9
Non-cash interest expense	6.6		6.4		7
Non-cash debt extinguishment costs	9.1		19		3.4
Provision for doubtful accounts	1.1		0.5		0.1
Unrealized (gain) loss on derivative instruments	39.5		0.6		(25.7)
Goodwill and Intangible Asset Impairment	33.8		36		10.5
Loss on disposal of fixed assets	2.9		4.8		15.2
Non-cash equity based compensation	9.8		6.5		4.8
Deferred income tax benefit	(28.5)		(1.2)		0
Lower of cost or market inventory adjustment	81.8		74.1		(2.1)
Loss from unconsolidated affiliates	61.5		3.4		0.3
Other non-cash activities	5.9		0.7		(10.2)
Changes in assets and liabilities:
Accounts receivable	138		(0.4)		(32.3)
Inventories	47.3		43.9		16.4
Prepaid expenses and other current assets	3.4		3.9		6.8
Derivative activity	(7)		6.7		(1.8)
Turnaround costs	(19.3)		(27.6)		(68.6)
Other assets	0		0		(0.1)
Accounts payable	(119.9)		(13.1)		6.8
Accrued interest payable	(6.5)		15.1		(1)
Accrued salaries, wages and benefits	10.2		(14.7)		(7.1)
Accrued income taxes payable	0		0		(27.6)
Other taxes payable	0.2		(1.1)		3
Other liabilities	73.8		13.7		6.8
Pension and postretirement benefit obligations	(2.3)		(1.3)		(2.7)
Net cash provided by operating activities	376.4		226.8		39.1
Investing activities
Additions to property, plant and equipment	(339.3)		(289.9)		(160.8)
Investment in unconsolidated affiliates	(58.6)		(105.4)		(31.8)
Cash paid for acquisitions, net of cash acquired	0		(263.6)		(177.7)
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	8.4		0		0
Proceeds from sale of property, plant and equipment	0.5		0.1		0
Net cash used in investing activities	(389)		(658.8)		(370.3)
Financing activities
Proceeds from borrowings — revolving credit facility	1,390		1,625.1		865.6
Repayments of borrowings — revolving credit facility	(1,429.8)		(1,474.3)		(865.6)
Repayments of borrowings — senior notes	(275)		(500)		(100)
Repayments of borrowings — acquisition debt assumed	0		0		(11.9)
Proceeds from Related Party Debt	75		0		0
Payments on capital lease obligations	(8)		(1.9)		(1.1)
Proceeds from other financing obligations	1.1		0		3.5
Proceeds from public offerings of common units, net	164.1		3.6		392.5
Proceeds from senior notes offerings	322.6		900		344.7
Payments of Debt Issuance Costs	(5.6)		(19.9)		(7.3)
Contributions from Calumet GP, LLC	3.5		0.1		8.4
Common units repurchased and taxes paid for phantom unit grants	(3.6)		(2.2)		(7.1)
Cash settlement of unit based compensation	0		(0.9)		0
Distributions to partners	(224.6)		(210.2)		(201.6)
Net cash provided by financing activities	9.7		319.4		420.1
Net increase (decrease) in cash and cash equivalents	(2.9)		(112.6)		88.9
Cash and cash equivalents at beginning of year	8.5		121.1		32.2
Cash and cash equivalents at end of year	5.6		8.5		121.1
Supplemental disclosure of cash flow information
Interest paid, net of capitalized interest	120.6		107.8		91.4
Income taxes paid	1.1		0.5		29.8
Non-cash property, plant and equipment additions	56.5		39.9		13.1
Non-cash capital lease	$ 4.4		$ 39.4		$ 0
[1]	(1) The sum of the four quarters may not equal the total year due to rounding.

Description of the Business

Description of the Business	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Business	Description of the Business Calumet Specialty Products Partners, L.P. (the “Company”) is a publicly traded Delaware limited partnership listed on the NASDAQ Global Select Market (“NASDAQ”) under the ticker symbol “CLMT.” The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of December 31, 2015 , the Company had 75,884,400 limited partner common units and 1,548,660 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, in addition to oilfield services and products. The Company is based in Indianapolis, Indiana and owns specialty and fuel products facilities. The Company owns and leases oilfield services locations and leases additional facilities, primarily related to production and distribution of specialty, fuel and oilfield services products, throughout the United States (“U.S.”).

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2015
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 principles (“U.S. GAAP”) 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 include 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. 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, 2015 2014 2013 Beginning balance $ 1.6 $ 1.2 $ 1.2 Provision 1.1 0.5 0.1 Write-offs, net (0.7 ) (0.1 ) (0.1 ) Ending balance $ 2.0 $ 1.6 $ 1.2 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 $41.0 million lower and $18.9 million lower as of December 31, 2015 and 2014 , respectively. At December 31, 2015 and 2014 , the Company had $1.4 million and $1.7 million , respectively, of consigned inventory. Inventories consisted of the following (in millions): December 31, 2015 2014 Raw materials $ 47.9 $ 77.8 Work in process 64.0 75.4 Finished goods 272.5 360.3 $ 384.4 $ 513.5 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, 2015 , 2014 and 2013 , the Company recorded gains and (losses) of $(24.3) million , $(26.5) million and $4.2 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. Such write downs are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. During the years ended December 31, 2015 and 2014 the Company recorded $81.8 million and $74.1 million , respectively, of losses in cost of sales in the consolidated statements of operations due to the lower of cost or market valuation. During the year ended December 31, 2013 , the Company recorded $2.1 million of gains 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, 2015 2014 Land $ 19.5 $ 18.3 Buildings and improvements (10 to 40 years) 70.2 66.8 Machinery and equipment (10 to 20 years) 1,629.7 1,420.7 Furniture and fixtures (5 to 10 years) 28.5 21.8 Assets under capital leases (4 to 26 years) 49.0 48.9 Construction-in-progress 466.4 354.0 2,263.3 1,930.5 Less accumulated depreciation (544.1 ) (466.1 ) $ 1,719.2 $ 1,464.4 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 2015 , 2014 and 2013 , the Company incurred $133.5 million , $122.8 million and $101.2 million , respectively, of interest expense of which $28.6 million , $12.0 million and $4.4 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, 2015 or 2014 because such potential obligations cannot be measured since it is not possible to estimate the settlement dates. During the years ended December 31, 2015 , 2014 and 2013 , the Company recorded $102.0 million , $98.3 million and $92.0 million , respectively, of depreciation expense on its property, plant and equipment. Depreciation expense included $2.6 million , $0.8 million and $0.7 million for the years ended 2015 , 2014 and 2013 , 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, 2015 and 2014 , the Company had $17.4 million and $17.4 million , respectively, of capitalized software costs. As of December 31, 2015 and 2014 , the Company had $13.1 million and $8.9 million , respectively of accumulated depreciation related to the capitalized software costs. During the years ended December 31, 2015 , 2014 and 2013 , the Company recorded $4.2 million , $3.4 million , and $3.3 million , respectively, of amortization expense on capitalized computer software. Capitalized software is included in furniture and fixtures. Investment in Unconsolidated Affiliates The Company accounts for its ownership in its Dakota Prairie Refining, LLC and Juniper GTL LLC joint ventures in accordance with ASC 323, Investments — Equity Method and Joint Ventures. 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 as 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. The Company recorded a $24.3 million impairment charge in loss from unconsolidated affiliates in the consolidated statement of operations for the year ended December 31, 2015 . No impairment was recognized in 2014 and 2013 . For further information on investment in unconsolidated affiliates, 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”). 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. 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. Due to the continued decline in crude oil prices, the Company updated its goodwill impairment analysis as of September 30, 2015, resulting in the fair value of one reporting unit to be less than its carrying value. An impairment charge of $33.8 million was recorded on goodwill as a result of this step 2 analysis. An impairment charge of $36.0 million was recorded on goodwill in 2014 . No impairment was recognized on goodwill in 2013 based upon the quantitative and qualitative assessments. Definite Lived Intangible Assets Definite lived 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 turnaround costs. Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $60.4 million and $70.1 million as of December 31, 2015 and 2014 , 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 $71.6 million and $46.2 million at December 31, 2015 and 2014 , respectively. Other Current Liabilities Other current liabilities consisted of the following at December 31, 2015 and 2014 (in millions): December 31, 2015 2014 RINs Obligation $ 88.4 $ 16.3 Other 30.6 23.7 Total $ 119.0 $ 40.0 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 (“RFS”). 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. From time to time, the Company holds varying amounts of RINs for resale. RINs obtained from third parties are initially recorded at their cost at the time the Company acquires them and are subsequently revalued at the lower of cost or market as of the last day of each accounting period and the resulting adjustments are reflected in costs of goods sold for the period. The value of RINs obtained from third parties would be reflected in prepaid expenses and other assets on the consolidated balance sheets. 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, the Company recorded write-downs related to idle fixed assets within its specialty products segment. The non-cash charges of $10.5 million were recorded in asset impairment on the consolidated statements of operations and loss on disposal of fixed assets in the consolidated statements of cash flows for the year ended December 31, 2013. No impairments of long-lived assets were recorded in 2015 and 2014. 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 the 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. The Company recognizes revenue on certain drilling fluids and completion fluids when consumed at the customer site during the drilling process. 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 and state income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries. However, the Company conducts certain activities through wholly-owned subsidiaries that are corporations, which in certain circumstances are subject to federal, state and local income taxes. Additionally, the Company is subject to franchise taxes in certain states. Income taxes on the earnings of the Company, with the exception of the above mentioned taxes, are the responsibility of its partners, with earnings of the Company included in partners’ earnings. In the event that the Company’s taxable income does 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, 2015 and 2014 . The Company accounts for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in the Company’s financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, the Company reassesses these probabilities and records any changes through the provision for income taxes. 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 $175.5 million , $171.4 million and $142.7 million , respectively, for the years ended December 31, 2015 , 2014 , and 2013 , 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 $14.2 million , $20.5 million and $14.6 million in 2015 , 2014 and 2013 , respectively. Advertising expenses are reported as selling expenses in the consolidated statements of operations. Foreign Currency Translation and Transactions Certain of the Company’s subsidiaries use a local currency as their functional currency. Assets and liabilities of subsidiaries with a local currency as their functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income (loss), which is reflected in partners’ capital in the Company’s consolidated balance sheets. Certain of the Company’s subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than such entity’s respective functional currency. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in other income (expense) in the consolidated statements of operations. New Accounting Pronouncements In January 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). ASU 2016-01 requires that (i) equity investments in unconsolidated entities that are not accounted for under the equity method of accounting generally be measured at fair value with changes recognized in net income and (ii) when the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk be recognized separately in other comprehensive income. Additionally, ASU 2016-01 changes the presentation and disclosure requirements for financial instruments. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”) . ASU 2015-17 requires that businesses classify deferred tax liabilities and assets on their balance sheets as noncurrent. Under existing accounting, a business must separate deferred income tax liabilities and assets into current and noncurrent. The amendments in this standard may be applied retrospectively or prospectively and are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company adopted ASU 2015-17 retrospectively, which resulted in the Company reclassifying approximately $2.3 million , as of December 31, 2014 , of deferred income taxes from current assets to noncurrent deferred income taxes in the consolidated balance sheets. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this standard are effective prospectively for fiscal years (including interim periods) beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2015-16 is not expected to have an impact on the Company’s consolidated financial statements. In June 2015, the FASB issued ASU No. 2015-10, Technical Corrections and Improvements (“ASU 2015-10”). With regard to fair value measurement disclosures, ASU 2015-10 clarified that, for nonrecurring measurements estimated at a date during the reporting period other than the end of the reporting period, an entity should clearly indicate that the fair value information presented is not as of the period’s end as well as the date or period that the measurement was taken. The Company adopted ASU 2015-10, effective June 12, 2015, as the change was effective upon issuance. The adoption did not have an impact on the Company’s consolidated financial statements. In May 2015, the FASB issued ASU No. 2015-08, Business Combinations (Topic 805): Pushdown Accounting — Amendments to SEC Paragraphs Pursuant to Staff Bulletin No. 115 (“ASU 2015-08”). The amendments in ASU 2015-08 amend various SEC paragraphs included in the FASB’s Accounting Standards Codification to reflect the issuance of Staff Accounting Bulletin No. 115 (“SAB 115”). SAB 115 rescinds portions of the interpretive guidance included in the SEC’s Staff Accounting Bulletins series and brings existing guidance into conformity with ASU No. 2014-17, “ Business Combinations (Topic 805): Pushdown Accounting ,” which provides an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The Company adopted the amendments in ASU 2015-08, effective May 8, 2015, as the amendments in the update are effective upon issuance. The adoption did not have an impact on the Company’s consolidated financial statements. In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (“ASU 2015-07”). ASU 201

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions On August 1, 2014 , the Company completed the acquisition of substantially all of the assets of privately-held Specialty Oilfield Solutions, Ltd. (“SOS”) for aggregate consideration of approximately $29.6 million , net of cash acquired (the “SOS Acquisition”). SOS is a full-service drilling fluids and solids control company with operations in the Eagle Ford, Marcellus and Utica shale formations. The SOS Acquisition was financed with borrowings under the Company’s revolving credit facility. The Company believes the SOS Acquisition increases its sales into the oilfield services market, expands its geographic reach and increases its asset diversity. On March 31, 2014 , the Company completed the acquisition of 100% of the capital stock of ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc. (“Anchor”), an independent provider and marketer of drilling fluids and completion fluids to the oil and gas exploration industry (the “Anchor Acquisition”). Total consideration was approximately $223.6 million , net of cash acquired. In connection with the Anchor Acquisition, the Company is required to pay the sellers 50% of the amount of taxes paid in a post-closing tax period that are reduced (or a refund is actually received or credited) as a result of the utilization of post-closing transaction tax deductions in the 2014 taxable year (but, for the avoidance of doubt, no other taxable year), which is estimated to be $1.1 million as of December 31, 2015 . Anchor designs, manufactures and packages drilling fluid products at its locations in Texas, Oklahoma, Louisiana, Arkansas, Colorado, Utah, Wyoming, Montana, New Mexico, New York, North Dakota, Pennsylvania and Ohio. The Anchor Acquisition was financed by using a portion of the net proceeds of approximately $884.0 million from the Company’s March 2014 private placement of 6.50% Senior Notes due 2021. The Company believes the Anchor Acquisition further expands its specialty products offering, increases its sales into the oilfield services market, expands its geographic reach and increases its asset diversity. On February 28, 2014 , the Company completed the acquisition of substantially all of the assets of United Petroleum, LLC (“United Petroleum”), a marketer and distributor of high performance lubricants, for aggregate consideration of approximately $10.4 million , (the “United Petroleum Acquisition”). The United Petroleum Acquisition was financed with cash on hand. The Company believes the United Petroleum Acquisition increases its position in the specialty lubricants market. On December 10, 2013 , the Company completed the acquisition of 100% of the membership interests of Bel-Ray Company, LLC (“Bel-Ray”), 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 (“Bel-Ray Acquisition”). Bel-Ray 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 7.625% senior notes due January 15, 2022 . The Company believes the Bel-Ray Acquisition increases its position 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 has the ability to transport crude oil directly from the point of lease, into the Company’s acquired crude oil loading facilities and then onto the Enbridge Pipeline where it can be routed to the Company’s Superior refinery and/or third party customers. As part of this transaction, the Company and Murphy jointly consented to terminate an existing crude oil purchase agreement wherein Murphy supplied the Company’s Superior refinery with up to 10,000 bpd 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 the major shale oil plays encompassing certain of 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 21,000 bpd and primarily produces diesel, jet fuel, gasoline, other fuel products and 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. Purchase Price Allocation The assets and results of the operations from such assets acquired as a result of the San Antonio and Crude Oil Logistics Acquisitions have been included in the fuel products segments since their dates of acquisition, January 2, 2013, and August 9, 2013, respectively. The assets and results of operations from such assets acquired as a result of the Bel-Ray and United Petroleum Acquisitions have been included in the specialty products segment since their dates of acquisition, December 10, 2013, and February 28, 2014, respectively. The assets and results of operations from such assets acquired as a result of the Anchor and SOS Acquisitions have been included in the oilfield services segment since their dates of acquisition, March 31, 2014, and August 1, 2014, respectively. The allocations of the aggregate purchase prices to assets acquired and liabilities assumed for acquisitions are as follows (in millions): 2014 Acquisitions 2013 Acquisitions SOS Anchor United Petroleum Bel-Ray Crude Oil Logistics San Antonio Accounts receivable $ 11.6 $ 75.0 $ — $ 4.3 $ — $ — Inventories 2.7 61.2 0.2 11.1 — 17.0 Prepaid expenses and other current assets 0.1 0.4 — 0.6 0.1 — Deposits — 0.6 — — — — Deferred tax asset — 0.9 — — — — Property, plant and equipment, net 15.1 35.9 — 6.5 0.9 100.7 Investment in unconsolidated affiliates — 1.9 — — — — Goodwill 0.8 69.0 5.0 9.1 5.2 5.7 Other intangible assets, net 5.7 74.0 5.2 41.4 — — Other noncurrent assets, net — — — 0.3 — — Accounts payable (6.2 ) (44.2 ) — (3.9 ) — — Accrued salaries, wages and benefits — (18.2 ) — (1.3 ) — (0.1 ) Accrued income taxes payable — — — — — — Other taxes payable (0.2 ) (1.8 ) — (1.7 ) — — Other current liabilities — (0.4 ) — (0.8 ) — (5.4 ) Current portion of long-term debt — — — (11.9 ) — — Long-term debt — — — — — — Deferred income tax liability — (30.7 ) — — — — Other long-term liabilities — — — (0.1 ) — — Pension and postretirement benefit obligations — — — — — — Total purchase price, net of cash acquired $ 29.6 $ 223.6 $ 10.4 $ 53.6 $ 6.2 $ 117.9 Intangible Assets The components of intangible assets listed in the table above were as follows (in millions): SOS Anchor United Petroleum Bel-Ray August 1, 2014 March 31, 2014 February 28, 2014 December 10, 2013 Amount Life (Years) Amount Life (Years) Amount Life (Years) Amount Life (Years) Customer relationships $ 4.3 15 $ 52.7 20 $ 3.8 20 $ 28.6 30 Tradenames 1.4 20 18.4 21 1.4 20 4.2 18 Trade secrets — — — — — — 8.5 18 Non-competition agreements — — 2.9 2 — — 0.1 3 Totals $ 5.7 $ 74.0 $ 5.2 $ 41.4 Weighted average amortization period 16 20 20 26 Goodwill The Company recorded the following goodwill (in millions): Amount Business Segment SOS Acquisition (1) $ 0.8 Oilfield Services Anchor Acquisition (1) (3) $ 69.0 Oilfield Services United Petroleum Acquisition (1) $ 5.0 Specialty Products 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 (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 and sales to third party customers. (3) Approximately $9.7 million of goodwill associated with the Anchor Acquisition is tax deductible due to Anchor’s tax status as a corporation on the acquisition date. Acquisition Expenses In connection with the respective acquisitions, 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, 2015 , 2014 and 2013 (in millions): Year Ended December 31, 2015 2014 2013 SOS Acquisition $ — $ 0.1 $ — Anchor Acquisition $ — $ 0.6 $ — United Petroleum Acquisition $ — $ 0.1 $ — Bel-Ray Acquisition $ — $ 0.3 $ 0.4 Crude Oil Logistics Acquisition $ — $ — $ 0.2 San Antonio Acquisition $ — $ — $ 0.5 Montana Acquisition $ — $ — $ 0.1 Results of Sales and Earnings The following financial information reflects sales and operating income (loss) of the Anchor Acquisition that are included in the consolidated statements of operations (in millions): Year Ended December 31, 2015 2014 2013 Sales $ 259.8 $ 349.1 $ — Operating loss $ (74.5 ) $ (19.1 ) $ — Unaudited Pro Forma Financial Information The following unaudited pro forma financial information reflects the unaudited consolidated results of operations of the Company as if the Anchor Acquisition had taken place on January 1, 2014, (in millions, except for per unit data): Year Ended December 31, 2014 Sales $ 5,873.6 Net loss $ (124.6 ) Limited partners’ interest basic and diluted net loss per unit $ (1.97 ) The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Anchor Acquisition. This unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliate	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliate	Investment in Unconsolidated Affiliates The following table summarizes the Company’s investments in unconsolidated affiliates for the years ended of December 31, 2015 and 2014 (in millions): Year Ended December 31, 2015 Year Ended December 31, 2014 Investment Percent Ownership Investment Percent Ownership Dakota Prairie Refining, LLC $ 124.7 50 % $ 117.2 50 % Juniper GTL LLC — — % 18.5 23 % Other 1.3 1.6 Total $ 126.0 $ 137.3 Dakota Prairie Refining, LLC 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 (“Dakota Prairie”). The capitalization of the construction cost was funded through cash contributions from MDU, cash contributions from the Company and proceeds of $75.0 million from a syndicated term loan facility with the joint venture as the borrower, which is expected to be repaid by the Company through its allocation of profits from the joint venture. The term loan facility was funded in April 2013. In addition to the $300.0 million commitment outlined in the joint venture agreement, MDU and the Company made additional cash contributions, net of distributions, in the amount of $80.4 million and $88.6 million , respectively, to fund construction costs and working capital needs. Additionally, MDU and the Company may make cash contributions to fund working capital needs. The joint venture allocates profits on a 50% /50% basis to the Company and MDU, except for the adjustments made to the Company’s share for repayment of the principal and interest of the $75.0 million term loan as noted above. The joint venture is governed by a board of managers comprised of representatives from both the Company and MDU. MDU is providing natural gas and electricity utility services to the joint venture. The Company is providing refinery operations, crude oil procurement and refined product marketing expertise to the joint venture. Dakota Prairie commenced sales of finished products in May 2015. On September 30, 2015, the Company entered into an agreement with MDU and Dakota Prairie, under which Dakota Prairie can borrow up to $25.0 million from each of the Company and MDU through June 30, 2016, (the “Subordinated Loan”). The Subordinated Loan is subordinated in right of payment to Dakota Prairie’s obligations under its revolving credit facility pursuant to the terms of a Subordination Agreement between the Company, MDU, Dakota Prairie and Wells Fargo Bank, N.A., as representative of the lenders under the revolving credit facility. As of December 31, 2015 , there are no amounts outstanding under the Subordinated Loan. On September 30, 2015, the Company issued a $39.4 million letter of credit supporting Dakota Prairie ’ s $75.0 million revolving credit agreement, which expires July 6, 2016. During the year ended December 31, 2015 , the Company purchased $2.6 million of crude oil and other feedstocks at cost from Dakota Prairie. Accounts payable to Dakota Prairie at December 31, 2015 , were $1.4 million for crude oil and other feedstock purchases. During the year ended December 31, 2015 , the Company purchased $4.6 million of crude oil on behalf of Dakota Prairie and sold it to Dakota Prairie at cost, which resulted in an immaterial gain. Other receivables from Dakota Prairie at December 31, 2015 , were $0.4 million . In the event Dakota Prairie is unable to sell atmospheric towers bottoms (“ATB’s”) to a third party at or above acquisition costs, or in the event third party sales do not cover crude oil acquisition costs, the joint venture agreement requires the Company to either buy the ATB’s or cover any shortfall between the third party sales and the crude oil acquisition cost. During the year ended December 31, 2015 , the Company paid $1.1 million of shortfall under the agreement. Accounts payable to Dakota Prairie at December 31, 2015 , were $0.7 million related to the shortfall agreement. The Company subleased railcars from Dakota Prairie in 2015 and 2014 . The amount charged for these subleases totaled $0.6 million in 2015 and 2014 . There were no accounts payable as of December 31, 2015 related to the railcar subleases. Accounts payable were $0.5 million as of December 31, 2014 related to the railcar subleases. On January 1, 2015, the Company entered into an agreement with Dakota Prairie to provide administrative services to Dakota Prairie. The amount charged for these services during the year ended December 31, 2015 was $0.4 million . Other accounts receivable from Dakota Prairie at December 31, 2015 were immaterial. The Company provides certain services to Dakota Prairie, which include costs for payroll and certain other employee benefits. The amount related to such services was $0.2 million in 2015 and $0.4 million in 2014 . The Company’s membership interest in Dakota Prairie is significant as defined by the Securities and Exchange Commission’s (“SEC”) Regulation S-X Rule 1-02(w). Accordingly, as required by Regulation S-X Rule 3-09, the Company has included the audited financial statements of Dakota Prairie as of and for the year ended December 31, 2015 , as an exhibit to this Annual Report on Form 10-K. Juniper GTL LLC On June 9, 2014 , the Company entered into a joint venture agreement with Clean Fuels North America, LLC, which is owned by SGC Energia and Great Northern Project Development, to develop, build and operate a gas-to-liquids (“GTL”) plant in Lake Charles, Louisiana. The joint venture is named New Source Fuels, LLC, and it owns 100% of Juniper GTL LLC (“Juniper”). The Company invested $25.0 million in total in exchange for an equity interest of approximately 23% in the joint venture. During September 2015, the Company determined the fair value of its investment in Juniper was less than its carrying value of $24.3 million . As a result, the Company recorded a $24.3 million impairment charge in loss from unconsolidated affiliates in the consolidated statement of operations for the year ended December 31, 2015 . Inputs used to estimate the fair value of Juniper was considered Level 3 of the fair value hierarchy.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangible Assets	Goodwill and Other Intangible Assets During September 2015 , the Company determined that the expected operating results for one of its reporting units was projected to be substantially lower than previous forecasts due to the continued decline in crude oil prices. As a result, the Company determined that these recent events constituted a triggering event that required the Company to update its goodwill impairment assessment through September 30, 2015. An impairment charge of $33.8 million for goodwill related to the oilfield services segment has been recorded in the consolidated statements of operations within asset impairment. The impairment charge was primarily driven by the reduced outlook on revenues and profitability as a result of falling crude oil prices driving declines in U.S. land based rig counts. To derive the fair value of the reporting units, as required in step one of the impairment test, the Company used the income approach, specifically the discounted cash flow method, to determine the fair value of each reporting unit and the associated amount of the impairment charge. 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. Inputs used to estimate the fair value of the Company’s reporting units are considered Level 3 inputs of the fair value hierarchy and include the following: • The Company’s financial projections for its reporting units are based on its analysis of various supply and demand factors, which include, among other things, industry-wide capacity, planned utilization rate, end-user demand, crack spreads, capital expenditures and economic conditions. Such estimates are consistent with those used in the Company’s planning and capital investment reviews and include recent historical prices and published forward prices. Revenue growth rates assumed for the Company’s reporting unit where impairment was recognized were approximately (17)% for 2015 and ranged from (3)% to 18% for 2016 and beyond. • The discount rate used to measure the present value of the projected future cash flows is based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. The discount rate used for the Company’s reporting unit where impairment was recognized was approximately 15.5% per year. For Level 3 measurements, significant increases or decreases in long-term growth rates or discount rates in isolation or in combination could result in a significantly lower or higher fair value measurement. Changes in goodwill balances are as follows (in millions): Specialty Fuel Oilfield Total Net balance as of December 31, 2013 $ 168.5 $ 38.5 $ — $ 207.0 Acquisitions (1) 5.0 — 69.8 74.8 Impairment (2) — — (36.0 ) (36.0 ) Net balance as of December 31, 2014 $ 173.5 $ 38.5 $ 33.8 $ 245.8 Impairment (2) — — (33.8 ) (33.8 ) Net balance as of December 31, 2015 $ 173.5 $ 38.5 $ — $ 212.0 (1) See Note 3 for discussion of the acquisitions completed during 2014. (2) Total accumulated goodwill impairment as of December 31, 2015 and 2014 , is $69.8 million and $36.0 million , respectively. Other intangible assets consist of the following (in millions): Weighted Average Life (Years) December 31, 2015 December 31, 2014 Gross Amount Accumulated Amortization Gross Amount Accumulated Amortization Customer relationships 21 $ 243.7 $ (97.5 ) $ 243.7 $ (68.4 ) Supplier agreements 4 21.5 (21.5 ) 21.5 (21.5 ) Tradenames 16 46.6 (10.7 ) 46.6 (4.9 ) Trade secrets 13 52.7 (23.4 ) 52.7 (16.7 ) Patents 12 1.6 (1.4 ) 1.6 (1.3 ) Non-competition agreements 4 8.8 (8.8 ) 8.8 (7.3 ) Distributor agreements 3 2.0 (2.0 ) 2.0 (2.0 ) Royalty agreements 19 4.5 (2.0 ) 4.5 (1.8 ) 18 $ 381.4 $ (167.3 ) $ 381.4 $ (123.9 ) Supplier agreements, tradenames (other than indefinite lived), trade secrets, patents, non-competition agreements, distributor agreements and royalty agreements are being amortized to properly match expenses with the undiscounted estimated future cash flows over the terms of the related agreements or the period expected to be benefited. The costs of 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 undiscounted estimated future cash flows based upon assumed rates of annual customer attrition. For the years ended December 31, 2015 , 2014 and 2013 , the Company recorded amortization expense of intangible assets of $43.4 million , $40.3 million and $25.6 million , respectively. As of December 31, 2015 , the Company estimates that amortization of intangible assets for the next five years will be as follows (in millions): Year Amortization Amount 2016 $ 37.2 2017 $ 32.3 2018 $ 27.3 2019 $ 22.8 2020 $ 18.8

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
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 July 2055 . Renewal options are available on certain of these leases in which the Company is the lessee. Rent expense for the years ended December 31, 2015 , 2014 and 2013 was $67.8 million , $59.9 million and $35.3 million , respectively. As of December 31, 2015 , 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 2016 $ 42.8 2017 37.9 2018 33.3 2019 22.2 2020 16.9 Thereafter 27.0 Total $ 180.1 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. 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. The BP Purchase Agreement, as amended and restated, had an initial term of one year ending April 1, 2014, 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. 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 all of the naphthenic lubricating oils produced at Houston Refining’s refinery in Houston, Texas, up to 3,100 bpd, and has a right of first refusal to purchase any additional naphthenic lubricating oils (above the 3,100 bpd) produced at the refinery. In addition, Houston Refining is required to toll-process a minimum of approximately 600 bpd of white mineral oil for the Company at Houston Refining’s Houston, Texas refinery. The annual purchase commitment under these agreements is approximately $87.5 million . As of December 31, 2015 , 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 2016 $ 493.6 2017 149.8 2018 87.6 2019 80.3 2020 — Thereafter — Total $ 811.3 The Company has 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 expects to purchase approximately $27.5 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, 2015 . This amount is not included in the table above. 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. Environmental The Company conducts crude oil and specialty hydrocarbon refining, blending and terminal operations in addition to providing oilfield services and products, which activities 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. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects, and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, 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, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures. Remediation of subsurface contamination is in process at certain of the Company’s refinery sites and is being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the soil and 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 deductible or 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. 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, pursuant to which Anadarko and Age Refining are obligated to assess and remediate certain contamination at the San Antonio refinery that predates the Company’s acquisition of the facility. The Company does not expect this pre-existing contamination at the San Antonio refinery to have a material adverse effect on its financial position or results of operations. Montana Refinery In connection with the acquisition of the Montana refinery from Connacher Oil and Gas Limited (“Connacher”), the Company became a party to an existing 2002 Refinery Initiative Consent Decree (the “Montana Consent Decree”) with the EPA and the Montana Department of Environmental Quality (the “MDEQ”). The material obligations imposed by the Montana Consent Decree have been completed. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previously held 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 timely notification, certain conditions and certain monetary baskets and caps, for environmental conditions arising under Holly’s ownership and operation of the Montana refinery and existing as of the date of sale to Connacher. During 2014, Holly provided the Company a notice challenging the Company’s position that Holly is obligated to indemnify the Company’s remediation expenses for environmental conditions to the extent arising under Holly’s ownership and operation of the refinery and existing as of the date of sale to Connacher, which expenses totaled approximately $17.6 million as of December 31, 2015 , of which $14.4 million was capitalized into the cost of the Company’s recently completed expansion project and $3.2 million was expensed. The Company continues to believe that Holly is responsible to indemnify the Company for these remediation expenses disputed by Holly, and on September 22, 2015, the Company initiated a lawsuit against Holly and the sellers of the Montana refinery under the asset purchase agreement. On November 24, 2015, Holly and the sellers of the Montana refinery under the asset purchase agreement filed a motion to dismiss the case pending arbitration. The Company is opposing the motion. In the event the Company is unsuccessful, the Company will be responsible for those remediation expenses. The Company expects that it may incur some costs to remediate other environmental conditions at the Montana refinery; however, the Company believes at this time that these other costs it may incur will not be material to its financial position or results of operations. Superior Refinery In connection with the acquisition of the Superior refinery, 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 must 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 estimates costs of up to $4.0 million to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform these required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be material. The Company is currently assessing certain past actions at the refinery for compliance with the terms of the Superior Consent Decree, which actions may be subject to stipulated penalties under the Superior Consent Decree but, in any event, the Company does not currently believe that the imposition of such penalties for those actions, should they be imposed, would be material. In addition, the Company is pursuing 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 2015 , the Company incurred no costs related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations. During 2014 , the Company incurred approximately $0.7 million of costs related to installing process equipment at the Superior refinery 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 is in settlement discussions with the EPA to resolve this issue. The Company has not yet received formal action from the EPA. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial position or results of 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 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 23, 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 2015 and 2014 , the Company incurred approximately $6.8 million and $0.6 million , respectively, of such expenditures and estimates additional expenditures of approximately $3.0 million to $5.0 million of capital expenditures and expenditures related to additional personnel and environmental studies through 2016 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 position or results of operations. 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 Company believes the contractual indemnity is unlimited in amount and duration, but requires the Company to contribute $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities. 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, 2015 , the trust fund contained approximately $0.8 million . In addition, Weston has 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. 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, 2015 and 2014 , the Company incurred approximately $0.6 million and $1.1 million , respectively, of PSM related capital expenditures and expects to incur up to $1.4 million of capital expenditures during 2016 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards. In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program. 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 the parties have reached a tentative settlement with OSHA on the matter, which the Company does not believe will have a material adverse effect on its financial position or results of operations. Labor Matters The Company has approximately 613 employees covered by various collective bargaining agreements, or approximately 28% of its total workforce of approximately 2,175 employees. These agreements have expiration dates of March 31, 2016 , April 30, 2016 , June 30, 2017 , October 31, 2017 , and January 31, 2019 . The Company has approximately 241 employees, or approximately 11% of its total workforce, covered by collective bargaining agreements that expire in less than one year and does not expect any work stoppages. Legal Proceedings The Company is involved in the legal proceedings described below and is subject to other claims and litigation arising in the normal course of its business. The Company has recorded accruals with respect to certain of these matters, where appropriate, that are reflected in its consolidated financial statements but are not, individually or in the aggregate, considered material. For other matters, the Company has not recorded accruals because it has not yet determined that a loss is probable or because the amount of loss cannot be reasonably estimated. While the ultimate outcome of the matters described below and other claims and litigation currently pending cannot be determined, the Company currently does not expect that these proceedings and claims, individually or in the aggregate, will have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any litigation is inherently uncertain, however, and if decided adversely to the Company, or if the Company determines that settlement of particular litigation is appropriate, the Company may be subject to liability that could have a material adverse effect on its financial position, results of operations, or cash flows. Accordingly, the Company discloses matters below for which a material loss is reasonably possible. In each case, however, the Company has either determined that the range of loss is not reasonably estimable or that any reasonably estimable range of loss is not material to its consolidated financial statements. On November 12, 2014, a nationwide collective action lawsuit alleging that Anchor, a wholly owned subsidiary of the Company, failed to pay drilling fluid engineers overtime in compliance with the Fair Labor Standards Act (“FLSA”) was filed titled Jonathan Wolfe v. Anchor Drilling Fluids USA, Inc. in the U.S. District Court for the Western District of Pennsylvania (“Wolfe”). The Company filed its answer to the complaint on January 9, 2015 and the Wolfe plaintiff filed an amended complaint on February 26, 2015, adding that Anchor’s failure to pay overtime to a subclass of drilling fluid engineers violated the Pennsylvania Minimum Wage Act (the “Pennsylvania Act”). For this subclass, the Wolfe plaintiff seeks certification of a class action under the Pennsylvania Act. The Wolfe plaintiff seeks to recover overtime pay, liquidated damages and attorneys’ fees and costs. The portion of the potential liability that relates to the period prior to March 31, 2014, the date on which the Company acquired Anchor, is eligible for indemnification under the securities purchase agreement that effected that transaction; however, the right to indemnification under the securities purchase agreement for the potential Wolfe liability is subject to a deductible and limitations otherwise set forth in the securities purchase agreement. On May 1, 2015, the parties engaged in mediation and agreed to a tentative settlement of this litigation. On September 3, 2015, the U.S. District Court entered an order granting preliminary approval of the settlement as well as attorneys’ fees and costs. On January 6, 2016, a final judgment was entered by the U.S. District Court approving the settlement. The settlement amount is not material to the consolidated financial statements. On November 21, 2014, a nationwide collective action lawsuit alleging that Anchor and the Company, as well as SOS, failed to pay solids control technicians overtime in compliance with the FLSA was filed titled Timothy Niver v. Specialty Oilfield Solutions, Ltd., et al. in the U.S. District Court for the Western District of Pennsylvania (“Niver”). The Niver plaintiff filed an amended complaint on January 21, 2015, adding that defendants’ failure to pay overtime to a subclass of solids control technicians violated the Pennsylvania Act. For this subclass, the Niver plaintiff seeks certification of a class action under the Pennsylvania Act. The Niver plaintiff seeks to recover overtime pay, liquidated damages and attorneys’ fees and costs. Anchor and the Company filed their answer to the amended complaint on February 2, 2015. The Company consented to conditional certification in the case, and notice of the collective action has been issued to potential class members. The portion of the potential liability that relates to the period prior to August 1, 2014, the date on which the Company acquired the assets of SOS, was retained by, and is the responsibility of, SOS. To the extent Anchor or the Company is found liable for damages relating to the period prior to the acquisition of the assets of SOS, Anchor and the Company are eligible for indemnification under the asset purchase agreement that effected that transaction, and no deductible is applicable; however, the right to indemnification is subject to limitations otherwise set forth in the asset purchase agreement. On June 1, 2015, the parties engaged in mediation and agreed to a tentative settlement of this litigation. On October 7, 2015, the U.S. District Court entered an order approving the settlement and dismissing the case with prejudice. The settlement amount was not material to the consolidated financial statements. Standby Letters of Credit The Company has agreements with various financial institutions for standby letters of credit which have been issued primarily to vendors. As of December 31, 2015 and 2014 , the Company had outstanding standby letters of credit of $66.8 million and $114.3 million , respectively, under its senior secured revolving credit facility, which was amended and restated on July 14, 2014 (the “revolving credit facility”). Refer to Note 7 for additional information regarding the Company’s revolving credit facility. At December 31, 2015 and 2014 , the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $600.0 million , which amount may be increased to 90% of revolver commitments in effect ( $1.0 billion at December 31, 2015 ) with the consent of the Agent (as defined in the revolving credit facility agreement). As of December 31, 2015 and 2014 , the Company had availability to issue letters of credit of $233.5 million and $310.8 million , respectively, under its revolving credit facility.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consisted of the following (in millions): December 31, December 31, Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rates of 3.3% and 2.6% at December 31, 2015 and 2014, respectively $ 111.0 $ 150.8 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.1% for each year ended December 31, 2015 and 2014 — 275.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rates of 6.8% and 6.7% for the year ended December 31, 2015 and 2014, respectively 900.0 900.0 Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 8.0% for each year ended December 31, 2015 and 2014 (1) 352.9 352.5 Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the year ended December 31, 2015 325.0 — Related party note payable, interest at a fixed rate of 6.0% on a portion of the note, interest payments at various dates, borrowings due July 2016, weighted average interest rate of 6% for the year ended December 31, 2015 73.5 — Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034 46.4 43.6 Less unamortized debt issuance costs (2) (28.9 ) (34.7 ) Less unamortized discounts (6.5 ) (8.4 ) Total long-term debt 1,773.4 1,678.8 Less current portion of note payable - related party 73.5 — Less current portion of long-term debt 1.7 0.6 $ 1,698.2 $ 1,678.2 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.9 million and $2.5 million as of December 31, 2015 and 2014 , respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge). (2) Deferred debt issuance costs 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 $8.1 million and $4.3 million at December 31, 2015 and 2014 , respectively. Senior Notes 7.75% Senior Notes (the “2023 Notes”) On March 27, 2015 , the Company issued and sold $325.0 million in aggregate principal amount of 7.75% Senior Notes due April 15, 2023 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 99.257 percent of par. The 2023 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 approximately $317.0 million net of discount, initial purchasers’ fees and expenses, which the Company used to fund the redemption of $178.8 million in aggregate principal amount of outstanding 2020 Notes (defined below) on April 28, 2015, to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at the Company’s facilities and working capital. Interest on the 2023 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2015. At any time prior to April 15, 2018, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2023 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.75% 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 2023 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 April 15, 2018, the Company may on any one or more occasions redeem all or a part of the 2023 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest to the applicable redemption date on such 2023 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2018 105.813 % 2019 103.875 % 2020 101.938 % 2021 and thereafter 100.000 % Prior to April 15, 2018, the Company may on any one or more occasions redeem all or part of the 2023 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) the make-whole premium (as set forth in the indenture governing the 2023 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date. On March 27, 2015 , in connection with the issuance and sale of the 2023 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2023 Notes obligating the Company to use reasonable best efforts to file an exchange offer registration statement with the SEC, so that holders of the 2023 Notes can offer to exchange the 2023 Notes for registered notes having substantially the same terms as the 2023 Notes and evidencing the same indebtedness as the 2023 Notes. On December 11, 2015, the Company filed an exchange offer registration statement for the 2023 Notes with the SEC, which was declared effective on January 28, 2016. The exchange offer is expected to be completed on February 29, 2016, thereby fulfilling all of the requirements of the 2023 Notes registration rights agreement. 6.50% Senior Notes (the “2021 Notes”) On March 31, 2014 , the Company issued and sold $900.0 million in aggregate principal amount of 6.50% senior notes due April 15, 2021 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 par. The Company received net proceeds of approximately $884.0 million , net of initial purchasers’ fees and expenses, which the Company used to fund the purchase price of the Anchor Acquisition (refer to Note 3 for additional information), the redemption of $500.0 million in aggregate principal amount outstanding of 9.375% senior notes due 2019 (“2019 Notes”) and for general partnership purposes, including planned capital expenditures at the Company’s facilities. Interest on the 2021 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2014. At any time prior to April 15, 2017, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net proceeds of a public or private equity offering at a redemption price of 106.5% 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 2021 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 April 15, 2017, the Company may on any one or more occasions redeem all or a part of the 2021 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 2021 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2017 103.250 % 2018 101.625 % 2019 and thereafter 100.000 % Prior to April 15, 2017, the Company may on any one or more occasions redeem all or part of the 2021 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 2021 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date. On March 31, 2014 , in connection with the issuance and sale of the 2021 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2021 Notes obligating the Company to use reasonable best efforts to file an exchange offer registration statement with the SEC, so that holders of the 2021 Notes can offer to exchange the 2021 Notes for registered notes having substantially the same terms as the 2021 Notes and evidencing the same indebtedness as the 2021 Notes. On March 24, 2015, the Company filed an exchange offer registration statement for the 2021 Notes with the SEC, which was declared effective on April 3, 2015. The exchange offer was completed on April 30, 2015, thereby fulfilling all of the requirements of the 2021 Notes registration rights agreement. 7.625% Senior Notes (the “2022 Notes”) On November 26, 2013 , the Company issued and sold $350.0 million in aggregate principal amount of 7.625% senior notes due January 15, 2022 , in a private placement pursuant to Section 4(a)(2) of 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, initial purchasers’ 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. 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. 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 100.000 % 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. 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. 9.625% Senior Notes (the “2020 Notes”) On June 29, 2012 , in connection with the acquisition of Royal Purple, the Company issued and sold $275.0 million in aggregate principal amount of 9.625% senior notes due August 1, 2020 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, initial purchasers’ fees and expenses, which the Company used to fund a portion of the purchase price of Royal Purple. On April 27, 2015 , the Company redeemed $96.2 million aggregate principal amount of 2020 Notes with a portion of the net proceeds of the March 13, 2015 public offering of its common units in which it sold 6,000,000 common units. Additionally, on April 28, 2015 , the Company redeemed the remaining $178.8 million aggregate principal amount of 2020 Notes with a portion of the net proceeds from the issuance of the 2023 Notes. In conjunction with the redemptions, the Company incurred debt extinguishment costs of $46.6 million . 2021 Notes, 2022 Notes and 2023 Notes In accordance with SEC Rule 3-10 of Regulation S-X, condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of the Company’s “minor” subsidiaries (as defined by Rule 3-10 of Regulation S-X), including 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 2021, 2022 and 2023 Notes). There are no significant restrictions on the ability of the Company or subsidiary guarantors for the Company to obtain funds from its subsidiary guarantors by dividend or loan. None of the subsidiary guarantors’ assets represent restricted assets pursuant to SEC Rule 4-08(e)(3) of Regulation S-X. The 2021, 2022 and 2023 Notes are subject to certain automatic customary releases, including the sale, disposition, or transfer of capital stock or substantially all of the assets of a subsidiary guarantor, designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture, exercise of legal defeasance option or covenant defeasance option, liquidation or dissolution of the subsidiary guarantor and a subsidiary guarantor ceases to both guarantee other Company debt and to be an obligor under the revolving credit facility. The Company’s 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 2021, 2022 and 2023 Notes. The indentures governing the 2021, 2022 and 2023 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 2021, 2022 and 2023 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Ratings Services (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of December 31, 2015 , the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 1.9 to 1.0. Second Amended and Restated Senior Secured Revolving Credit Facility The Company has a $1.0 billion senior secured revolving credit facility, subject to borrowing base limitations, which includes a $500.0 million incremental uncommitted expansion feature. The revolving credit facility is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in July 2019 and currently bears interest at a rate equal to prime plus a basis points margin or London Interbank Offered Rate (“LIBOR”) plus a basis points margin, at the Company’s option. As of December 31, 2015 , the margin was 75 basis points for prime and 175 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 Revolving Loans Margin on LIBOR Revolving Loans ≥ 66% 0.50% 1.50% ≥ 33% and < 66% 0.75% 1.75% < 33% 1.00% 2.00% In addition to paying interest quarterly 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 0.250% or 0.375% 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, 2015 , under the revolving credit facility was $411.3 million . As of December 31, 2015 , the Company had $111.0 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $66.8 million , leaving $233.5 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 accounts receivable, inventory and substantially all of its cash. 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 (a) 12.5% of the Borrowing Base (as defined in the revolving credit agreement) then in effect and (b) $45.0 million, 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, 2015 , the Company was in compliance with all covenants under the revolving credit facility. 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, 2015 . 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. Related Party Note Payable On December 30, 2015, the Company entered into an agreement with The Heritage Group (“Heritage”), an affiliate of the Company’s general partner, in which Heritage made a $27.0 million uncommitted prepayment for the purchase of certain finished products and entered into a $48.0 million unsecured note payable with the Company as the borrower. Imputed interest on the prepayment totaled $1.5 million . The note bears interest at 6.0% , with interest payments due on March 31, 2016, June 30, 2016, and July 31, 2016. Principal payments of $15.0 million each are due on May 31, 2016 and June 30, 2016, with the remaining principal amount due before July 31, 2016. The proceeds were used for general partnership purposes. Capital Leases Assets recorded under these capital lease obligations are included in property, plant and equipment and total $49.0 million and $48.9 million as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 and 2014 , the Company had recorded $3.9 million and $5.7 million , respectively, in accumulated depreciation for these capital lease assets. On July 7, 2014 , the Company entered into a capital lease agreement with TexStar Midstream Logistics, L.P. (“TexStar”) under which TexStar constructed, owns and operates a 30,000 bpd crude oil pipeline system supplying significant volumes of Eagle Ford crude oil to the Company’s San Antonio refinery for a term of 20 years. Thereafter, the agreement will continue on a month-to-month basis unless terminated by either party. Under the terms of the agreement, TexStar installed and operates the Karnes North Pipeline System (“KNPS”), a pipeline that transports 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 12,000 bpd of crude oil through the KNPS-Elmendorf terminal supply route. The pipeline became fully operational on November 1, 2014 . The total obligation and asset under the capital lease agreement as of December 31, 2015 and 2014 , was $39.4 million and $39.3 million , respectively. Total depreciation expense for this lease during the years ended December 31, 2015 and 2014 , was $2.0 million and $0.3 million , respectively. As of December 31, 2015 , the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows (in millions): Year Capital Leases 2016 $ 8.2 2017 7.9 2018 7.8 2019 7.4 2020 6.9 Thereafter 96.2 Total minimum lease payments 134.4 Less amount representing interest 88.0 Capital lease obligations 46.4 Less obligations due within one year 1.7 Long-term capital lease obligations $ 44.7 Maturities of Long-Term Debt As of December 31, 2015 , principal payments of debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2016 $ 76.7 2017 1.6 2018 1.5 2019 112.3 2020 0.9 Thereafter 1,614.4 Total $ 1,807.4

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2015
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), natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. 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; • precious metals purchases: and • fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”). The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions. The changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in risk profiles. These changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise. The Company recognizes all derivative instruments at their fair values (see Note 9 ) as either current assets or current liabilities in 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 portions or all of its derivative instruments for hedge accounting. The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s consolidated balance sheets as of December 31, 2015 and 2014 (in millions): December 31, 2015 December 31, 2014 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 $ — $ — $ — $ — $ (10.0 ) $ (10.0 ) Gasoline swaps — — — 15.9 (4.4 ) 11.5 Swaps not allocated to a specific segment: Interest rate swaps — — — 2.5 — 2.5 Total derivative instruments designated as hedges — — — 18.4 (14.4 ) 4.0 Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps — — — — (7.2 ) (7.2 ) Natural gas collars — — — 0.1 (0.6 ) (0.5 ) Platinum swaps — — — — (0.1 ) (0.1 ) Fuel products segment: Crude oil swaps — — — 31.4 (111.2 ) (79.8 ) Crude oil basis swaps 0.4 (0.4 ) — 0.8 — 0.8 Crude oil percentage basis swaps 0.2 (0.2 ) — — (0.2 ) (0.2 ) Crude oil options 0.8 (0.8 ) — — — — Gasoline swaps — — — 2.4 (0.4 ) 2.0 Diesel swaps — — — 116.1 (19.1 ) 97.0 Diesel crack spread swaps — — — 4.5 — 4.5 Jet fuel swaps — — — 7.9 (5.2 ) 2.7 Total derivative instruments not designated as hedges 1.4 (1.4 ) — 163.2 (144.0 ) 19.2 Total derivative instruments $ 1.4 $ (1.4 ) $ — $ 181.6 $ (158.4 ) $ 23.2 The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s consolidated balance sheets as of December 31, 2015 and 2014 (in millions): December 31, 2015 December 31, 2014 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 $ — $ — $ — $ (13.8 ) $ 10.0 $ (3.8 ) Gasoline swaps — — — — 4.4 4.4 Total derivative instruments designated as hedges — — — (13.8 ) 14.4 0.6 Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps (14.9 ) — (14.9 ) (12.1 ) 7.2 (4.9 ) Natural gas collars (0.9 ) — (0.9 ) (1.1 ) 0.6 (0.5 ) Platinum swaps — — — (0.1 ) 0.1 — Fuel products segment: Crude oil swaps (5.2 ) — (5.2 ) (102.4 ) 111.2 8.8 Crude oil basis swaps (0.7 ) 0.4 (0.3 ) — — — Crude oil percentage basis swaps (6.9 ) 0.2 (6.7 ) (0.2 ) 0.2 — Crude oil options (1.1 ) 0.8 (0.3 ) — — — Gasoline swaps — — — (1.0 ) 0.4 (0.6 ) Gasoline crack spread swaps (4.3 ) — (4.3 ) — — — Diesel swaps — — — (28.1 ) 19.1 (9.0 ) Jet fuel swaps — — — (5.2 ) 5.2 — Natural gas swaps (1.3 ) — (1.3 ) — — — Total derivative instruments not designated as hedges (35.3 ) 1.4 (33.9 ) (150.2 ) 144.0 (6.2 ) Total derivative instruments $ (35.3 ) $ 1.4 $ (33.9 ) $ (164.0 ) $ 158.4 $ (5.6 ) 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, 2015 , the Company had no counterparties in which derivatives held were net assets. As of December 31, 2014 , the Company had five counterparties, in which derivatives held were net assets, totaling $23.2 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 Baa1 and BBB+ by Moody’s Investor Service, Inc. (“Moody’s”) and Standard & Poor’s Ratings Services (“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, 2015 or December 31, 2014 . 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 is not netted against derivative assets or liabilities. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability. As of December 31, 2015 and 2014 , the Company had provided its counterparties with no collateral. 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. 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 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. Derivative Instruments Designated as Cash Flow Hedges The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel swaps as cash flow hedges. The derivative instruments designated as cash flow hedges that are 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 cash flow 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 cash flow hedge. To the extent a derivative instrument designated as a cash flow 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. 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 cash flow hedge accounting. Ineffectiveness has resulted, and the loss of cash flow hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow 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. Cash flow 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 cash flow 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 deferred 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. The Company recorded the following amounts in its consolidated balance sheets, consolidated statements of operations, consolidated statements of comprehensive income (loss) and consolidated statements of partners’ capital as of, and for the years ended December 31, 2015 and 2014 , related to its derivative instruments that were designated as cash flow hedges (in millions): Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion) Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion) Year Ended December 31, Location of (Gain) Loss Year Ended December 31, Location of Gain (Loss) Year Ended December 31, Type of Derivative 2015 2014 2015 2014 2015 2014 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ 3.0 $ 1.8 Unrealized/Realized $ — $ — Fuel products segment: Crude oil swaps (5.6 ) (185.8 ) Cost of sales (170.3 ) 44.2 Unrealized/Realized (0.2 ) 4.8 Gasoline swaps 5.7 56.3 Sales 44.7 (1.4 ) Unrealized/Realized 0.7 (7.6 ) Diesel swaps (8.8 ) 220.0 Sales 121.6 (6.7 ) Unrealized/Realized — — Jet fuel swaps 1.4 23.7 Sales 13.1 (0.9 ) Unrealized/Realized — 0.6 Total $ (7.3 ) $ 114.2 $ 12.1 $ 37.0 $ 0.5 $ (2.2 ) The effective portion of the cash flow hedges classified in accumulated other comprehensive income (loss) was a gain of $6.4 million and a gain of $25.8 million as of December 31, 2015 and 2014 , respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive gain at December 31, 2015 , will be reclassified to earnings by December 31, 2016, with balances being recognized as follows (in millions): Year Accumulated Other Comprehensive Income 2016 $ 6.4 Total $ 6.4 Derivative Instruments Designated as Fair Value Hedges For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the consolidated statements of operations. No hedge ineffectiveness was recognized as the interest rate swap qualifies for the “shortcut” method and, as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items. Fair value 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 fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as effective fair value hedge, the derivative instrument is still subject to mark-to-market method of accounting, however the Company will cease to adjust the hedged asset or liability for changes in fair value. In 2014, the Company entered into an interest rate swap agreement which converts a portion of the Company’s fixed rate debt to a floating rate. This agreement involves the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount. Also, in connection with the interest rate swap agreement, the Company entered into an option that permits the counterparty to cancel the interest rate swap for a specified premium. The Company designated this interest rate swap and option as a fair value hedge. On January 13, 2015, the Company terminated its interest rate swap, which was designated as a fair value hedge, related to a notional amount of $200.0 million of 2022 Notes. In settlement of this swap, the Company recognized a net gain of approximately $3.3 million . The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2015 and 2014 related to its derivative instrument designated as a fair value hedge (in millions): Location of Gain of Derivative Amount of Gain Recognized in Net Loss Hedged Item Location of Loss on Hedged Item Amount of Loss Recognized in Net Loss Year Ended December 31, Year Ended December 31, 2015 2014 2015 2014 Swaps not allocated to a specific segment: Interest rate swap Interest expense $ 0.5 $ 2.5 2022 Notes Interest expense $ — $ (2.5 ) Total $ 0.5 $ 2.5 $ — $ (2.5 ) Derivative Instruments Not Designated as Hedges For derivative instruments not designated as hedges, 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 hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations. 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. Additionally, the Company has entered into diesel crack spread collars, gasoline crack spread collars, natural gas collars, and certain other crude oil swaps, diesel swaps, gasoline swaps, natural gas swaps and platinum swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and gasoline and diesel sales at the Company’s Superior refinery. The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2015 and 2014 related to its derivative instruments not designated as hedges (in millions): Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments Year Ended December 31, Year Ended December 31, Type of Derivative 2015 2014 2015 2014 Specialty products segment: Natural gas swaps $ (10.7 ) $ 1.1 $ (2.5 ) $ (11.9 ) Platinum swaps (0.8 ) — 0.1 (0.1 ) Fuel products segment: Crude oil swaps (67.6 ) (48.5 ) 52.0 (61.9 ) Crude oil basis swaps 1.1 5.7 (7.8 ) 0.1 Crude oil percentage basis swaps (3.2 ) — 0.2 — Crude oil options 6.1 — (0.3 ) — Gasoline swaps (20.0 ) (2.2 ) (0.7 ) 10.1 Gasoline crack spread swaps (5.5 ) — (4.3 ) — Gasoline crack spread collars — (0.4 ) — — Diesel swaps 82.3 76.3 (68.7 ) 71.5 Diesel crack spread swaps 24.3 (3.6 ) — 4.5 Diesel percentage basis crack spread swaps (0.1 ) — (4.5 ) — Diesel crack spread collars — 1.0 — (0.1 ) Jet fuel swaps 1.6 3.2 (1.6 ) 0.7 Jet fuel crack spread swaps — (0.1 ) — — Natural gas swaps — — (1.3 ) — Total $ 7.5 $ 32.5 $ (39.4 ) $ 12.9 Derivative Positions — Specialty Products Segment Natural Gas Swap Contracts At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 1,580,000 $ 4.24 Second Quarter 2016 1,380,000 $ 4.26 Third Quarter 2016 1,380,000 $ 4.26 Fourth Quarter 2016 1,540,000 $ 4.14 Calendar Year 2017 4,950,000 $ 3.85 Total 10,830,000 Average price $ 4.05 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2015 1,770,000 $ 4.09 Second Quarter 2015 1,500,000 $ 4.11 Third Quarter 2015 1,500,000 $ 4.11 Fourth Quarter 2015 1,900,000 $ 4.12 Calendar Year 2016 5,880,000 $ 4.22 Calendar Year 2017 1,830,000 $ 4.28 Total 14,380,000 Average price $ 4.18 Natural Gas Collars At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2016 180,000 $ 4.25 $ 3.89 Second Quarter 2016 180,000 $ 4.25 $ 3.89 Third Quarter 2016 180,000 $ 4.25 $ 3.89 Fourth Quarter 2016 60,000 $ 4.25 $ 3.89 Total 600,000 Average price $ 4.25 $ 3.89 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2015 240,000 $ 4.25 $ 3.79 Second Quarter 2015 240,000 $ 4.25 $ 3.79 Third Quarter 2015 240,000 $ 4.25 $ 3.79 Fourth Quarter 2015 200,000 $ 4.25 $ 3.85 Calendar Year 2016 600,000 $ 4.25 $ 3.89 Total 1,520,000 Average price $ 4.25 $ 3.84 Derivative Positions — Fuel Products Segment Crude Oil Swap Contracts At December 31, 2015 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2016 29,120 320 $ 44.06 Second Quarter 2016 29,120 320 $ 44.06 Third Quarter 2016 29,440 320 $ 44.06 Fourth Quarter 2016 29,440 320 $ 44.06 Calendar Year 2017 630,720 1,728 $ 54.94 Total 747,840 Average price $ 53.24 At December 31, 2014 , 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 First Quarter 2015 315,000 3,500 $ 97.71 Total 315,000 Average price $ 97.71 At December 31, 2014 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 89.55 Second Quarter 2015 91,000 1,000 $ 89.89 Third Quarter 2015 386,400 4,200 $ 69.20 Fourth Quarter 2015 386,400 4,200 $ 69.20 Calendar Year 2016 972,828 2,658 $ 78.02 Total 3,510,628 Average price $ 81.89 At December 31, 2014 , the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 84.21 Total 1,674,000 Average price $ 84.21 Crude Oil Basis Swap Contracts The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between LLS and NYMEX WTI. At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 182,000 2,000 $ 2.40 Second Quarter 2016 182,000 2,000 $ 2.40 Third Quarter 2016 184,000 2,000 $ 2.40 Fourth Quarter 2016 184,000 2,000 $ 2.40 Total 732,000 Average differential $ 2.40 The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 91,000 1,000 $ (14.10 ) Second Quarter 2016 91,000 1,000 $ (14.10 ) Third Quarter 2016 92,000 1,000 $ (14.10 ) Fourth Quarter 2016 92,000 1,000 $ (14.10 ) Calendar Year 2017 365,000 1,000 $ (13.70 ) Total 731,000 Average differential $ (13.90 ) At December 31, 2014 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2015 118,000 2,000 $ (22.40 ) Total 118,000 Average differential $ (22.40 ) Crude Oil Percentage Basis Swap Contracts The Company has entered into derivative instruments to secure a percentage differential on WCS crude oil to NYMEX WTI. At December 31, 2015 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl) First Quarter 2016 728,000 8,000 73.5 % Second Quarter 2016 728,000 8,000 73.5 % Third Quarter 2016 736,000 8,000 73.5 % Fourth Quarter 2016 736,000 8,000 73.5 % Calendar Year 2017 730,000 2,000 73.0 % Total 3,658,000 Average percentage 73.4 % At December 31, 2014 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI (Average % of WTI/ B bl) Third Quarter 2015 184,000 2,000 73.0 % Fourth Quarter 2015 184,000 2,000 73.0 % Total 368,000 Average percentage 73.0 % Crude Oil Option Contracts During 2015 , the Company entered into derivative instruments to mitigate the risk of future changes in the price of NYMEX WTI crude oil. At December 31, 2015 , the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Call ($/Bbl) Fourth Quarter 2016 350,000 11,290 $ 55.00 Total 350,000 Average price $ 55.00 Gasoline Swap Contracts At December 31, 2014 , 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 ($/Bbl) First Quarter 2015 315,000 3,500 $ 109.68 Total 315,000 Average price $ 109.68 At December 31, 2014 , the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges: Gasoline Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 45,000 500 $ 78.12 Total 45,000 Average price $ 78.12 At December 31, 2014 , the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as hedges: Gasoline Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 45,000 500 $ 111.72 Total 45,000 Average price $ 111.72 Gasoline Crack Spread Swap Contracts At December 31, 2015 , the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges: Gasoline Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2016 873,000 9,593 $ 8.98 Total 873,000 Average price $ 8.98 Diesel Swap Contracts At December 31, 2014 , the Company had the following derivatives related to diesel purchases in its fuel products segment, none of which are designated as hedges: Diesel Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap ($/Bbl) First Quarter 2015 1,449,000 16,100 $ 105.78 Total 1,449,000 Average price $ 105.78 At December 31, 2014 , the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges: Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2015 1,449,000 16,100 $ 116.27 Second Quarter 2015 91,000 1,000 $ 117.92 Third Quarter 2015 322,000 3,500 $ 95.04 Fourth Quarter 2015 322,000 3,500 $ 95.04 Calendar Year 2016 915,000 2,500 $ 104.32 Total 3,099,000 Average price $ 108.38 Diesel Percentage Basis Crack Spread Swap Contracts The Company has entered into derivative instruments to secure a fixed percentage of gross profit on diesel in excess of the floating value of NYMEX WTI crude oil. At December 31, 2014 , the Company had the following diesel percentage basis crack spread swap contracts in its fuel products segment, none of which are designated as hedges: Diesel Percentage Basis Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average % of WTI/Bbl Third Quarter 2015 414,000 4,500 33.2 % Fourth Quarter 2015 414,000 4,500 33.2 % Calendar Year 2016 1,647,000 4,500 31.7 % Total 2,475,000 Average percentage 32.2 % Jet Fuel Swap Contracts At December 31, 2014 , the Company had the following derivatives related to jet fuel purchases 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 2015 180,000 2,000 $ 100.91 Total 180,000 Average price $ 100.91 At December 31, 2014 , the Company had the following derivatives related to jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges: Jet Fuel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 180,000 2,000 $ 115.65 Total 180,000 Average price $ 115.65 Natural Gas Swap Contracts At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its fuel products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 603,000 $ 3.01 Second Quarter 2016 603,000 $ 2.99 Third Quarter 2016 606,000 $ 3.03 Fourth Quarter 2016 790,000 $ 3.02 Total 2,602,000 Average price $ 3.01 Platinum Swap Contracts At December 31, 2014 , the Company had approximately 1,900 troy ounces of platinum swap contracts through 2015 in its fuel products segment, none of which are designated as hedges.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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 Baa1 and BBB+ by Moody’s and S&P, respectively. To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument, the Company uses discounted cash flows, which use observable inputs such as maturity and market interest rates. 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 creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the transaction 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, 2015 , the Company’s net liability was reduced by approximately $1.2 million . As a result of applying the CVA at December 31, 2014 , the Company’s net asset was increased by approximately $2.0 million and net liability was reduced by approximately $0.1 million . Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily 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, 2015 , the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of 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 NAV of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. Plan investments can be redeemed within a short time frame (10 or so business days), if requested. 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 Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date. 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 net of amounts internally generated and the market 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. In October 2014, the EPA granted the Company’s Shreveport and San Antonio refineries a “small refinery exemption” under the RFS for the full year 2013, as provided for under the Clean Air Act. The EPA determined that for the full year 2013, compliance with the RFS would represent a “disproportionate economic hardship” for these two refineries. As a result of the exemption, the Company sold all excess RINs related to these refineries for a gain of $18.2 million , net of cost to generate, recorded in cost of sales for the year ended December 31, 2014 , in the consolidated statements of operations. For the years ended December 31, 2015 and 2014 , the Company sold approximately 89 million RINs and 31 million RINS, respectively, for a gain of $55.4 million and $14.5 million , respectively, net of cost to generate, recorded in cost of sales in the consolidated statements of operations. As of December 31, 2015 and 2014 , the Company had a RINs Obligation of approximately 125 million RINs and 87 million RINs, respectively, which resulted in RINs expense for the years ended December 31, 2015 and 2014 , of approximately $94.2 million and $23.9 million , respectively. Hierarchy of Recurring Fair Value Measurements The Company’s recurring assets and liabilities measured at fair value at December 31, 2015 and 2014 were as follows (in millions): December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Crude oil swaps $ — $ — $ — $ — $ — $ — $ (89.8 ) $ (89.8 ) Crude oil basis swaps — — — — — — 0.8 0.8 Crude oil percentage basis swaps — — — — — — (0.2 ) (0.2 ) Gasoline swaps — — — — — — 13.5 13.5 Diesel swaps — — — — — — 97.0 97.0 Diesel crack spread swaps — — — — — — 4.5 4.5 Jet fuel swaps — — — — — — 2.7 2.7 Natural gas swaps — — — — — — (7.2 ) (7.2 ) Natural gas collars — — — — — — (0.5 ) (0.5 ) Platinum swaps — — — — — — (0.1 ) (0.1 ) Interest rate swaps — — — — — — 2.5 2.5 Total derivative assets — — — — — — 23.2 23.2 Pension plan investments 0.4 47.1 — 47.5 0.2 49.4 — 49.6 Total recurring assets at fair value $ 0.4 $ 47.1 $ — $ 47.5 $ 0.2 $ 49.4 $ 23.2 $ 72.8 Liabilities: Derivative liabilities: Crude oil swaps $ — $ — $ (5.2 ) $ (5.2 ) $ — $ — $ 5.0 $ 5.0 Crude oil basis swaps — — (0.3 ) (0.3 ) — — — — Crude oil percentage basis swaps — — (6.7 ) (6.7 ) — — — — Crude oil options — — (0.3 ) (0.3 ) — — — — Gasoline swaps — — — — — — 3.8 3.8 Gasoline crack spread swaps — — (4.3 ) (4.3 ) — — — — Diesel swaps — — — — — — (9.0 ) (9.0 ) Natural gas swaps — — (16.2 ) (16.2 ) — — (4.9 ) (4.9 ) Natural gas collars — — (0.9 ) (0.9 ) — — (0.5 ) (0.5 ) Total derivative liabilities — — (33.9 ) (33.9 ) — — (5.6 ) (5.6 ) RINs Obligation — (88.4 ) — (88.4 ) — (16.3 ) — (16.3 ) Liability Awards — — — — (4.7 ) — — (4.7 ) Total recurring liabilities at fair value $ — $ (88.4 ) $ (33.9 ) $ (122.3 ) $ (4.7 ) $ (16.3 ) $ (5.6 ) $ (26.6 ) 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 years ended December 31, 2015 and 2014 (in millions): Derivative Instruments, Net For the Year Ended December 31, 2015 2014 Fair value at January 1, $ 17.6 $ (54.8 ) Realized gain on derivative instruments (8.1 ) (43.8 ) Unrealized loss on derivative instruments (39.5 ) (0.6 ) Interest income, net (0.5 ) (0.8 ) Change in fair value of cash flow hedges (7.3 ) 114.2 Settlements 3.9 3.4 Transfers in (out) of Level 3 — — Fair value at December 31, $ (33.9 ) $ 17.6 Total loss included in net loss attributable to changes in unrealized loss relating to financial assets and liabilities held as of December 31, $ (39.5 ) $ (0.6 ) All settlements from derivative instruments designated as cash flow hedges and deemed “effective” 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 settlements from derivative instruments designated as cash flow hedges are recorded in earnings in realized gain (loss) on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments designated as fair value hedges are accrued and recorded as an adjustment to interest expense in the consolidated statements of operations. All settlements from derivative instruments not designated as 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. 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. The Company periodically evaluates the carrying value of long-lived assets to be held and used, including 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. Estimated Fair Value of Financial Instruments Cash The carrying value of cash is considered to be representative of its fair value. Debt The estimated aggregate fair value of the Company’s senior notes defined as Level 1 was based upon quoted market prices in an active market. The estimated aggregate fair value of the Company’s senior notes classified as Level 2 was 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. The carrying value of the related party note payable approximates its fair value due to the short-term maturity of this financial instrument. 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, 2015 and 2014 , were as follows (in millions): December 31, 2015 December 31, 2014 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,095.8 $ 1,230.8 $ 630.0 $ 606.6 Senior notes 2 $ 294.1 $ 317.6 $ 803.3 $ 885.3 Revolving credit facility 3 $ 105.1 $ 105.1 $ 143.3 $ 143.3 Note payable - related party 3 $ 73.5 $ 73.5 $ — $ — Capital lease and other obligations 3 $ 46.4 $ 46.4 $ 43.6 $ 43.6

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Partners' Capital	Partners’ Capital Units Outstanding Of the 75,884,400 common units outstanding at December 31, 2015 , 59,623,920 common units were held by the public, with the remaining 16,260,480 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 Distribution Per Common Unit Marginal Percentage 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 the greater of (i) 15% of the Borrowing Base (as defined in the credit agreement) then in effect and (ii) $70.0 million. 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 (a) 12.5% of the Borrowing Base (as defined in the credit agreement) then in effect and (b) $45.0 million, the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the credit agreement) of at least 1.0 to 1.0. The indentures governing the 2021 Notes, 2022 Notes and 2023 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 $225.0 million basket for the 2021 Notes, (ii) a $210.0 million basket for the 2022 Notes and (iii) a $225.0 million basket for the 2023 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, 2015 , 2014 and 2013 , the Company made distributions of $224.6 million , $210.2 million and $201.6 million , respectively, to its partners. For the years ended December 31, 2015 , 2014 and 2013 , the general partner was allocated $16.8 million , $15.4 million and $14.7 million , respectively, in incentive distribution rights. Public Offerings of Common Units During 2015 , 2014 and 2013 , the Company completed the following marketed 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 January 8, 2013 5,750,000 (3) $ 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. April 1, 2013 6,037,500 (4) $ 37.50 $ 217.3 $ 4.6 $ 9.1 Net proceeds were used for general partnership purposes. March 13, 2015 6,000,000 $ 26.75 $ 153.9 $ 3.3 $ 6.4 Net proceeds were used to redeem a portion of the 2020 Notes and to repay borrowings under the revolving credit facility. (1) Proceeds are net of underwriting discounts, commissions and expenses but before the general partner’s capital contribution. (2) The Company’s general partner contributions were made to retain its 2% general partner interest. (3) 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. (4) Includes the full exercise of the overallotment option of 787,500 common units which closed on April 4, 2013. On March 10, 2014 , the Company entered into an Equity Placement Agreement with various sales agents under which the Company may issue and sell, from time to time, common units representing limited partner interests, having an aggregate offering price of up to $300.0 million through one or more sales agents. The Equity Placement Agreement provides the Company the right, but not the obligation, to sell common units in the future, at prices the Company deems appropriate. These sales, if any, will be made pursuant to the terms of the Equity Placement Agreement between the Company and the sales agents. The net proceeds from any sales under this agreement will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, working capital, capital expenditures and acquisitions. The Company’s general partner contributed its proportionate capital contribution to retain its 2% general partner interest. For the years ended December 31, 2015 and 2014 , the Company sold 432,167 and 134,955 , respectively, common units under the Equity Placement Agreement for net proceeds of $10.2 million and $3.6 million , respectively. Underwriting discounts for 2015 and 2014 totaled $0.1 million and $0.1 million , respectively, and the Company’s general partner contributed $0.2 million and $0.1 million , respectively, to maintain its general partner interest.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2015
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 December 10, 2015 (“LTIP”), for its employees, consultants and directors and its affiliates who perform services for the Company. The LTIP 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 3,883,960 common units may be delivered pursuant to awards under the LTIP. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP 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 LTIP as part of their director compensation package related to fiscal years 2013 and 2014 . 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. In addition, the recipients have DERs on these phantom units from the date of grant. For the years ended December 31, 2015 and 2014 , named executive officers and certain employees were awarded phantom units under the terms of the LTIP, 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. As a result of the amendment and restatement of the LTIP on December 10, 2015, all Liability Awards were modified to value the awards based upon the closing unit price on that date. This modification did not affect the remaining service period. A summary of the Company’s non-vested phantom units as of December 31, 2015 , and the changes during the years ended December 31, 2015 , 2014 and 2013 , are presented below: Number of Phantom Units Weighted-Average Grant Date Fair Value Non-vested at January 1, 2013 835,927 $ 27.57 Granted 483,044 27.73 Vested (276,115 ) 24.22 Forfeited (354,600 ) 30.60 Non-vested at December 31, 2013 688,256 $ 23.70 Granted 477,527 25.97 Vested (280,263 ) 23.72 Forfeited (383,400 ) 25.59 Non-vested at December 31, 2014 502,120 $ 26.48 Granted 343,533 21.70 Vested (321,741 ) 23.54 Forfeited (103,188 ) 23.94 Non-vested at December 31, 2015 420,724 $ 24.27 For the years ended December 31, 2015 , 2014 and 2013 , compensation expense of $7.5 million , $5.5 million and $4.8 million , respectively, was recognized in the consolidated statements of operations related to vested phantom unit grants, including $5.0 million , $2.5 million and $1.6 million , attributable to Liability Awards for the years ended December 31, 2015 , 2014 and 2013 , respectively. As of December 31, 2015 and 2014 , there was a total of $9.6 million and $12.2 million , respectively of unrecognized compensation costs related to nonvested phantom unit grants, including $10.5 million , attributable to Liability Awards for the year ended December 31, 2014 . These costs are expected to be recognized over a weighted-average period of approximately 3 years. The total fair value of phantom units vested during the years ended December 31, 2015 , 2014 and 2013 , was $7.0 million , $6.7 million and $6.7 million , respectively.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
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, 2015 , 2014 and 2013 (in millions): Year Ended December 31, 2015 2014 2013 401(k) Plan matching contribution expense $ 5.9 $ 5.4 $ 4.1 Profit sharing expense $ — $ 1.2 $ 0.9 Defined Benefit 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 Corporation (“Murphy Oil”) represented by the IUOE and who became employees of the Company as a result of the acquisition of the Superior refinery 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 2015 , the Company made contributions of $1.5 million to its Pension Plan and expects to make contributions in 2016 of approximately $1.9 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 of compensation 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. 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. Effective August 31, 2015, the Company again amended the Montana Pension Plan, which curtailed the collective bargaining employees from accumulating additional benefits subsequent to December 31, 2015. As a result, the Company recorded a $0.9 million curtailment gain for the year ended December 31, 2015. 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 acquisition of the Superior refinery 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 28, 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. The long-term accrued benefit obligation recognized in the consolidated balance sheets for the Penreco Other Plan was $0.2 million and $0.3 million as of December 31, 2015 and 2014, respectively. In addition, other post-retirement benefit income related to this plan was $0.4 million for 2015. There was no other post-retirement benefit income (cost) related to this plan for 2014. All information presented below has been adjusted for these curtailments for the Pension 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, 2015 2014 Pension Plan Change in projected benefit obligation: Benefit obligation at beginning of year $ 69.3 $ 57.2 Service cost 0.5 0.4 Interest cost 2.6 2.6 Plan curtailment (0.9 ) — Benefits paid (2.6 ) (2.5 ) Actuarial (gain) loss (8.6 ) 11.7 Administrative expense — (0.1 ) Benefit obligation at end of year $ 60.3 $ 69.3 Change in plan assets: Fair value of plan assets at beginning of year $ 49.6 $ 45.8 Benefit payments (2.6 ) (2.5 ) Actual return on assets (1.0 ) 4.9 Administrative expense — (0.1 ) Employer contribution 1.5 1.5 Fair value of plan assets at end of year $ 47.5 $ 49.6 Funded status — benefit obligation in excess of plan assets $ (12.8 ) $ (19.7 ) Reconciliation of amounts recognized in the consolidated balance sheets: Accrued benefit obligation, long-term $ (12.8 ) $ (19.7 ) Unrecognized net actuarial loss 6.8 11.9 Accumulated other comprehensive loss 6.8 11.9 Net amount recognized at end of year $ (6.0 ) $ (7.8 ) The accumulated benefit obligation for the Pension Plan was $60.3 million and $68.4 million as of December 31, 2015 and 2014 , 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, 2015 2014 Accumulated benefit obligation $ 60.3 $ 68.4 Fair value of plan assets $ 47.5 $ 49.6 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, 2015 2014 Projected benefit obligation $ 60.3 $ 69.3 Fair value of plan assets $ 47.5 $ 49.6 The components of net periodic pension cost (income) for 2015 , 2014 and 2013 were as follows (in millions): Pension Plan Year Ended December 31, 2015 2014 2013 Service cost $ 0.5 $ 0.4 $ 0.4 Interest cost 2.6 2.6 2.4 Expected return on assets (3.3 ) (3.1 ) (2.9 ) Amortization of net loss 0.8 0.3 0.8 Curtailment gain recognized (0.9 ) — — Net periodic benefit cost (income) $ (0.3 ) $ 0.2 $ 0.7 The components of changes recognized in other comprehensive (income) loss for the Pension Plan for 2015 , 2014 and 2013 were as follows (in millions): Pension Plan Year Ended December 31, 2015 2014 2013 Changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net (gain) loss $ (4.3 ) $ 9.9 $ (8.8 ) Amounts recognized as a component of net periodic benefit cost: Amortization or settlement recognition of net loss (0.8 ) (0.3 ) (0.8 ) Total recognized in other comprehensive (income) loss $ (5.1 ) $ 9.6 $ (9.6 ) The portion relating to the Pension Plan classified in accumulated other comprehensive income (loss) includes losses of $6.8 million and $11.9 million as of December 31, 2015 and 2014 , respectively. In 2016 , the estimated amount that will be amortized from accumulated other comprehensive income (loss) includes a net loss of $0.4 million for the Pension Plan. For the Pension Plan, the Company uses a corridor approach to amortize actuarial gains and losses. Under this approach, net actuarial gains or losses in excess of ten percent of the larger of the projected benefit obligation or the fair value of plan assets are amortized on a straight-line basis. The period of amortization is the average remaining service of active participants who are expected to receive benefits under the plans. All pension plans have a December 31 measurement date. The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2015 and 2014 , were as follows: Benefit Obligations Assumptions 2015 2014 Pension Plan: Discount rate for Penreco Pension Plan 4.30 % 3.92 % Discount rate for Superior Pension Plan 4.27 % 3.86 % Discount rate for Montana Pension Plan 4.21 % 4.13 % Rate of compensation increase for Montana Pension Plan N/A 3.00 % The significant weighted average assumptions used to determine the net periodic benefit cost (income) for the years ended December 31, 2015 , 2014 and 2013 were as follows: Net Periodic Benefit Cost (Income) Assumptions 2015 2014 2013 Pension Plan: Discount rate for Penreco Pension Plan 3.92 % 4.78 % 3.86 % Discount rate for Superior Pension Plan 3.86 % 4.66 % 3.75 % Discount rate for Montana Pension Plan 4.13 % 4.97 % 4.03 % Expected return on plan assets for Penreco Pension Plan (1) 6.75 % 6.75 % 6.75 % Expected return on plan assets for Superior Pension Plan (1) 6.75 % 6.75 % 6.75 % Expected return on plan assets for Montana Pension Plan (1) 6.75 % 6.75 % 6.75 % Rate of compensation increase for Montana Pension Plan 3.00 % 3.00 % 3.00 % (1) The Company considered the historical returns, the future expectation for returns for each asset class and fair value of the plan assets, 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. Investment Policy The Defined Benefit Plan Investment Committee (the “Investment Committee”) is responsible for the overall management of the Pension Plan assets, and its 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 Investment 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 Asset Allocation Target Allocation Domestic equities 15–25% 20% Foreign equities 15–25% 20% Fixed income 55–65% 60% Investment Fund Strategies Domestic equity 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, 2015 and 2014 , by asset category, are as follows: 2015 2014 Cash and cash equivalents 1 % — % Domestic equities 20 % 20 % Foreign equities 19 % 19 % Fixed income 60 % 61 % 100 % 100 % At December 31, 2015 , the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consisted 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, 2015 and 2014 , were as follows (in millions): Fair Value of Pension Assets at December 31, 2015 2014 Level 1 Level 2 Level 1 Level 2 Cash and cash equivalents $ 0.4 $ — $ 0.2 $ — Domestic equities — 9.6 — 10.0 Foreign equities — 9.2 — 9.4 Fixed income — 28.3 — 30.0 $ 0.4 $ 47.1 $ 0.2 $ 49.4 The following benefit payments for the Pension Plan, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2015 (in millions): Pension Benefits 2016 $ 2.8 2017 3.0 2018 3.0 2019 3.1 2020 3.3 2021 to 2025 17.6 Total $ 32.8

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Comprehensive Income (Loss) Note	Accumulated Other Comprehensive Loss The table below sets forth a summary of changes in accumulated other comprehensive income (loss) by component for the year ended December 31, 2015 and 2014 (in millions): Derivatives Defined Benefit Pension And Retiree Health Benefit Plans Foreign Currency Translation Adjustment Total Accumulated other comprehensive loss at December 31, 2013 $ (51.4 ) $ (1.9 ) $ (0.1 ) $ (53.4 ) Other comprehensive income (loss) before reclassifications 114.2 (9.9 ) (0.5 ) 103.8 Amounts reclassified from accumulated other comprehensive loss (37.0 ) 0.3 — (36.7 ) Net current period other comprehensive income (loss) 77.2 (9.6 ) (0.5 ) 67.1 Accumulated other comprehensive income (loss) at December 31, 2014 25.8 (11.5 ) (0.6 ) 13.7 Other comprehensive income (loss) before reclassifications (7.3 ) 4.3 (0.6 ) (3.6 ) Amounts reclassified from accumulated other comprehensive income (loss) (12.1 ) 0.4 — (11.7 ) Net current period other comprehensive income (loss) (19.4 ) 4.7 (0.6 ) (15.3 ) Accumulated other comprehensive income (loss) at December 31, 2015 $ 6.4 $ (6.8 ) $ (1.2 ) $ (1.6 ) The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive income (loss) in the Company’s consolidated statements of operations for the years ended December 31, 2015 and 2014 , (in millions): Components of Accumulated Other Comprehensive Income (Loss) 2015 2014 Location of Gain (Loss) Derivative gains (losses) reflected in gross profit $ 179.4 $ (9.0 ) Sales (167.3 ) 46.0 Cost of sales $ 12.1 $ 37.0 Total Amortization of defined benefit pension benefit plans: Amortization of net loss $ (0.8 ) $ (0.3 ) (1) $ (0.8 ) $ (0.3 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 12 for additional information.

Income Taxes Income Taxes

Income Taxes Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes The Company conducts certain activities through wholly-owned subsidiaries that are corporations which in certain circumstances are subject to federal, state and local income taxes. On December 31, 2015, ADF Holdings, Inc. converted to ADF Holdings, LLC and Anchor Drilling Fluids USA, Inc. converted to Anchor Drilling Fluids USA, LLC. Both ADF Holdings, LLC and Anchor Drilling Fluids USA, LLC have elected to be treated as pass-through entities for tax purposes. As a result, the activities of Anchor will be included in the earnings of the Company going forward and generally the Company will not be subject to federal and state income taxes. As of December 31, 2015 , 2014 and 2013 , the components of federal and state income tax expense are summarized as follows (in millions): December 31, 2015 2014 2013 Current expense: Federal $ 0.1 $ 0.2 $ — State — 0.2 0.4 Total $ 0.1 $ 0.4 $ 0.4 Deferred expense (benefit): Federal $ (26.5 ) $ (1.5 ) $ — State (2.0 ) 0.3 — Total $ (28.5 ) $ (1.2 ) $ — Total income tax expense (benefit) $ (28.4 ) $ (0.8 ) $ 0.4 A reconciliation of effective tax rate to the U.S. statutory rate attributable to operations for December 31, 2015 , 2014 and 2013 is as follows: December 31, 2015 2014 2013 Federal income tax rate 35.0 % 35.0 % 35.0 % Partnership earnings not subject to tax (13.8 )% (22.4 )% (35.0 )% State income taxes, net of federal income tax effect 0.6 % (0.4 )% 11.4 % State tax rate change 0.2 % — % — % Impact of non-deductible goodwill (5.0 )% (11.5 )% — % Anchor LLC conversions 0.3 % — % — % Other items, net (0.4 )% — % (1.1 )% Effective tax rate 16.9 % 0.7 % 10.3 % Deferred Taxes Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows as of December 31, 2015 and 2014 (in millions): December 31, 2015 2014 Deferred income tax assets: Inventory $ — $ 2.3 Net operating loss carryforwards 0.8 3.7 Total deferred income tax assets $ 0.8 $ 6.0 Deferred income tax liabilities: Intangible assets $ (0.1 ) $ (22.0 ) Unrealized gains (0.5 ) — Property, plant and equipment (2.0 ) (14.0 ) Total deferred income tax liabilities $ (2.6 ) $ (36.0 ) Net deferred income tax liability $ (1.8 ) $ (30.0 ) As a result of the Company’s analysis, management has determined that the Company does not have any uncertain tax positions. As of December 31, 2015 , the Company had tax loss carryforwards of approximately $2.1 million , which are expected to be utilized prior to expiration in 2035. As of December 31, 2015 , the Company had $0.8 million deferred tax assets arising from net operating loss carryforwards. The Company’s federal and state tax returns remain subject to examination by taxing authorities for three years.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2015
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, 2015 , 2014 and 2013 (in millions, except unit and per unit data): Year Ended December 31, 2015 2014 2013 Numerator for basic and diluted earnings per limited partner unit: Net income (loss) $ (139.4 ) $ (112.2 ) $ 3.5 Less: General partner’s interest in net income (loss) (2.8 ) (2.2 ) 0.1 General partner’s incentive distribution rights 16.8 15.4 14.7 Non-vested share based payments — — 0.2 Net loss available to limited partners $ (153.4 ) $ (125.4 ) $ (11.5 ) Denominator for basic and diluted earnings per limited partner unit: Basic weighted average limited partner units outstanding 74,896,096 69,671,827 67,938,784 Diluted weighted average limited partner units outstanding (1) 74,896,096 69,671,827 67,938,784 Limited partners’ interest basic and diluted net loss per unit $ (2.05 ) $ (1.80 ) $ (0.17 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.4 million , 0.2 million and 0.2 million potentially dilutive phantom units for the years ended December 31, 2015 , 2014 and 2013 , respectively.

Transactions with Related Parti

Transactions with Related Parties	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Transactions with Related Parties	Transactions with Related Parties During the years ended December 31, 2015 , 2014 and 2013 , the Company had product sales to related parties owned by a limited partner, excluding the transactions discussed below, of $12.0 million , $9.1 million and $9.7 million , respectively. Trade accounts and other receivables from related parties at December 31, 2015 and 2014 were $0.4 million and $1.2 million , respectively. The Company also had purchases from related parties owned by a limited partner, excluding transactions discussed below, during the years ended December 31, 2015 , 2014 and 2013 of $21.8 million , $41.1 million and $9.0 million , respectively. Accounts payable to related parties, excluding accounts payable related to the transactions discussed below, at December 31, 2015 and 2014 , were $2.3 million and $4.3 million , respectively. The Company has a crude oil supply agreement with Legacy Resources, the Master Crude Oil Purchase and Sale Agreement. Legacy Resources is owned in part by one of the Company’s general partners, the Company’s executive vice chairman of the board of the Company’s general partner, F. William Grube. No crude oil is currently being purchased by the Company under this agreement. During the year ended December 31, 2015 , the Company had no crude oil purchases from Legacy Resources. During the years ended December 31, 2014 and 2013 , the Company had crude oil purchases of $0.8 million and $1.2 million , respectively, from Legacy Resources under spot agreements. The Company had no accounts payable to Legacy Resources at December 31, 2015 and December 31, 2014 . Nicholas J. Rutigliano, a former member of the board of directors of the Company’s general partner who retired in September 2014, 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. There were no premiums paid to Tobias for the year ended December 31, 2015 . The total premiums paid to Tobias by the Company for the years ended December 31, 2014 and 2013 , were $0.7 million and $0.7 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, 2015 , 2014 and 2013 . The Company has a general services master services agreement with a third party construction company related to the Montana refinery expansion project in which various construction related services were performed during 2015 and 2014. This third party is related to refinery management. For the years ended December 31, 2015 , 2014 and 2013 , the Company had capital expenditures of $43.0 million , $29.0 million and $6.3 million , respectively, for construction related services. Accounts payable under this contract at December 31, 2015 and 2014 , were $10.0 million and $2.6 million , respectively. During 2015, the Company entered into an agreement for logistic administration/support, general administrative management and fiscal administration services with Monument Chemicals, Inc. (“Monument Chemical”). Monument Chemical is owned by a limited partner and a member of the board of the Company’s general partner is a member of Monument Chemical’s management. Under this agreement, Monument Chemical rents storage tanks in Belgium on the Company’s behalf and organizes delivery of products to the Company’s customers. A commission is paid to Monument Chemical based on the sales value invoiced to the Company’s customers. For the year ended December 31, 2015 , the Company paid total commissions and general administrative fees of $0.5 million . Accounts payable under this contract at December 31, 2015 were immaterial. During the year ended December 31, 2015 and 2014 , the Company entered into various transactions with Dakota Prairie. See Note 4 for further information on Dakota Prairie transactions. On December 30, 2015, the Company entered into an agreement with Heritage in which Heritage made an uncommitted prepayment for the purchase of certain finished products and entered into an unsecured note payable with the Company as the borrower. See Note 7 for further information on this agreement.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2015
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, jet fuel and asphalt which are primarily sold to customers located in the PADD 2, PADD 3 and PADD 4 areas within the U.S. • Oilfield Services. The oilfield services segment markets its products and oilfield services including drilling fluids, completion fluids and solids control services to the oil and gas industry. During the fourth quarter 2014, the Company realigned its reportable segments for financial reporting purposes as a result of the Anchor and SOS Acquisitions in 2014 resulting in a new segment, oilfield services. Prior to this change, Anchor and SOS were reported as part of the specialty products segment. This reporting change did not impact the Company’s consolidated results. The accounting policies of the reporting segments are the same as those described in the summary of significant accounting policies as disclosed 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 accounts for intersegment sales and transfers at cost plus a specified mark-up. 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. 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, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,367.8 $ 2,562.5 $ 282.5 $ 4,212.8 $ — $ 4,212.8 Intersegment sales 3.9 39.1 — 43.0 (43.0 ) — Total sales $ 1,371.7 $ 2,601.6 $ 282.5 $ 4,255.8 $ (43.0 ) $ 4,212.8 Loss from unconsolidated affiliates $ — $ (61.1 ) $ (0.4 ) $ (61.5 ) $ — $ (61.5 ) Adjusted EBITDA $ 201.7 $ 81.9 $ (25.9 ) $ 257.7 $ — $ 257.7 Reconciling items to net loss: Depreciation and amortization 69.2 82.4 22.8 174.4 — 174.4 Realized loss on derivatives, not reflected in net loss or settled in a prior period (3.0 ) (7.0 ) — (10.0 ) — (10.0 ) Impairment charges — 24.3 33.8 58.1 — 58.1 Unrealized loss on derivatives 39.5 Interest expense 104.9 Debt extinguishment costs 46.6 Non-cash equity based compensation and other items 12.0 Income tax benefit (28.4 ) Net loss $ (139.4 ) Year Ended December 31, 2014 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,729.2 $ 3,693.4 $ 368.5 $ 5,791.1 $ — $ 5,791.1 Intersegment sales 18.4 89.8 — 108.2 (108.2 ) — Total sales $ 1,747.6 $ 3,783.2 $ 368.5 $ 5,899.3 $ (108.2 ) $ 5,791.1 Loss from unconsolidated affiliates $ — $ (3.2 ) $ (0.2 ) $ (3.4 ) $ — $ (3.4 ) Adjusted EBITDA $ 220.8 $ 50.0 $ 35.1 $ 305.9 $ — $ 305.9 Reconciling items to net loss: Depreciation and amortization 68.1 80.0 15.0 163.1 — 163.1 Realized gain (loss) on derivatives, not reflected in net loss or settled in a prior period (1.9 ) 8.5 — 6.6 — 6.6 Impairment charges — — 36.0 36.0 — 36.0 Unrealized loss on derivatives 0.6 Interest expense 110.8 Debt extinguishment costs 89.9 Non-cash equity based compensation and other items 11.9 Income tax benefit (0.8 ) Net loss $ (112.2 ) Year Ended December 31, 2013 Specialty Fuel Oilfield Services Combined Eliminations Consolidated Sales: External customers $ 1,774.9 $ 3,646.5 $ — $ 5,421.4 $ — $ 5,421.4 Intersegment sales — 77.3 — 77.3 (77.3 ) — Total sales $ 1,774.9 $ 3,723.8 $ — $ 5,498.7 $ (77.3 ) $ 5,421.4 Loss from unconsolidated affiliates $ — $ (0.3 ) $ — $ (0.3 ) $ — $ (0.3 ) Adjusted EBITDA $ 194.5 $ 47.0 $ — $ 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 or settled in a prior period (0.5 ) (1.3 ) — (1.8 ) — (1.8 ) Impairment charges 10.5 — — 10.5 — 10.5 Unrealized gain on derivatives (25.7 ) Interest expense 96.8 Debt extinguishment costs 14.6 Non-cash equity based compensation and other items 9.5 Income tax expense 0.4 Net income $ 3.5 b. Geographic Information International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2015 , 2014 and 2013 . Substantially all of the Company’s long-lived assets are domestically located. c. Product Information The Company offers specialty products primarily in 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, heavy fuel oils and other. All oilfield services products are consolidated in a standalone category. The following table sets forth the major product category sales (in millions): Year Ended December 31, 2015 2014 2013 Specialty products: Lubricating oils $ 575.6 13.7 % $ 748.4 12.9 % $ 848.8 15.7 % Solvents 302.0 7.2 % 485.2 8.4 % 511.7 9.4 % Waxes 136.9 3.2 % 144.1 2.5 % 141.0 2.6 % Packaged and synthetic specialty products 316.6 7.5 % 313.5 5.4 % 233.6 4.3 % Other 36.7 0.9 % 38.0 0.7 % 39.8 0.7 % Total 1,367.8 32.5 % 1,729.2 29.9 % 1,774.9 32.7 % Fuel products: Gasoline 1,047.1 24.9 % 1,443.1 24.9 % 1,409.4 26.0 % Diesel 894.8 21.2 % 1,197.4 20.7 % 1,259.2 23.3 % Jet fuel 149.6 3.6 % 199.3 3.4 % 191.4 3.5 % Asphalt, heavy fuel oils and other 471.0 11.1 % 853.6 14.7 % 786.5 14.5 % Total 2,562.5 60.8 % 3,693.4 63.7 % 3,646.5 67.3 % Oilfield services: Total 282.5 6.7 % 368.5 6.4 % — — % Consolidated sales $ 4,212.8 100.0 % $ 5,791.1 100.0 % $ 5,421.4 100.0 % d. Major Customers During the years ended December 31, 2015 , 2014 and 2013 , the Company had no customer that represented 10% or greater of consolidated sales. e. Major Suppliers During the years ended December 31, 2015 , 2014 and 2013 , the Company had two suppliers that supplied approximately 52.2% , 45.9% and 54.1% , respectively, of its crude oil supply.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
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 Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 2015 Sales $ 1,018.6 $ 1,156.2 $ 1,140.0 $ 898.0 $ 4,212.8 Gross profit 195.2 202.7 164.8 31.9 594.6 Net income (loss) 23.8 2.5 (48.9 ) (116.8 ) (139.4 ) Net income (loss) available to limited partners 19.1 (1.7 ) (52.2 ) (118.6 ) (153.4 ) Limited partners’ interest basic and diluted net income (loss) per unit $ 0.27 $ (0.02 ) $ (0.68 ) $ (1.56 ) $ (2.05 ) Weighted average limited partner units outstanding — basic 71,232,392 76,092,517 76,112,325 76,124,133 Weighted average limited partner units outstanding — diluted 71,275,452 76,092,517 76,112,325 76,124,133 First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 2014 Sales $ 1,341.0 $ 1,434.9 $ 1,675.8 $ 1,339.4 $ 5,791.1 Gross profit 124.8 99.0 182.6 123.3 529.7 Net income (loss) (49.8 ) (8.3 ) 9.4 (63.5 ) (112.2 ) Net income (loss) available to limited partners (52.6 ) (12.0 ) 5.4 (66.2 ) (125.4 ) Limited partners’ interest basic and diluted net income (loss) per unit $ (0.76 ) $ (0.17 ) $ 0.08 $ (0.95 ) $ (1.80 ) Weighted average limited partner units outstanding — basic 69,622,884 69,604,669 69,684,621 69,775,827 Weighted average limited partner units outstanding — diluted 69,622,884 69,604,669 69,850,685 69,775,827 (1) The sum of the four quarters may not equal the total year due to rounding.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On January 19, 2016 , the Company declared a quarterly cash distribution of $0.685 per unit on all outstanding common units, or approximately $57.4 million (including the general partner’s incentive distribution rights) in aggregate, for the quarter ended December 31, 2015 . The distribution was paid on February 12, 2016 , to unitholders of record as of the close of business on February 2, 2016 . This quarterly distribution of $0.685 per unit equates to $2.74 per unit, or approximately $229.6 million (including the general partner’s incentive distribution rights) in aggregate on an annualized basis. The fair value of the Company’s derivatives that were outstanding as of December 31, 2015 , decreased by approximately $9.0 million subsequent to December 31, 2015 , to a net liability of approximately $38.0 million . The fair value of the Company’s senior notes has decreased by approximately $455.0 million subsequent to December 31, 2015 .

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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.
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 principles (“U.S. GAAP”) 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 include 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. 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 $41.0 million lower and $18.9 million lower as of December 31, 2015 and 2014 , respectively. At December 31, 2015 and 2014 , the Company had $1.4 million and $1.7 million , respectively, of consigned inventory. Inventories consisted of the following (in millions): December 31, 2015 2014 Raw materials $ 47.9 $ 77.8 Work in process 64.0 75.4 Finished goods 272.5 360.3 $ 384.4 $ 513.5 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, 2015 , 2014 and 2013 , the Company recorded gains and (losses) of $(24.3) million , $(26.5) million and $4.2 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. Such write downs are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. During the years ended December 31, 2015 and 2014 the Company recorded $81.8 million and $74.1 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. 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), natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. 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; • precious metals purchases: and • fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”). The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions. The changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in risk profiles. These changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise. The Company recognizes all derivative instruments at their fair values (see Note 9 ) as either current assets or current liabilities in 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 portions or all of its derivative instruments for hedge accounting. Derivative Instruments Designated as Cash Flow Hedges The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel swaps as cash flow hedges. The derivative instruments designated as cash flow hedges that are 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 cash flow 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 cash flow hedge. To the extent a derivative instrument designated as a cash flow 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. 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 cash flow hedge accounting. Ineffectiveness has resulted, and the loss of cash flow hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow 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. Cash flow 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 cash flow 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 deferred 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. Derivative Instruments Designated as Fair Value Hedges For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the consolidated statements of operations. No hedge ineffectiveness was recognized as the interest rate swap qualifies for the “shortcut” method and, as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items. Fair value 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 fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as effective fair value hedge, the derivative instrument is still subject to mark-to-market method of accounting, however the Company will cease to adjust the hedged asset or liability for changes in fair value. Derivative Instruments Not Designated as Hedges For derivative instruments not designated as hedges, 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 hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations. 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. Additionally, the Company has entered into diesel crack spread collars, gasoline crack spread collars, natural gas collars, and certain other crude oil swaps, diesel swaps, gasoline swaps, natural gas swaps and platinum swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and 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 and Juniper GTL LLC joint ventures in accordance with ASC 323, Investments — Equity Method and Joint Ventures. 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 as 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. The Company recorded a $24.3 million impairment charge in loss from unconsolidated affiliates in the consolidated statement of operations for the year ended December 31, 2015 . No impairment was recognized in 2014 and 2013 .
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”). 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. 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.
Other Intangible Assets	Definite lived 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.
Turnaround Costs	Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and were $60.4 million and $70.1 million as of December 31, 2015 and 2014 , 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 $71.6 million and $46.2 million at December 31, 2015 and 2014 , 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 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.
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 the 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. The Company recognizes revenue on certain drilling fluids and completion fluids when consumed at the customer site during the drilling process.
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 and state income taxes on the earnings of Calumet Specialty Products Partners, L.P. and its wholly-owned subsidiaries. However, the Company conducts certain activities through wholly-owned subsidiaries that are corporations, which in certain circumstances are subject to federal, state and local income taxes. Additionally, the Company is subject to franchise taxes in certain states. Income taxes on the earnings of the Company, with the exception of the above mentioned taxes, are the responsibility of its partners, with earnings of the Company included in partners’ earnings. In the event that the Company’s taxable income does 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, 2015 and 2014 . The Company accounts for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in the Company’s financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, the Company reassesses these probabilities and records any changes through the provision for income taxes.
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 December 10, 2015 (“LTIP”), for its employees, consultants and directors and its affiliates who perform services for the Company. The LTIP 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 3,883,960 common units may be delivered pursuant to awards under the LTIP. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP 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 LTIP as part of their director compensation package related to fiscal years 2013 and 2014 . 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. In addition, the recipients have DERs on these phantom units from the date of grant. For the years ended December 31, 2015 and 2014 , named executive officers and certain employees were awarded phantom units under the terms of the LTIP, 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 which totaled $14.2 million , $20.5 million and $14.6 million in 2015 , 2014 and 2013 , respectively. Advertising expenses are reported as selling expenses in the consolidated statements of operations.
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 (“RFS”). 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. From time to time, the Company holds varying amounts of RINs for resale. RINs obtained from third parties are initially recorded at their cost at the time the Company acquires them and are subsequently revalued at the lower of cost or market as of the last day of each accounting period and the resulting adjustments are reflected in costs of goods sold for the period. The value of RINs obtained from third parties would be reflected in prepaid expenses and other assets on the consolidated balance sheets.
Foreign Currency Translation and Transactions	Certain of the Company’s subsidiaries use a local currency as their functional currency. Assets and liabilities of subsidiaries with a local currency as their functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income (loss), which is reflected in partners’ capital in the Company’s consolidated balance sheets. Certain of the Company’s subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than such entity’s respective functional currency. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in other income (expense) in the consolidated statements of operations.
New Accounting Pronouncements	In January 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). ASU 2016-01 requires that (i) equity investments in unconsolidated entities that are not accounted for under the equity method of accounting generally be measured at fair value with changes recognized in net income and (ii) when the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk be recognized separately in other comprehensive income. Additionally, ASU 2016-01 changes the presentation and disclosure requirements for financial instruments. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”) . ASU 2015-17 requires that businesses classify deferred tax liabilities and assets on their balance sheets as noncurrent. Under existing accounting, a business must separate deferred income tax liabilities and assets into current and noncurrent. The amendments in this standard may be applied retrospectively or prospectively and are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company adopted ASU 2015-17 retrospectively, which resulted in the Company reclassifying approximately $2.3 million , as of December 31, 2014 , of deferred income taxes from current assets to noncurrent deferred income taxes in the consolidated balance sheets. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this standard are effective prospectively for fiscal years (including interim periods) beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2015-16 is not expected to have an impact on the Company’s consolidated financial statements. In June 2015, the FASB issued ASU No. 2015-10, Technical Corrections and Improvements (“ASU 2015-10”). With regard to fair value measurement disclosures, ASU 2015-10 clarified that, for nonrecurring measurements estimated at a date during the reporting period other than the end of the reporting period, an entity should clearly indicate that the fair value information presented is not as of the period’s end as well as the date or period that the measurement was taken. The Company adopted ASU 2015-10, effective June 12, 2015, as the change was effective upon issuance. The adoption did not have an impact on the Company’s consolidated financial statements. In May 2015, the FASB issued ASU No. 2015-08, Business Combinations (Topic 805): Pushdown Accounting — Amendments to SEC Paragraphs Pursuant to Staff Bulletin No. 115 (“ASU 2015-08”). The amendments in ASU 2015-08 amend various SEC paragraphs included in the FASB’s Accounting Standards Codification to reflect the issuance of Staff Accounting Bulletin No. 115 (“SAB 115”). SAB 115 rescinds portions of the interpretive guidance included in the SEC’s Staff Accounting Bulletins series and brings existing guidance into conformity with ASU No. 2014-17, “ Business Combinations (Topic 805): Pushdown Accounting ,” which provides an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The Company adopted the amendments in ASU 2015-08, effective May 8, 2015, as the amendments in the update are effective upon issuance. The adoption did not have an impact on the Company’s consolidated financial statements. In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (“ASU 2015-07”). ASU 2015-07 provides guidance that amends the required disclosure of investments for which fair value is measured at net asset value (“NAV”) per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the NAV per share practical expedient. ASU 2015-07 is effective for fiscal periods (including interim periods) beginning after December 15, 2015, with early adoption permitted. ASU 2015-07 should be applied retrospectively. The adoption of ASU 2015-07 is not expected to have an impact on the Company’s consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-06, Earnings per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“ASU 2015-06”). ASU 2015-06 provides guidance for calculating historical earnings per unit under the two-class method, stating that the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest. ASU 2015-06 is effective for fiscal periods (including interim periods) beginning after December 15, 2015, with early adoption permitted. ASU 2015-06 should be applied retrospectively. The adoption of ASU 2015-06 is not expected to have an impact on the Company’s consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-05, Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (“ASU 2015-05”). ASU 2015-05 provides guidance to determine whether a cloud computing agreement includes a software license or should be considered as a service agreement. ASU 2015-05 is effective for fiscal periods (including interim periods) beginning after December 15, 2015, with early adoption permitted. An entity can elect to adopt the amendments either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The adoption of ASU 2015-05 is not expected to have an impact on the Company’s consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-04, Compensation — Retirement Benefits (Topic 715): Practical Expedient for the Measurement Date of an Employer’s Defined Benefit Obligation and Plan Assets (“ASU 2015-04”). ASU 2015-04 provides guidance for the measuring of assets in defined benefit pension plans and other retirement plans if they are on fiscal years that do not end on the last day of a month. ASU 2015-04 is effective for fiscal periods (including interim periods) beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2015-04 is not expected to have an impact on the Company’s consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs to be recognized in the balance sheet as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 also requires the amortization of debt issuance costs to be reported as interest expense. ASU 2015-03 is effective for fiscal periods (including interim periods) beginning after December 15, 2015, with early adoption permitted. ASU 2015-03 must be applied retrospectively, where the balance sheet of each presented individual period is adjusted to indicate the period-specific impact of using the new guidance. In August 2015, the FASB issued ASU 2015-15, Interest — Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”), which states that an entity can defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company adopted ASU 2015-03, which resulted in the Company reclassifying approximately $34.7 million , as of December 31, 2014 , of deferred debt issuance costs from other noncurrent assets to long-term debt in the consolidated balance sheets. In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”). ASU 2015-02 amends the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 is effective for fiscal periods (including interim periods) beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2015-02 is not expected to have an impact on the Company’s consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in Accounting Standards Codification 605, Revenue Recognition . ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 was originally effective for fiscal periods (including interim periods) beginning after December 15, 2016. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date by one year, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Policies)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
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 expenses with the undiscounted estimated future cash flows over the terms of the related agreements or the period expected to be benefited. The costs of 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 undiscounted estimated future cash flows based upon assumed rates of annual customer attrition.

Derivatives (Policies)

Derivatives (Policies)	12 Months Ended
	Dec. 31, 2015
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. 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), natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. 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; • precious metals purchases: and • fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”). The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions. The changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in risk profiles. These changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise. The Company recognizes all derivative instruments at their fair values (see Note 9 ) as either current assets or current liabilities in 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 portions or all of its derivative instruments for hedge accounting. Derivative Instruments Designated as Cash Flow Hedges The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel swaps as cash flow hedges. The derivative instruments designated as cash flow hedges that are 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 cash flow 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 cash flow hedge. To the extent a derivative instrument designated as a cash flow 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. 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 cash flow hedge accounting. Ineffectiveness has resulted, and the loss of cash flow hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow 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. Cash flow 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 cash flow 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 deferred 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. Derivative Instruments Designated as Fair Value Hedges For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the consolidated statements of operations. No hedge ineffectiveness was recognized as the interest rate swap qualifies for the “shortcut” method and, as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items. Fair value 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 fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as effective fair value hedge, the derivative instrument is still subject to mark-to-market method of accounting, however the Company will cease to adjust the hedged asset or liability for changes in fair value. Derivative Instruments Not Designated as Hedges For derivative instruments not designated as hedges, 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 hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the consolidated statements of operations. 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. Additionally, the Company has entered into diesel crack spread collars, gasoline crack spread collars, natural gas collars, and certain other crude oil swaps, diesel swaps, gasoline swaps, natural gas swaps and platinum swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and gasoline and diesel sales at the Company’s Superior refinery.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurement, Policy	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. 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. The Company periodically evaluates the carrying value of long-lived assets to be held and used, including 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. 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. The estimated aggregate fair value of the Company’s senior notes defined as Level 1 was based upon quoted market prices in an active market. The estimated aggregate fair value of the Company’s senior notes classified as Level 2 was 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. All settlements from derivative instruments designated as cash flow hedges and deemed “effective” 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 settlements from derivative instruments designated as cash flow hedges are recorded in earnings in realized gain (loss) on derivative instruments in the consolidated statements of operations. All settlements from derivative instruments designated as fair value hedges are accrued and recorded as an adjustment to interest expense in the consolidated statements of operations. All settlements from derivative instruments not designated as hedges are recorded in realized gain (loss) on derivative instruments in the consolidated statements of operations. Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily 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. Pension Assets Pension assets are reported at fair value in the accompanying consolidated financial statements. At December 31, 2015 , the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of 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 NAV of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. Plan investments can be redeemed within a short time frame (10 or so business days), if requested. 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 Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date. 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 net of amounts internally generated and the market 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. 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. To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument, the Company uses discounted cash flows, which use observable inputs such as maturity and market interest rates. 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 creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the transaction 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.

Unit-Based Compensation (Polici

Unit-Based Compensation (Policies)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [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 December 10, 2015 (“LTIP”), for its employees, consultants and directors and its affiliates who perform services for the Company. The LTIP 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 3,883,960 common units may be delivered pursuant to awards under the LTIP. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP 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 LTIP as part of their director compensation package related to fiscal years 2013 and 2014 . 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. In addition, the recipients have DERs on these phantom units from the date of grant. For the years ended December 31, 2015 and 2014 , named executive officers and certain employees were awarded phantom units under the terms of the LTIP, 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 Informat32

Segments and Related Information (Policies)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Reporting, Policy	The accounting policies of the reporting segments are the same as those described in the summary of significant accounting policies as disclosed 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 accounts for intersegment sales and transfers at cost plus a specified mark-up. 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.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Allowance for Doubtful Accounts Activity	The activity in the allowance for doubtful accounts was as follows (in millions): December 31, 2015 2014 2013 Beginning balance $ 1.6 $ 1.2 $ 1.2 Provision 1.1 0.5 0.1 Write-offs, net (0.7 ) (0.1 ) (0.1 ) Ending balance $ 2.0 $ 1.6 $ 1.2
Inventories	Inventories consisted of the following (in millions): December 31, 2015 2014 Raw materials $ 47.9 $ 77.8 Work in process 64.0 75.4 Finished goods 272.5 360.3 $ 384.4 $ 513.5
Property, Plant and Equipment	Property, plant and equipment, including depreciable lives, consisted of the following (in millions): December 31, 2015 2014 Land $ 19.5 $ 18.3 Buildings and improvements (10 to 40 years) 70.2 66.8 Machinery and equipment (10 to 20 years) 1,629.7 1,420.7 Furniture and fixtures (5 to 10 years) 28.5 21.8 Assets under capital leases (4 to 26 years) 49.0 48.9 Construction-in-progress 466.4 354.0 2,263.3 1,930.5 Less accumulated depreciation (544.1 ) (466.1 ) $ 1,719.2 $ 1,464.4
Other Current Liabilities [Table Text Block]	Other current liabilities consisted of the following at December 31, 2015 and 2014 (in millions): December 31, 2015 2014 RINs Obligation $ 88.4 $ 16.3 Other 30.6 23.7 Total $ 119.0 $ 40.0

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Purchase price allocation	The allocations of the aggregate purchase prices to assets acquired and liabilities assumed for acquisitions are as follows (in millions): 2014 Acquisitions 2013 Acquisitions SOS Anchor United Petroleum Bel-Ray Crude Oil Logistics San Antonio Accounts receivable $ 11.6 $ 75.0 $ — $ 4.3 $ — $ — Inventories 2.7 61.2 0.2 11.1 — 17.0 Prepaid expenses and other current assets 0.1 0.4 — 0.6 0.1 — Deposits — 0.6 — — — — Deferred tax asset — 0.9 — — — — Property, plant and equipment, net 15.1 35.9 — 6.5 0.9 100.7 Investment in unconsolidated affiliates — 1.9 — — — — Goodwill 0.8 69.0 5.0 9.1 5.2 5.7 Other intangible assets, net 5.7 74.0 5.2 41.4 — — Other noncurrent assets, net — — — 0.3 — — Accounts payable (6.2 ) (44.2 ) — (3.9 ) — — Accrued salaries, wages and benefits — (18.2 ) — (1.3 ) — (0.1 ) Accrued income taxes payable — — — — — — Other taxes payable (0.2 ) (1.8 ) — (1.7 ) — — Other current liabilities — (0.4 ) — (0.8 ) — (5.4 ) Current portion of long-term debt — — — (11.9 ) — — Long-term debt — — — — — — Deferred income tax liability — (30.7 ) — — — — Other long-term liabilities — — — (0.1 ) — — Pension and postretirement benefit obligations — — — — — — Total purchase price, net of cash acquired $ 29.6 $ 223.6 $ 10.4 $ 53.6 $ 6.2 $ 117.9
Components of intangible asset	The components of intangible assets listed in the table above were as follows (in millions): SOS Anchor United Petroleum Bel-Ray August 1, 2014 March 31, 2014 February 28, 2014 December 10, 2013 Amount Life (Years) Amount Life (Years) Amount Life (Years) Amount Life (Years) Customer relationships $ 4.3 15 $ 52.7 20 $ 3.8 20 $ 28.6 30 Tradenames 1.4 20 18.4 21 1.4 20 4.2 18 Trade secrets — — — — — — 8.5 18 Non-competition agreements — — 2.9 2 — — 0.1 3 Totals $ 5.7 $ 74.0 $ 5.2 $ 41.4 Weighted average amortization period 16 20 20 26
Schedule of business acquisitions	The Company recorded the following goodwill (in millions): Amount Business Segment SOS Acquisition (1) $ 0.8 Oilfield Services Anchor Acquisition (1) (3) $ 69.0 Oilfield Services United Petroleum Acquisition (1) $ 5.0 Specialty Products 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 (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 and sales to third party customers. (3) Approximately $9.7 million of goodwill associated with the Anchor Acquisition is tax deductible due to Anchor’s tax status as a corporation on the acquisition date. In connection with the respective acquisitions, 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, 2015 , 2014 and 2013 (in millions): Year Ended December 31, 2015 2014 2013 SOS Acquisition $ — $ 0.1 $ — Anchor Acquisition $ — $ 0.6 $ — United Petroleum Acquisition $ — $ 0.1 $ — Bel-Ray Acquisition $ — $ 0.3 $ 0.4 Crude Oil Logistics Acquisition $ — $ — $ 0.2 San Antonio Acquisition $ — $ — $ 0.5 Montana Acquisition $ — $ — $ 0.1
Unaudited pro forma financial information	The following financial information reflects sales and operating income (loss) of the Anchor Acquisition that are included in the consolidated statements of operations (in millions): Year Ended December 31, 2015 2014 2013 Sales $ 259.8 $ 349.1 $ — Operating loss $ (74.5 ) $ (19.1 ) $ — Unaudited Pro Forma Financial Information The following unaudited pro forma financial information reflects the unaudited consolidated results of operations of the Company as if the Anchor Acquisition had taken place on January 1, 2014, (in millions, except for per unit data): Year Ended December 31, 2014 Sales $ 5,873.6 Net loss $ (124.6 ) Limited partners’ interest basic and diluted net loss per unit $ (1.97 )

Investment in Unconsolidated 35

Investment in Unconsolidated Affiliate Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The following table summarizes the Company’s investments in unconsolidated affiliates for the years ended of December 31, 2015 and 2014 (in millions): Year Ended December 31, 2015 Year Ended December 31, 2014 Investment Percent Ownership Investment Percent Ownership Dakota Prairie Refining, LLC $ 124.7 50 % $ 117.2 50 % Juniper GTL LLC — — % 18.5 23 % Other 1.3 1.6 Total $ 126.0 $ 137.3

Goodwill and Intangible Asset36

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Changes in goodwill balances are as follows (in millions): Specialty Fuel Oilfield Total Net balance as of December 31, 2013 $ 168.5 $ 38.5 $ — $ 207.0 Acquisitions (1) 5.0 — 69.8 74.8 Impairment (2) — — (36.0 ) (36.0 ) Net balance as of December 31, 2014 $ 173.5 $ 38.5 $ 33.8 $ 245.8 Impairment (2) — — (33.8 ) (33.8 ) Net balance as of December 31, 2015 $ 173.5 $ 38.5 $ — $ 212.0 (1) See Note 3 for discussion of the acquisitions completed during 2014. (2) Total accumulated goodwill impairment as of December 31, 2015 and 2014 , is $69.8 million and $36.0 million , respectively.
Schedule of Other Intangible Assets	Other intangible assets consist of the following (in millions): Weighted Average Life (Years) December 31, 2015 December 31, 2014 Gross Amount Accumulated Amortization Gross Amount Accumulated Amortization Customer relationships 21 $ 243.7 $ (97.5 ) $ 243.7 $ (68.4 ) Supplier agreements 4 21.5 (21.5 ) 21.5 (21.5 ) Tradenames 16 46.6 (10.7 ) 46.6 (4.9 ) Trade secrets 13 52.7 (23.4 ) 52.7 (16.7 ) Patents 12 1.6 (1.4 ) 1.6 (1.3 ) Non-competition agreements 4 8.8 (8.8 ) 8.8 (7.3 ) Distributor agreements 3 2.0 (2.0 ) 2.0 (2.0 ) Royalty agreements 19 4.5 (2.0 ) 4.5 (1.8 ) 18 $ 381.4 $ (167.3 ) $ 381.4 $ (123.9 )
Schedule of Estimated Future Amortization Expense	As of December 31, 2015 , the Company estimates that amortization of intangible assets for the next five years will be as follows (in millions): Year Amortization Amount 2016 $ 37.2 2017 $ 32.3 2018 $ 27.3 2019 $ 22.8 2020 $ 18.8

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Fiscal Year Maturity Schedule	As of December 31, 2015 , 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 2016 $ 42.8 2017 37.9 2018 33.3 2019 22.2 2020 16.9 Thereafter 27.0 Total $ 180.1
Purchase Commitment, Fiscal Year Maturity Schedule	As of December 31, 2015 , 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 2016 $ 493.6 2017 149.8 2018 87.6 2019 80.3 2020 — Thereafter — Total $ 811.3

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instrument [Line Items]
Summary of long-term debt	Long-term debt consisted of the following (in millions): December 31, December 31, Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rates of 3.3% and 2.6% at December 31, 2015 and 2014, respectively $ 111.0 $ 150.8 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.1% for each year ended December 31, 2015 and 2014 — 275.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rates of 6.8% and 6.7% for the year ended December 31, 2015 and 2014, respectively 900.0 900.0 Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 8.0% for each year ended December 31, 2015 and 2014 (1) 352.9 352.5 Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the year ended December 31, 2015 325.0 — Related party note payable, interest at a fixed rate of 6.0% on a portion of the note, interest payments at various dates, borrowings due July 2016, weighted average interest rate of 6% for the year ended December 31, 2015 73.5 — Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034 46.4 43.6 Less unamortized debt issuance costs (2) (28.9 ) (34.7 ) Less unamortized discounts (6.5 ) (8.4 ) Total long-term debt 1,773.4 1,678.8 Less current portion of note payable - related party 73.5 — Less current portion of long-term debt 1.7 0.6 $ 1,698.2 $ 1,678.2 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.9 million and $2.5 million as of December 31, 2015 and 2014 , respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge). (2) Deferred debt issuance costs 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 $8.1 million and $4.3 million at December 31, 2015 and 2014 , respectively.
Schedule of basis spread	As of December 31, 2015 , the margin was 75 basis points for prime and 175 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 Revolving Loans Margin on LIBOR Revolving Loans ≥ 66% 0.50% 1.50% ≥ 33% and < 66% 0.75% 1.75% < 33% 1.00% 2.00%
Summary of future minimum lease payments	As of December 31, 2015 , the Company had estimated minimum commitments for the payment of total rentals under capital leases as follows (in millions): Year Capital Leases 2016 $ 8.2 2017 7.9 2018 7.8 2019 7.4 2020 6.9 Thereafter 96.2 Total minimum lease payments 134.4 Less amount representing interest 88.0 Capital lease obligations 46.4 Less obligations due within one year 1.7 Long-term capital lease obligations $ 44.7
Maturities of long-term debt	As of December 31, 2015 , principal payments of debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2016 $ 76.7 2017 1.6 2018 1.5 2019 112.3 2020 0.9 Thereafter 1,614.4 Total $ 1,807.4
7.75% Notes
Debt Instrument [Line Items]
Summary of redemption price during the period	On and after April 15, 2018, the Company may on any one or more occasions redeem all or a part of the 2023 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest to the applicable redemption date on such 2023 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2018 105.813 % 2019 103.875 % 2020 101.938 % 2021 and thereafter 100.000 %
6.50% Notes
Debt Instrument [Line Items]
Summary of redemption price during the period	On and after April 15, 2017, the Company may on any one or more occasions redeem all or a part of the 2021 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 2021 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2017 103.250 % 2018 101.625 % 2019 and thereafter 100.000 %
7.625% 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 100.000 %

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Offsetting Assets	The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s consolidated balance sheets as of December 31, 2015 and 2014 (in millions): December 31, 2015 December 31, 2014 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 $ — $ — $ — $ — $ (10.0 ) $ (10.0 ) Gasoline swaps — — — 15.9 (4.4 ) 11.5 Swaps not allocated to a specific segment: Interest rate swaps — — — 2.5 — 2.5 Total derivative instruments designated as hedges — — — 18.4 (14.4 ) 4.0 Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps — — — — (7.2 ) (7.2 ) Natural gas collars — — — 0.1 (0.6 ) (0.5 ) Platinum swaps — — — — (0.1 ) (0.1 ) Fuel products segment: Crude oil swaps — — — 31.4 (111.2 ) (79.8 ) Crude oil basis swaps 0.4 (0.4 ) — 0.8 — 0.8 Crude oil percentage basis swaps 0.2 (0.2 ) — — (0.2 ) (0.2 ) Crude oil options 0.8 (0.8 ) — — — — Gasoline swaps — — — 2.4 (0.4 ) 2.0 Diesel swaps — — — 116.1 (19.1 ) 97.0 Diesel crack spread swaps — — — 4.5 — 4.5 Jet fuel swaps — — — 7.9 (5.2 ) 2.7 Total derivative instruments not designated as hedges 1.4 (1.4 ) — 163.2 (144.0 ) 19.2 Total derivative instruments $ 1.4 $ (1.4 ) $ — $ 181.6 $ (158.4 ) $ 23.2
Offsetting Liabilities	The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s consolidated balance sheets as of December 31, 2015 and 2014 (in millions): December 31, 2015 December 31, 2014 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 $ — $ — $ — $ (13.8 ) $ 10.0 $ (3.8 ) Gasoline swaps — — — — 4.4 4.4 Total derivative instruments designated as hedges — — — (13.8 ) 14.4 0.6 Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps (14.9 ) — (14.9 ) (12.1 ) 7.2 (4.9 ) Natural gas collars (0.9 ) — (0.9 ) (1.1 ) 0.6 (0.5 ) Platinum swaps — — — (0.1 ) 0.1 — Fuel products segment: Crude oil swaps (5.2 ) — (5.2 ) (102.4 ) 111.2 8.8 Crude oil basis swaps (0.7 ) 0.4 (0.3 ) — — — Crude oil percentage basis swaps (6.9 ) 0.2 (6.7 ) (0.2 ) 0.2 — Crude oil options (1.1 ) 0.8 (0.3 ) — — — Gasoline swaps — — — (1.0 ) 0.4 (0.6 ) Gasoline crack spread swaps (4.3 ) — (4.3 ) — — — Diesel swaps — — — (28.1 ) 19.1 (9.0 ) Jet fuel swaps — — — (5.2 ) 5.2 — Natural gas swaps (1.3 ) — (1.3 ) — — — Total derivative instruments not designated as hedges (35.3 ) 1.4 (33.9 ) (150.2 ) 144.0 (6.2 ) Total derivative instruments $ (35.3 ) $ 1.4 $ (33.9 ) $ (164.0 ) $ 158.4 $ (5.6 )
Derivative Instruments, Gain (Loss) by Hedging Relationship, by Income Statement Location, by Derivative Instrument Risk	The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2015 and 2014 related to its derivative instruments not designated as hedges (in millions): Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments Year Ended December 31, Year Ended December 31, Type of Derivative 2015 2014 2015 2014 Specialty products segment: Natural gas swaps $ (10.7 ) $ 1.1 $ (2.5 ) $ (11.9 ) Platinum swaps (0.8 ) — 0.1 (0.1 ) Fuel products segment: Crude oil swaps (67.6 ) (48.5 ) 52.0 (61.9 ) Crude oil basis swaps 1.1 5.7 (7.8 ) 0.1 Crude oil percentage basis swaps (3.2 ) — 0.2 — Crude oil options 6.1 — (0.3 ) — Gasoline swaps (20.0 ) (2.2 ) (0.7 ) 10.1 Gasoline crack spread swaps (5.5 ) — (4.3 ) — Gasoline crack spread collars — (0.4 ) — — Diesel swaps 82.3 76.3 (68.7 ) 71.5 Diesel crack spread swaps 24.3 (3.6 ) — 4.5 Diesel percentage basis crack spread swaps (0.1 ) — (4.5 ) — Diesel crack spread collars — 1.0 — (0.1 ) Jet fuel swaps 1.6 3.2 (1.6 ) 0.7 Jet fuel crack spread swaps — (0.1 ) — — Natural gas swaps — — (1.3 ) — Total $ 7.5 $ 32.5 $ (39.4 ) $ 12.9
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive gain at December 31, 2015 , will be reclassified to earnings by December 31, 2016, with balances being recognized as follows (in millions): Year Accumulated Other Comprehensive Income 2016 $ 6.4 Total $ 6.4
Specialty Product | Natural Gas Swap Contracts
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Natural Gas Swap Contracts At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 1,580,000 $ 4.24 Second Quarter 2016 1,380,000 $ 4.26 Third Quarter 2016 1,380,000 $ 4.26 Fourth Quarter 2016 1,540,000 $ 4.14 Calendar Year 2017 4,950,000 $ 3.85 Total 10,830,000 Average price $ 4.05 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2015 1,770,000 $ 4.09 Second Quarter 2015 1,500,000 $ 4.11 Third Quarter 2015 1,500,000 $ 4.11 Fourth Quarter 2015 1,900,000 $ 4.12 Calendar Year 2016 5,880,000 $ 4.22 Calendar Year 2017 1,830,000 $ 4.28 Total 14,380,000 Average price $ 4.18
Specialty Product | Natural Gas Collars
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Natural Gas Collars At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2016 180,000 $ 4.25 $ 3.89 Second Quarter 2016 180,000 $ 4.25 $ 3.89 Third Quarter 2016 180,000 $ 4.25 $ 3.89 Fourth Quarter 2016 60,000 $ 4.25 $ 3.89 Total 600,000 Average price $ 4.25 $ 3.89 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2015 240,000 $ 4.25 $ 3.79 Second Quarter 2015 240,000 $ 4.25 $ 3.79 Third Quarter 2015 240,000 $ 4.25 $ 3.79 Fourth Quarter 2015 200,000 $ 4.25 $ 3.85 Calendar Year 2016 600,000 $ 4.25 $ 3.89 Total 1,520,000 Average price $ 4.25 $ 3.84
Fuel Product | Natural Gas Swap Contracts
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Natural Gas Swap Contracts At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its fuel products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 603,000 $ 3.01 Second Quarter 2016 603,000 $ 2.99 Third Quarter 2016 606,000 $ 3.03 Fourth Quarter 2016 790,000 $ 3.02 Total 2,602,000 Average price $ 3.01
Fuel Product | Crude Oil Swaps
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Crude Oil Swap Contracts At December 31, 2015 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2016 29,120 320 $ 44.06 Second Quarter 2016 29,120 320 $ 44.06 Third Quarter 2016 29,440 320 $ 44.06 Fourth Quarter 2016 29,440 320 $ 44.06 Calendar Year 2017 630,720 1,728 $ 54.94 Total 747,840 Average price $ 53.24 At December 31, 2014 , 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 First Quarter 2015 315,000 3,500 $ 97.71 Total 315,000 Average price $ 97.71 At December 31, 2014 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 89.55 Second Quarter 2015 91,000 1,000 $ 89.89 Third Quarter 2015 386,400 4,200 $ 69.20 Fourth Quarter 2015 386,400 4,200 $ 69.20 Calendar Year 2016 972,828 2,658 $ 78.02 Total 3,510,628 Average price $ 81.89 At December 31, 2014 , the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 84.21 Total 1,674,000 Average price $ 84.21
Fuel Product | Crude Oil Basis Swaps
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Crude Oil Basis Swap Contracts The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between LLS and NYMEX WTI. At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 182,000 2,000 $ 2.40 Second Quarter 2016 182,000 2,000 $ 2.40 Third Quarter 2016 184,000 2,000 $ 2.40 Fourth Quarter 2016 184,000 2,000 $ 2.40 Total 732,000 Average differential $ 2.40 The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 91,000 1,000 $ (14.10 ) Second Quarter 2016 91,000 1,000 $ (14.10 ) Third Quarter 2016 92,000 1,000 $ (14.10 ) Fourth Quarter 2016 92,000 1,000 $ (14.10 ) Calendar Year 2017 365,000 1,000 $ (13.70 ) Total 731,000 Average differential $ (13.90 ) At December 31, 2014 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2015 118,000 2,000 $ (22.40 ) Total 118,000 Average differential $ (22.40 )
Fuel Product | Crude Oil Percent Basis Swaps [Member]
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Crude Oil Percentage Basis Swap Contracts The Company has entered into derivative instruments to secure a percentage differential on WCS crude oil to NYMEX WTI. At December 31, 2015 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl) First Quarter 2016 728,000 8,000 73.5 % Second Quarter 2016 728,000 8,000 73.5 % Third Quarter 2016 736,000 8,000 73.5 % Fourth Quarter 2016 736,000 8,000 73.5 % Calendar Year 2017 730,000 2,000 73.0 % Total 3,658,000 Average percentage 73.4 % At December 31, 2014 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI (Average % of WTI/ B bl) Third Quarter 2015 184,000 2,000 73.0 % Fourth Quarter 2015 184,000 2,000 73.0 % Total 368,000 Average percentage 73.0 %
Fuel Product | Crude Oil Options [Member]
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Crude Oil Option Contracts During 2015 , the Company entered into derivative instruments to mitigate the risk of future changes in the price of NYMEX WTI crude oil. At December 31, 2015 , the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Call ($/Bbl) Fourth Quarter 2016 350,000 11,290 $ 55.00 Total 350,000 Average price $ 55.00
Fuel Product | Gasoline Swap Contracts
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Gasoline Swap Contracts At December 31, 2014 , 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 ($/Bbl) First Quarter 2015 315,000 3,500 $ 109.68 Total 315,000 Average price $ 109.68 At December 31, 2014 , the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges: Gasoline Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 45,000 500 $ 78.12 Total 45,000 Average price $ 78.12 At December 31, 2014 , the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as hedges: Gasoline Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 45,000 500 $ 111.72 Total 45,000 Average price $ 111.72
Fuel Product | Gasoline Crack Spread Swaps [Member]
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Gasoline Crack Spread Swap Contracts At December 31, 2015 , the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges: Gasoline Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2016 873,000 9,593 $ 8.98 Total 873,000 Average price $ 8.98
Fuel Product | Diesel Swaps
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Diesel Swap Contracts At December 31, 2014 , the Company had the following derivatives related to diesel purchases in its fuel products segment, none of which are designated as hedges: Diesel Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap ($/Bbl) First Quarter 2015 1,449,000 16,100 $ 105.78 Total 1,449,000 Average price $ 105.78 At December 31, 2014 , the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges: Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2015 1,449,000 16,100 $ 116.27 Second Quarter 2015 91,000 1,000 $ 117.92 Third Quarter 2015 322,000 3,500 $ 95.04 Fourth Quarter 2015 322,000 3,500 $ 95.04 Calendar Year 2016 915,000 2,500 $ 104.32 Total 3,099,000 Average price $ 108.38
Fuel Product | Diesel Percent Basis Crack Spread Swaps [Member]
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Diesel Percentage Basis Crack Spread Swap Contracts The Company has entered into derivative instruments to secure a fixed percentage of gross profit on diesel in excess of the floating value of NYMEX WTI crude oil. At December 31, 2014 , the Company had the following diesel percentage basis crack spread swap contracts in its fuel products segment, none of which are designated as hedges: Diesel Percentage Basis Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average % of WTI/Bbl Third Quarter 2015 414,000 4,500 33.2 % Fourth Quarter 2015 414,000 4,500 33.2 % Calendar Year 2016 1,647,000 4,500 31.7 % Total 2,475,000 Average percentage 32.2 %
Fuel Product | Jet Fuel Swap Contracts
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Jet Fuel Swap Contracts At December 31, 2014 , the Company had the following derivatives related to jet fuel purchases 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 2015 180,000 2,000 $ 100.91 Total 180,000 Average price $ 100.91 At December 31, 2014 , the Company had the following derivatives related to jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges: Jet Fuel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 180,000 2,000 $ 115.65 Total 180,000 Average price $ 115.65
Commodity Contract [Member] | Designated as Hedging Instrument | Cash Flow Hedging [Member]
Derivative [Line Items]
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 comprehensive income (loss) and consolidated statements of partners’ capital as of, and for the years ended December 31, 2015 and 2014 , related to its derivative instruments that were designated as cash flow hedges (in millions): Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion) Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion) Year Ended December 31, Location of (Gain) Loss Year Ended December 31, Location of Gain (Loss) Year Ended December 31, Type of Derivative 2015 2014 2015 2014 2015 2014 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ 3.0 $ 1.8 Unrealized/Realized $ — $ — Fuel products segment: Crude oil swaps (5.6 ) (185.8 ) Cost of sales (170.3 ) 44.2 Unrealized/Realized (0.2 ) 4.8 Gasoline swaps 5.7 56.3 Sales 44.7 (1.4 ) Unrealized/Realized 0.7 (7.6 ) Diesel swaps (8.8 ) 220.0 Sales 121.6 (6.7 ) Unrealized/Realized — — Jet fuel swaps 1.4 23.7 Sales 13.1 (0.9 ) Unrealized/Realized — 0.6 Total $ (7.3 ) $ 114.2 $ 12.1 $ 37.0 $ 0.5 $ (2.2 )
Interest Rate Contract [Member] | Designated as Hedging Instrument | Fair Value Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) by Hedging Relationship, by Income Statement Location, by Derivative Instrument Risk	The Company recorded the following gains (losses) in its consolidated statements of operations for the years ended December 31, 2015 and 2014 related to its derivative instrument designated as a fair value hedge (in millions): Location of Gain of Derivative Amount of Gain Recognized in Net Loss Hedged Item Location of Loss on Hedged Item Amount of Loss Recognized in Net Loss Year Ended December 31, Year Ended December 31, 2015 2014 2015 2014 Swaps not allocated to a specific segment: Interest rate swap Interest expense $ 0.5 $ 2.5 2022 Notes Interest expense $ — $ (2.5 ) Total $ 0.5 $ 2.5 $ — $ (2.5 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Hierarchy of Recurring Fair Value Measurements	The Company’s recurring assets and liabilities measured at fair value at December 31, 2015 and 2014 were as follows (in millions): December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Crude oil swaps $ — $ — $ — $ — $ — $ — $ (89.8 ) $ (89.8 ) Crude oil basis swaps — — — — — — 0.8 0.8 Crude oil percentage basis swaps — — — — — — (0.2 ) (0.2 ) Gasoline swaps — — — — — — 13.5 13.5 Diesel swaps — — — — — — 97.0 97.0 Diesel crack spread swaps — — — — — — 4.5 4.5 Jet fuel swaps — — — — — — 2.7 2.7 Natural gas swaps — — — — — — (7.2 ) (7.2 ) Natural gas collars — — — — — — (0.5 ) (0.5 ) Platinum swaps — — — — — — (0.1 ) (0.1 ) Interest rate swaps — — — — — — 2.5 2.5 Total derivative assets — — — — — — 23.2 23.2 Pension plan investments 0.4 47.1 — 47.5 0.2 49.4 — 49.6 Total recurring assets at fair value $ 0.4 $ 47.1 $ — $ 47.5 $ 0.2 $ 49.4 $ 23.2 $ 72.8 Liabilities: Derivative liabilities: Crude oil swaps $ — $ — $ (5.2 ) $ (5.2 ) $ — $ — $ 5.0 $ 5.0 Crude oil basis swaps — — (0.3 ) (0.3 ) — — — — Crude oil percentage basis swaps — — (6.7 ) (6.7 ) — — — — Crude oil options — — (0.3 ) (0.3 ) — — — — Gasoline swaps — — — — — — 3.8 3.8 Gasoline crack spread swaps — — (4.3 ) (4.3 ) — — — — Diesel swaps — — — — — — (9.0 ) (9.0 ) Natural gas swaps — — (16.2 ) (16.2 ) — — (4.9 ) (4.9 ) Natural gas collars — — (0.9 ) (0.9 ) — — (0.5 ) (0.5 ) Total derivative liabilities — — (33.9 ) (33.9 ) — — (5.6 ) (5.6 ) RINs Obligation — (88.4 ) — (88.4 ) — (16.3 ) — (16.3 ) Liability Awards — — — — (4.7 ) — — (4.7 ) Total recurring liabilities at fair value $ — $ (88.4 ) $ (33.9 ) $ (122.3 ) $ (4.7 ) $ (16.3 ) $ (5.6 ) $ (26.6 )
Summary of Net Changes in Fair Value of the Company's Level 3 Financial Assets and Liabilities	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 years ended December 31, 2015 and 2014 (in millions): Derivative Instruments, Net For the Year Ended December 31, 2015 2014 Fair value at January 1, $ 17.6 $ (54.8 ) Realized gain on derivative instruments (8.1 ) (43.8 ) Unrealized loss on derivative instruments (39.5 ) (0.6 ) Interest income, net (0.5 ) (0.8 ) Change in fair value of cash flow hedges (7.3 ) 114.2 Settlements 3.9 3.4 Transfers in (out) of Level 3 — — Fair value at December 31, $ (33.9 ) $ 17.6 Total loss included in net loss attributable to changes in unrealized loss relating to financial assets and liabilities held as of December 31, $ (39.5 ) $ (0.6 )
Carrying and Estimated Fair Value of the Company's Financial Instruments, Carried at Adjusted Historical Cost, by Balance Sheet Grouping	The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at December 31, 2015 and 2014 , were as follows (in millions): December 31, 2015 December 31, 2014 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,095.8 $ 1,230.8 $ 630.0 $ 606.6 Senior notes 2 $ 294.1 $ 317.6 $ 803.3 $ 885.3 Revolving credit facility 3 $ 105.1 $ 105.1 $ 143.3 $ 143.3 Note payable - related party 3 $ 73.5 $ 73.5 $ — $ — Capital lease and other obligations 3 $ 46.4 $ 46.4 $ 43.6 $ 43.6

Partners' Capital Partner's Cap

Partners' Capital Partner's Capital (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Incentive Distributions	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 Distribution Per Common Unit Marginal Percentage 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 2015 , 2014 and 2013 , the Company completed the following marketed 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 January 8, 2013 5,750,000 (3) $ 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. April 1, 2013 6,037,500 (4) $ 37.50 $ 217.3 $ 4.6 $ 9.1 Net proceeds were used for general partnership purposes. March 13, 2015 6,000,000 $ 26.75 $ 153.9 $ 3.3 $ 6.4 Net proceeds were used to redeem a portion of the 2020 Notes and to repay borrowings under the revolving credit facility. (1) Proceeds are net of underwriting discounts, commissions and expenses but before the general partner’s capital contribution. (2) The Company’s general partner contributions were made to retain its 2% general partner interest. (3) 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. (4) Includes the full exercise of the overallotment option of 787,500 common units which closed on April 4, 2013.

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of the Company's nonvested phantom units	A summary of the Company’s non-vested phantom units as of December 31, 2015 , and the changes during the years ended December 31, 2015 , 2014 and 2013 , are presented below: Number of Phantom Units Weighted-Average Grant Date Fair Value Non-vested at January 1, 2013 835,927 $ 27.57 Granted 483,044 27.73 Vested (276,115 ) 24.22 Forfeited (354,600 ) 30.60 Non-vested at December 31, 2013 688,256 $ 23.70 Granted 477,527 25.97 Vested (280,263 ) 23.72 Forfeited (383,400 ) 25.59 Non-vested at December 31, 2014 502,120 $ 26.48 Granted 343,533 21.70 Vested (321,741 ) 23.54 Forfeited (103,188 ) 23.94 Non-vested at December 31, 2015 420,724 $ 24.27

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of Contribution Expenses	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, 2015 , 2014 and 2013 (in millions): Year Ended December 31, 2015 2014 2013 401(k) Plan matching contribution expense $ 5.9 $ 5.4 $ 4.1 Profit sharing expense $ — $ 1.2 $ 0.9
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, 2015 2014 Pension Plan Change in projected benefit obligation: Benefit obligation at beginning of year $ 69.3 $ 57.2 Service cost 0.5 0.4 Interest cost 2.6 2.6 Plan curtailment (0.9 ) — Benefits paid (2.6 ) (2.5 ) Actuarial (gain) loss (8.6 ) 11.7 Administrative expense — (0.1 ) Benefit obligation at end of year $ 60.3 $ 69.3 Change in plan assets: Fair value of plan assets at beginning of year $ 49.6 $ 45.8 Benefit payments (2.6 ) (2.5 ) Actual return on assets (1.0 ) 4.9 Administrative expense — (0.1 ) Employer contribution 1.5 1.5 Fair value of plan assets at end of year $ 47.5 $ 49.6 Funded status — benefit obligation in excess of plan assets $ (12.8 ) $ (19.7 ) Reconciliation of amounts recognized in the consolidated balance sheets: Accrued benefit obligation, long-term $ (12.8 ) $ (19.7 ) Unrecognized net actuarial loss 6.8 11.9 Accumulated other comprehensive loss 6.8 11.9 Net amount recognized at end of year $ (6.0 ) $ (7.8 )
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, 2015 2014 Accumulated benefit obligation $ 60.3 $ 68.4 Fair value of plan assets $ 47.5 $ 49.6
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, 2015 2014 Projected benefit obligation $ 60.3 $ 69.3 Fair value of plan assets $ 47.5 $ 49.6
Components of Net Periodic Pension Cost	The components of net periodic pension cost (income) for 2015 , 2014 and 2013 were as follows (in millions): Pension Plan Year Ended December 31, 2015 2014 2013 Service cost $ 0.5 $ 0.4 $ 0.4 Interest cost 2.6 2.6 2.4 Expected return on assets (3.3 ) (3.1 ) (2.9 ) Amortization of net loss 0.8 0.3 0.8 Curtailment gain recognized (0.9 ) — — Net periodic benefit cost (income) $ (0.3 ) $ 0.2 $ 0.7
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 for 2015 , 2014 and 2013 were as follows (in millions): Pension Plan Year Ended December 31, 2015 2014 2013 Changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net (gain) loss $ (4.3 ) $ 9.9 $ (8.8 ) Amounts recognized as a component of net periodic benefit cost: Amortization or settlement recognition of net loss (0.8 ) (0.3 ) (0.8 ) Total recognized in other comprehensive (income) loss $ (5.1 ) $ 9.6 $ (9.6 )
Schedule of Assumptions Used	The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2015 and 2014 , were as follows: Benefit Obligations Assumptions 2015 2014 Pension Plan: Discount rate for Penreco Pension Plan 4.30 % 3.92 % Discount rate for Superior Pension Plan 4.27 % 3.86 % Discount rate for Montana Pension Plan 4.21 % 4.13 % Rate of compensation increase for Montana Pension Plan N/A 3.00 % The significant weighted average assumptions used to determine the net periodic benefit cost (income) for the years ended December 31, 2015 , 2014 and 2013 were as follows: Net Periodic Benefit Cost (Income) Assumptions 2015 2014 2013 Pension Plan: Discount rate for Penreco Pension Plan 3.92 % 4.78 % 3.86 % Discount rate for Superior Pension Plan 3.86 % 4.66 % 3.75 % Discount rate for Montana Pension Plan 4.13 % 4.97 % 4.03 % Expected return on plan assets for Penreco Pension Plan (1) 6.75 % 6.75 % 6.75 % Expected return on plan assets for Superior Pension Plan (1) 6.75 % 6.75 % 6.75 % Expected return on plan assets for Montana Pension Plan (1) 6.75 % 6.75 % 6.75 % Rate of compensation increase for Montana Pension Plan 3.00 % 3.00 % 3.00 % (1) The Company considered the historical returns, the future expectation for returns for each asset class and fair value of the plan assets, 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.
Schedule of Allocation of Plan Assets	The Pension Plan’s target asset allocation is currently comprised of the following: Asset Class Range of Asset Allocation Target Allocation Domestic equities 15–25% 20% Foreign equities 15–25% 20% Fixed income 55–65% 60% The Company’s Pension Plan asset allocations, as of December 31, 2015 and 2014 , by asset category, are as follows: 2015 2014 Cash and cash equivalents 1 % — % Domestic equities 20 % 20 % Foreign equities 19 % 19 % Fixed income 60 % 61 % 100 % 100 %
Schedule of Pension Plan assets measured at fair value	The Company’s Pension Plan assets measured at fair value at December 31, 2015 and 2014 , were as follows (in millions): Fair Value of Pension Assets at December 31, 2015 2014 Level 1 Level 2 Level 1 Level 2 Cash and cash equivalents $ 0.4 $ — $ 0.2 $ — Domestic equities — 9.6 — 10.0 Foreign equities — 9.2 — 9.4 Fixed income — 28.3 — 30.0 $ 0.4 $ 47.1 $ 0.2 $ 49.4
Schedule of Expected Benefit Payments	The following benefit payments for the Pension Plan, which reflect expected future service, as appropriate, are expected to be paid in the years indicated as of December 31, 2015 (in millions): Pension Benefits 2016 $ 2.8 2017 3.0 2018 3.0 2019 3.1 2020 3.3 2021 to 2025 17.6 Total $ 32.8

Accumulated Other Comprehensi44

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The table below sets forth a summary of changes in accumulated other comprehensive income (loss) by component for the year ended December 31, 2015 and 2014 (in millions): Derivatives Defined Benefit Pension And Retiree Health Benefit Plans Foreign Currency Translation Adjustment Total Accumulated other comprehensive loss at December 31, 2013 $ (51.4 ) $ (1.9 ) $ (0.1 ) $ (53.4 ) Other comprehensive income (loss) before reclassifications 114.2 (9.9 ) (0.5 ) 103.8 Amounts reclassified from accumulated other comprehensive loss (37.0 ) 0.3 — (36.7 ) Net current period other comprehensive income (loss) 77.2 (9.6 ) (0.5 ) 67.1 Accumulated other comprehensive income (loss) at December 31, 2014 25.8 (11.5 ) (0.6 ) 13.7 Other comprehensive income (loss) before reclassifications (7.3 ) 4.3 (0.6 ) (3.6 ) Amounts reclassified from accumulated other comprehensive income (loss) (12.1 ) 0.4 — (11.7 ) Net current period other comprehensive income (loss) (19.4 ) 4.7 (0.6 ) (15.3 ) Accumulated other comprehensive income (loss) at December 31, 2015 $ 6.4 $ (6.8 ) $ (1.2 ) $ (1.6 )
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 income (loss) in the Company’s consolidated statements of operations for the years ended December 31, 2015 and 2014 , (in millions): Components of Accumulated Other Comprehensive Income (Loss) 2015 2014 Location of Gain (Loss) Derivative gains (losses) reflected in gross profit $ 179.4 $ (9.0 ) Sales (167.3 ) 46.0 Cost of sales $ 12.1 $ 37.0 Total Amortization of defined benefit pension benefit plans: Amortization of net loss $ (0.8 ) $ (0.3 ) (1) $ (0.8 ) $ (0.3 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 12 for additional information.

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	On December 31, 2015, ADF Holdings, Inc. converted to ADF Holdings, LLC and Anchor Drilling Fluids USA, Inc. converted to Anchor Drilling Fluids USA, LLC. Both ADF Holdings, LLC and Anchor Drilling Fluids USA, LLC have elected to be treated as pass-through entities for tax purposes. As a result, the activities of Anchor will be included in the earnings of the Company going forward and generally the Company will not be subject to federal and state income taxes. As of December 31, 2015 , 2014 and 2013 , the components of federal and state income tax expense are summarized as follows (in millions): December 31, 2015 2014 2013 Current expense: Federal $ 0.1 $ 0.2 $ — State — 0.2 0.4 Total $ 0.1 $ 0.4 $ 0.4 Deferred expense (benefit): Federal $ (26.5 ) $ (1.5 ) $ — State (2.0 ) 0.3 — Total $ (28.5 ) $ (1.2 ) $ — Total income tax expense (benefit) $ (28.4 ) $ (0.8 ) $ 0.4
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	A reconciliation of effective tax rate to the U.S. statutory rate attributable to operations for December 31, 2015 , 2014 and 2013 is as follows: December 31, 2015 2014 2013 Federal income tax rate 35.0 % 35.0 % 35.0 % Partnership earnings not subject to tax (13.8 )% (22.4 )% (35.0 )% State income taxes, net of federal income tax effect 0.6 % (0.4 )% 11.4 % State tax rate change 0.2 % — % — % Impact of non-deductible goodwill (5.0 )% (11.5 )% — % Anchor LLC conversions 0.3 % — % — % Other items, net (0.4 )% — % (1.1 )% Effective tax rate 16.9 % 0.7 % 10.3 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The table below summarizes the principal components of the deferred tax assets (liabilities) as follows as of December 31, 2015 and 2014 (in millions): December 31, 2015 2014 Deferred income tax assets: Inventory $ — $ 2.3 Net operating loss carryforwards 0.8 3.7 Total deferred income tax assets $ 0.8 $ 6.0 Deferred income tax liabilities: Intangible assets $ (0.1 ) $ (22.0 ) Unrealized gains (0.5 ) — Property, plant and equipment (2.0 ) (14.0 ) Total deferred income tax liabilities $ (2.6 ) $ (36.0 ) Net deferred income tax liability $ (1.8 ) $ (30.0 )

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 , 2014 and 2013 (in millions, except unit and per unit data): Year Ended December 31, 2015 2014 2013 Numerator for basic and diluted earnings per limited partner unit: Net income (loss) $ (139.4 ) $ (112.2 ) $ 3.5 Less: General partner’s interest in net income (loss) (2.8 ) (2.2 ) 0.1 General partner’s incentive distribution rights 16.8 15.4 14.7 Non-vested share based payments — — 0.2 Net loss available to limited partners $ (153.4 ) $ (125.4 ) $ (11.5 ) Denominator for basic and diluted earnings per limited partner unit: Basic weighted average limited partner units outstanding 74,896,096 69,671,827 67,938,784 Diluted weighted average limited partner units outstanding (1) 74,896,096 69,671,827 67,938,784 Limited partners’ interest basic and diluted net loss per unit $ (2.05 ) $ (1.80 ) $ (0.17 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.4 million , 0.2 million and 0.2 million potentially dilutive phantom units for the years ended December 31, 2015 , 2014 and 2013 , respectively.

Segments and Related Informat47

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Reportable segment information	Reportable segment information is as follows (in millions): Year Ended December 31, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,367.8 $ 2,562.5 $ 282.5 $ 4,212.8 $ — $ 4,212.8 Intersegment sales 3.9 39.1 — 43.0 (43.0 ) — Total sales $ 1,371.7 $ 2,601.6 $ 282.5 $ 4,255.8 $ (43.0 ) $ 4,212.8 Loss from unconsolidated affiliates $ — $ (61.1 ) $ (0.4 ) $ (61.5 ) $ — $ (61.5 ) Adjusted EBITDA $ 201.7 $ 81.9 $ (25.9 ) $ 257.7 $ — $ 257.7 Reconciling items to net loss: Depreciation and amortization 69.2 82.4 22.8 174.4 — 174.4 Realized loss on derivatives, not reflected in net loss or settled in a prior period (3.0 ) (7.0 ) — (10.0 ) — (10.0 ) Impairment charges — 24.3 33.8 58.1 — 58.1 Unrealized loss on derivatives 39.5 Interest expense 104.9 Debt extinguishment costs 46.6 Non-cash equity based compensation and other items 12.0 Income tax benefit (28.4 ) Net loss $ (139.4 ) Year Ended December 31, 2014 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,729.2 $ 3,693.4 $ 368.5 $ 5,791.1 $ — $ 5,791.1 Intersegment sales 18.4 89.8 — 108.2 (108.2 ) — Total sales $ 1,747.6 $ 3,783.2 $ 368.5 $ 5,899.3 $ (108.2 ) $ 5,791.1 Loss from unconsolidated affiliates $ — $ (3.2 ) $ (0.2 ) $ (3.4 ) $ — $ (3.4 ) Adjusted EBITDA $ 220.8 $ 50.0 $ 35.1 $ 305.9 $ — $ 305.9 Reconciling items to net loss: Depreciation and amortization 68.1 80.0 15.0 163.1 — 163.1 Realized gain (loss) on derivatives, not reflected in net loss or settled in a prior period (1.9 ) 8.5 — 6.6 — 6.6 Impairment charges — — 36.0 36.0 — 36.0 Unrealized loss on derivatives 0.6 Interest expense 110.8 Debt extinguishment costs 89.9 Non-cash equity based compensation and other items 11.9 Income tax benefit (0.8 ) Net loss $ (112.2 ) Year Ended December 31, 2013 Specialty Fuel Oilfield Services Combined Eliminations Consolidated Sales: External customers $ 1,774.9 $ 3,646.5 $ — $ 5,421.4 $ — $ 5,421.4 Intersegment sales — 77.3 — 77.3 (77.3 ) — Total sales $ 1,774.9 $ 3,723.8 $ — $ 5,498.7 $ (77.3 ) $ 5,421.4 Loss from unconsolidated affiliates $ — $ (0.3 ) $ — $ (0.3 ) $ — $ (0.3 ) Adjusted EBITDA $ 194.5 $ 47.0 $ — $ 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 or settled in a prior period (0.5 ) (1.3 ) — (1.8 ) — (1.8 ) Impairment charges 10.5 — — 10.5 — 10.5 Unrealized gain on derivatives (25.7 ) Interest expense 96.8 Debt extinguishment costs 14.6 Non-cash equity based compensation and other items 9.5 Income tax expense 0.4 Net income $ 3.5
Major product category sales	The following table sets forth the major product category sales (in millions): Year Ended December 31, 2015 2014 2013 Specialty products: Lubricating oils $ 575.6 13.7 % $ 748.4 12.9 % $ 848.8 15.7 % Solvents 302.0 7.2 % 485.2 8.4 % 511.7 9.4 % Waxes 136.9 3.2 % 144.1 2.5 % 141.0 2.6 % Packaged and synthetic specialty products 316.6 7.5 % 313.5 5.4 % 233.6 4.3 % Other 36.7 0.9 % 38.0 0.7 % 39.8 0.7 % Total 1,367.8 32.5 % 1,729.2 29.9 % 1,774.9 32.7 % Fuel products: Gasoline 1,047.1 24.9 % 1,443.1 24.9 % 1,409.4 26.0 % Diesel 894.8 21.2 % 1,197.4 20.7 % 1,259.2 23.3 % Jet fuel 149.6 3.6 % 199.3 3.4 % 191.4 3.5 % Asphalt, heavy fuel oils and other 471.0 11.1 % 853.6 14.7 % 786.5 14.5 % Total 2,562.5 60.8 % 3,693.4 63.7 % 3,646.5 67.3 % Oilfield services: Total 282.5 6.7 % 368.5 6.4 % — — % Consolidated sales $ 4,212.8 100.0 % $ 5,791.1 100.0 % $ 5,421.4 100.0 %

Quarterly Financial Data (Una48

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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 Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 2015 Sales $ 1,018.6 $ 1,156.2 $ 1,140.0 $ 898.0 $ 4,212.8 Gross profit 195.2 202.7 164.8 31.9 594.6 Net income (loss) 23.8 2.5 (48.9 ) (116.8 ) (139.4 ) Net income (loss) available to limited partners 19.1 (1.7 ) (52.2 ) (118.6 ) (153.4 ) Limited partners’ interest basic and diluted net income (loss) per unit $ 0.27 $ (0.02 ) $ (0.68 ) $ (1.56 ) $ (2.05 ) Weighted average limited partner units outstanding — basic 71,232,392 76,092,517 76,112,325 76,124,133 Weighted average limited partner units outstanding — diluted 71,275,452 76,092,517 76,112,325 76,124,133 First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 2014 Sales $ 1,341.0 $ 1,434.9 $ 1,675.8 $ 1,339.4 $ 5,791.1 Gross profit 124.8 99.0 182.6 123.3 529.7 Net income (loss) (49.8 ) (8.3 ) 9.4 (63.5 ) (112.2 ) Net income (loss) available to limited partners (52.6 ) (12.0 ) 5.4 (66.2 ) (125.4 ) Limited partners’ interest basic and diluted net income (loss) per unit $ (0.76 ) $ (0.17 ) $ 0.08 $ (0.95 ) $ (1.80 ) Weighted average limited partner units outstanding — basic 69,622,884 69,604,669 69,684,621 69,775,827 Weighted average limited partner units outstanding — diluted 69,622,884 69,604,669 69,850,685 69,775,827 (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) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Limited Partners
Organization, Consolidation and Presentation of Financial Statements
Limited Partners' Capital Account, Units Outstanding	75,884,400	69,452,233
Incentive distribution rights	98.00%
General Partner
Organization, Consolidation and Presentation of Financial Statements
Number of units	1,548,660
Incentive distribution rights	2.00%

Summary of Significant Accoun50

Summary of Significant Accounting Policies (A/R) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Activity in Allowance for Doubtful Accounts
Beginning balance	$ 1.6	$ 1.2	$ 1.2
Provisions	1.1	0.5	0.1
Write-offs, net	(0.7)	(0.1)	(0.1)
Ending balance	$ 2	$ 1.6	$ 1.2

Summary of Significant Accoun51

Summary of Significant Accounting Policies (Inventories) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Inventories
Raw materials	$ 47.9	$ 77.8
Work in process	64	75.4
Finished goods	272.5	360.3
Inventories total	$ 384.4	$ 513.5

Summary of Significant Accoun52

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Inventories Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
LIFO Inventory Related Text	last-in, first-out (“LIFO”)
Replacement costs	$ (41)	$ (18.9)
Consigned inventory	1.4	1.7
Effect of LIFO Inventory Liquidation on Income	(24.3)	(26.5)	$ 4.2
Lower of cost or market adjustments	$ (81.8)	$ (74.1)	$ 2.1

Summary of Significant Accoun53

Summary of Significant Accounting Policies (PPE) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	$ 2,263.3	$ 1,930.5
Less accumulated depreciation	(544.1)	(466.1)
Property, plant and equipment, net	1,719.2	1,464.4
Land
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	19.5	18.3
Building and improvements
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	$ 70.2	66.8
Building and improvements | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Building and improvements | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Machinery and equipment
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	$ 1,629.7	1,420.7
Machinery and equipment | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Machinery and equipment | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	20 years
Furniture and fixtures
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	$ 28.5	21.8
Furniture and fixtures | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years
Furniture and fixtures | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Assets under capital leases
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	$ 49	48.9
Less accumulated depreciation	$ (3.9)	(5.7)
Assets under capital leases | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	4 years
Assets under capital leases | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	26 years
Construction-in-progress
Property, Plant and Equipment, Net, by Type
Property, plant and equipment, gross	$ 466.4	$ 354

Summary of Significant Accoun54

Summary of Significant Accounting Policies (PPE Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Interest Costs
Interest Costs Incurred	$ 133.5	$ 122.8	$ 101.2
Interest Costs Capitalized in PPE	28.6	12	4.4
Depreciation [Abstract]
Depreciation	102	98.3	92
Capitalized Computer Software [Abstract]
Capitalized Computer Software, Gross	17.4	17.4
Capitalized Computer Software, Accumulated Amortization	13.1	8.9
Assets under capital leases
Depreciation [Abstract]
Depreciation	$ 2.6	0.8	0.7
Software developed or obtained
Depreciation [Abstract]
Property, Plant and Equipment, Useful Life	5 years
Capitalized Computer Software [Abstract]
Amortization	$ 4.2	$ 3.4	$ 3.3

Summary of Significant Accoun55

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Investment in Unconsolidated Affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Other than Temporary Impairment		$ 0	$ 0
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Other than Temporary Impairment	$ 24.3

Summary of Significant Accoun56

Summary of Significant Accounting Policies (Goodwill and Indefinite Lived Intangibles) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Goodwill [Line Items]
Reviews for goodwill impairment annually on		Oct. 1, 2015
Goodwill impairment losses		$ (33.8)	[1]	$ (36)	[1]	$ 0
Oilfield Services
Goodwill [Line Items]
Goodwill impairment losses	[1]	$ (33.8)		$ (36)
[1]	(2) Total accumulated goodwill impairment as of December 31, 2015 and 2014, is $69.8 million and $36.0 million, respectively.

Summary of Significant Accoun57

Summary of Significant Accounting Policies (Other Noncurrent Assets) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Capitalized major maintenance and repairs	$ 60.4	$ 70.1
Accumulated amortization, capitalized major maintenance and repairs	$ 71.6	$ 46.2

Summary of Significant Accoun58

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Other Current Liabilities) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
RINs Obligation	$ 88.4	$ 16.3
Other	30.6	23.7
Total	$ 119	$ 40

Summary of Significant Accoun59

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Impairment of Long-Lived Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Specialty Product
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ 0	$ 0	$ 10.5

Summary of Significant Accoun60

Summary of Significant Accounting Policies (Income Taxes) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Unrecognized Tax Benefits	$ 0	$ 0

Summary of Significant Accoun61

Summary of Significant Accounting Policies (Shipping and Handling Costs) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Shipping and handling costs	$ 175.5	$ 171.4	$ 142.7

Summary of Significant Accoun62

Summary of Significant Accounting Policies (Advertising Expenses) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Advertising expense	$ 14.2	$ 20.5	$ 14.6

Summary of Significant Accoun63

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (New Accounting Pronouncements) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015
Accounting Policies [Abstract]
Deferred Tax Assets, Net, Noncurrent	$ 2.3	$ 0
Amortization of Financing Costs	$ 34.7

Acquisitions (Purchase Price Al

Acquisitions (Purchase Price Allocation) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014	Aug. 01, 2014	Mar. 31, 2014	Feb. 28, 2014	Dec. 31, 2013	Dec. 10, 2013	Aug. 09, 2013	Jan. 02, 2013
Business Acquisition [Line Items]
Goodwill		$ 212	$ 245.8				$ 207
SOS Acquisition [Member]
Business Acquisition [Line Items]
Accounts receivable				$ 11.6
Inventories				2.7
Prepaid expenses and other current assets				0.1
Deposits				0
Deferred tax asset				0
Property, plant and equipment				15.1
Investment in unconsolidated affiliates				0
Goodwill	[1]			0.8
Other intangible assets				5.7
Other noncurrent assets, net				0
Accounts payable				(6.2)
Accrued salaries, wages and benefits				0
Accrued income taxes payable				0
Other taxes payable				(0.2)
Other current liabilities				0
Current portion of long-term debt				0
Long-term debt				0
Deferred income tax liability				0
Other long-term liabilities				0
Pension and postretirement benefit obligations				0
Total purchase price, net of cash acquired				$ 29.6
Anchor Acquisition [Member]
Business Acquisition [Line Items]
Accounts receivable					$ 75
Inventories					61.2
Prepaid expenses and other current assets					0.4
Deposits					0.6
Deferred tax asset					0.9
Property, plant and equipment					35.9
Investment in unconsolidated affiliates					1.9
Goodwill	[1],[2]				69
Other intangible assets					74
Other noncurrent assets, net					0
Accounts payable					(44.2)
Accrued salaries, wages and benefits					(18.2)
Accrued income taxes payable					0
Other taxes payable					(1.8)
Other current liabilities					(0.4)
Current portion of long-term debt					0
Long-term debt					0
Deferred income tax liability					(30.7)
Other long-term liabilities					0
Pension and postretirement benefit obligations					0
Total purchase price, net of cash acquired					$ 223.6
United Acquisition [Member]
Business Acquisition [Line Items]
Accounts receivable						$ 0
Inventories						0.2
Prepaid expenses and other current assets						0
Deposits						0
Deferred tax asset						0
Property, plant and equipment						0
Investment in unconsolidated affiliates						0
Goodwill	[1]					5
Other intangible assets						5.2
Other noncurrent assets, net						0
Accounts payable						0
Accrued salaries, wages and benefits						0
Accrued income taxes payable						0
Other taxes payable						0
Other current liabilities						0
Current portion of long-term debt						0
Long-term debt						0
Deferred income tax liability						0
Other long-term liabilities						0
Pension and postretirement benefit obligations						0
Total purchase price, net of cash acquired						$ 10.4
Bel-ray Acquisition
Business Acquisition [Line Items]
Accounts receivable								$ 4.3
Inventories								11.1
Prepaid expenses and other current assets								0.6
Deposits								0
Deferred tax asset								0
Property, plant and equipment								6.5
Investment in unconsolidated affiliates								0
Goodwill	[1]							9.1
Other intangible assets								41.4
Other noncurrent assets, net								0.3
Accounts payable								(3.9)
Accrued salaries, wages and benefits								(1.3)
Accrued income taxes payable								0
Other taxes payable								(1.7)
Other current liabilities								(0.8)
Current portion of long-term debt								(11.9)
Long-term debt								0
Deferred income tax liability								0
Other long-term liabilities								(0.1)
Pension and postretirement benefit obligations								0
Total purchase price, net of cash acquired								$ 53.6
Crude Oil Logistics Acquisition
Business Acquisition [Line Items]
Accounts receivable									$ 0
Inventories									0
Prepaid expenses and other current assets									0.1
Deposits									0
Deferred tax asset									0
Property, plant and equipment									0.9
Investment in unconsolidated affiliates									0
Goodwill	[3]								5.2
Other intangible assets									0
Other noncurrent assets, net									0
Accounts payable									0
Accrued salaries, wages and benefits									0
Accrued income taxes payable									0
Other taxes payable									0
Other current liabilities									0
Current portion of long-term debt									0
Long-term debt									0
Deferred income tax liability									0
Other long-term liabilities									0
Pension and postretirement benefit obligations									0
Total purchase price, net of cash acquired									$ 6.2
San Antonio Acquisition
Business Acquisition [Line Items]
Accounts receivable										$ 0
Inventories										17
Prepaid expenses and other current assets										0
Deposits										0
Deferred tax asset										0
Property, plant and equipment										100.7
Investment in unconsolidated affiliates										0
Goodwill	[1]									5.7
Other intangible assets										0
Other noncurrent assets, net										0
Accounts payable										0
Accrued salaries, wages and benefits										(0.1)
Accrued income taxes payable										0
Other taxes payable										0
Other current liabilities										(5.4)
Current portion of long-term debt										0
Long-term debt										0
Deferred income tax liability										0
Other long-term liabilities										0
Pension and postretirement benefit obligations										0
Total purchase price, net of cash acquired										$ 117.9
[1]	Goodwill recognized relates primarily to enhancing the Company’s strategic platform for expansion in the respective business segment noted above.
[2]	Approximately $9.7 million of goodwill associated with the Anchor Acquisition is tax deductible due to Anchor’s tax status as a corporation on the acquisition date.
[3]	Goodwill recognized relates primarily to enhancing the Company’s crude oil gathering operations to support the Superior refinery and sales to third party customers.

Acquisitions (Intangible Assets

Acquisitions (Intangible Assets) - USD ($) $ in Millions	Aug. 01, 2014	Mar. 31, 2014	Feb. 28, 2014	Dec. 10, 2013
SOS Acquisition [Member]
Component of intangible asset
Amount	$ 5.7
Life	16 years
SOS Acquisition [Member] | Customer relationships
Component of intangible asset
Amount	$ 4.3
Life	15 years
SOS Acquisition [Member] | Tradenames
Component of intangible asset
Amount	$ 1.4
Life	20 years
SOS Acquisition [Member] | Trade secrets
Component of intangible asset
Amount	$ 0
SOS Acquisition [Member] | Non-competition agreements
Component of intangible asset
Amount	$ 0
Anchor Acquisition [Member]
Component of intangible asset
Amount		$ 74
Life		20 years
Anchor Acquisition [Member] | Customer relationships
Component of intangible asset
Amount		$ 52.7
Life		20 years
Anchor Acquisition [Member] | Tradenames
Component of intangible asset
Amount		$ 18.4
Life		21 years
Anchor Acquisition [Member] | Trade secrets
Component of intangible asset
Amount		$ 0
Anchor Acquisition [Member] | Non-competition agreements
Component of intangible asset
Amount		$ 2.9
Life		2 years
United Acquisition [Member]
Component of intangible asset
Amount			$ 5.2
Life			20 years
United Acquisition [Member] | Customer relationships
Component of intangible asset
Amount			$ 3.8
Life			20 years
United Acquisition [Member] | Tradenames
Component of intangible asset
Amount			$ 1.4
Life			20 years
United Acquisition [Member] | Trade secrets
Component of intangible asset
Amount			$ 0
United Acquisition [Member] | Non-competition agreements
Component of intangible asset
Amount			$ 0
Bel-ray Acquisition
Component of intangible asset
Amount				$ 41.4
Life				26 years
Bel-ray Acquisition | Customer relationships
Component of intangible asset
Amount				$ 28.6
Life				30 years
Bel-ray Acquisition | Tradenames
Component of intangible asset
Amount				$ 4.2
Life				18 years
Bel-ray Acquisition | Trade secrets
Component of intangible asset
Amount				$ 8.5
Life				18 years
Bel-ray Acquisition | Non-competition agreements
Component of intangible asset
Amount				$ 0.1
Life				3 years

Acquisitions (Goodwill)

Acquisitions (Goodwill) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014	Aug. 01, 2014	Mar. 31, 2014	Feb. 28, 2014	Dec. 31, 2013	Dec. 10, 2013	Aug. 09, 2013	Jan. 02, 2013
Business Acquisition [Line Items]
Goodwill		$ 212	$ 245.8				$ 207
SOS Acquisition [Member]
Business Acquisition [Line Items]
Goodwill	[1]			$ 0.8
Anchor Acquisition [Member]
Business Acquisition [Line Items]
Goodwill	[1],[2]				$ 69
United Acquisition [Member]
Business Acquisition [Line Items]
Goodwill	[1]					$ 5
Bel-ray Acquisition
Business Acquisition [Line Items]
Goodwill	[1]							$ 9.1
Crude Oil Logistics Acquisition
Business Acquisition [Line Items]
Goodwill	[3]								$ 5.2
San Antonio Acquisition
Business Acquisition [Line Items]
Goodwill	[1]									$ 5.7
[1]	Goodwill recognized relates primarily to enhancing the Company’s strategic platform for expansion in the respective business segment noted above.
[2]	Approximately $9.7 million of goodwill associated with the Anchor Acquisition is tax deductible due to Anchor’s tax status as a corporation on the acquisition date.
[3]	Goodwill recognized relates primarily to enhancing the Company’s crude oil gathering operations to support the Superior refinery and sales to third party customers.

Acquisitions (Acquisition Expen

Acquisitions (Acquisition Expenses) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
SOS Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$ 0	$ 0.1	$ 0
Anchor Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	0	0.6	0
United Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	0	0.1	0
Bel-ray Acquisition
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	0	0.3	0.4
Crude Oil Logistics Acquisition
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	0	0	0.2
San Antonio Acquisition
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	0	0	0.5
Montana Refining Company, Inc. [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$ 0	$ 0	$ 0.1

Acquisitions (Results of Sales

Acquisitions (Results of Sales and Earnings) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Result of sales and operating income
Sales	$ 259.8	$ 349.1	$ 0
Operating income (loss)	$ (74.5)	(19.1)	$ 0
Business Acquisition, Pro Forma Information [Abstract]
Pro Forma Sales		5,873.6
Pro Forma Net income (loss)		$ (124.6)
Pro Forma Limited partners’ interest net income (loss) per unit — basic		$ (1.97)
Pro Forma Limited partners’ interest net income (loss) per unit — diluted		$ (1.97)

Acquisition (Textuals)

Acquisition (Textuals) $ in Millions	Mar. 30, 2014USD ($)	Nov. 26, 2013USD ($)	Jun. 29, 2012USD ($)	Dec. 31, 2015USD ($)	Aug. 01, 2014USD ($)	Mar. 31, 2014USD ($)	Feb. 28, 2014USD ($)	Dec. 10, 2013USD ($)	Aug. 09, 2013USD ($)D / bbl	Jan. 02, 2013USD ($)D / bbl
Business Acquisition [Line Items]
Business Acquisition, Percent Required to Pay in Post-Closing Transaction Tax Deductions				50.00%
SOS Acquisition [Member]
Business Acquisition [Line Items]
Total purchase price					$ 29.6
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent					$ 0
Anchor Acquisition [Member]
Business Acquisition [Line Items]
Total purchase price						$ 223.6
Business Acquisition, Post-Closing Transaction Tax Deductions				$ 1.1
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent						$ 30.7
United Acquisition [Member]
Business Acquisition [Line Items]
Total purchase price							$ 10.4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent							$ 0
Bel-ray Acquisition
Business Acquisition [Line Items]
Total purchase price								$ 53.6
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent								$ 0
Crude Oil Logistics Acquisition
Business Acquisition [Line Items]
Total purchase price									$ 6.2
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent									$ 0
Production capacity | D / bbl									10,000
San Antonio Acquisition
Business Acquisition [Line Items]
Total purchase price										$ 117.9
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent										$ 0
Production capacity | D / bbl										21,000
6.50% Notes
Business Acquisition [Line Items]
Proceeds from debt	$ 884
Maturity date	Apr. 15, 2021
7.625% Notes
Business Acquisition [Line Items]
Proceeds from debt		$ 337.4
Maturity date		Jan. 15, 2022
9.625% Notes
Business Acquisition [Line Items]
Proceeds from debt			$ 262.5
Maturity date			Aug. 1, 2020

Investment in Unconsolidated 70

Investment in Unconsolidated Affiliate Investment in Unconsolidated Affiliate (Schedule) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Jun. 09, 2014
Schedule of Equity Method Investments [Line Items]
Investment	$ 126		$ 137.3
Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investment	$ 124.7		$ 117.2
Percent Ownership	50.00%		50.00%
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investment	$ 0	$ 24.3	$ 18.5
Percent Ownership	0.00%		23.00%	23.00%
Other Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Investment	$ 1.3		$ 1.6
Percent Ownership

Investment in Unconsolidated 71

Investment in Unconsolidated Affiliate (Textuals) - USD ($)	Jun. 09, 2014	Feb. 07, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2015
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments			$ 58,600,000	$ 105,400,000	$ 31,800,000
Investment in unconsolidated affiliates			126,000,000	137,300,000
Equity Method Investment, Other than Temporary Impairment				0	$ 0
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Joint Venture, Ownership Percentage in Entity	100.00%
Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Notes Receivable Initial Available Amount			25,000,000
Due from Affiliates			0
Line of Credit Facility, Maximum Borrowing Capacity			75,000,000
Costs and Expenses, Related Party			200,000	$ 400,000
Payments to Acquire Equity Method Investments			$ 300,000,000
Equity Method Investment, Ownership Percentage			50.00%	50.00%
Investment in unconsolidated affiliates			$ 124,700,000	$ 117,200,000
Dakota Prairie Refining, LLC [Member] | Proceeds From Term Loan
Schedule of Equity Method Investments [Line Items]
Contribution amount funded		$ 75,000,000
Payments to Acquire Equity Method Investments			88,600,000
Dakota Prairie Refining, LLC [Member] | MDU Resources Group Inc [Member]
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments			$ 80,400,000
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Contribution amount funded	$ 25,000,000
Equity Method Investment, Ownership Percentage	23.00%		0.00%	23.00%
Investment in unconsolidated affiliates			$ 0	$ 18,500,000		$ 24,300,000
Equity Method Investment, Other than Temporary Impairment			24,300,000
Related Party Purchases [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Amounts of Transaction			2,600,000
Due to Related Parties			1,400,000
Related Party Sales [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Amounts of Transaction			4,600,000
Due from Related Parties			400,000
Related Party Shortfall [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Amounts of Transaction			1,100,000
Due to Related Parties			700,000
Related Party Subleases [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Amounts of Transaction			600,000	600,000
Due to Related Parties			0	500,000
Related Party Administrative Services [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Amounts of Transaction			400,000
Revolving Credit Facility [Member]
Schedule of Equity Method Investments [Line Items]
Letters of Credit Outstanding, Amount			66,800,000	$ 114,300,000
Revolving Credit Facility [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Letters of Credit Outstanding, Amount			$ 39,400,000

Goodwill and Intangible Asset72

Goodwill and Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Goodwill [Line Items]
Goodwill, Impaired, Accumulated Impairment Loss		$ (69.8)		$ (36)
Goodwill
Beginning Balance		245.8		207
Acquisitions (1)	[1]			74.8
Impairment (2)		(33.8)	[2]	(36)	[2]	$ 0
Ending Balance		212		245.8		207
Specialty Product
Goodwill
Beginning Balance		173.5		168.5
Acquisitions (1)	[1]			5
Impairment (2)	[2]	0		0
Ending Balance		173.5		173.5		168.5
Fuel Product
Goodwill
Beginning Balance		38.5		38.5
Acquisitions (1)	[1]			0
Impairment (2)	[2]	0		0
Ending Balance		38.5		38.5		38.5
Oilfield Services
Goodwill
Beginning Balance		33.8		0
Acquisitions (1)	[1]			69.8
Impairment (2)	[2]	(33.8)		(36)
Ending Balance		$ 0		$ 33.8		$ 0
[1]	(1) See Note 3 for discussion of the acquisitions completed during 2014.
[2]	(2) Total accumulated goodwill impairment as of December 31, 2015 and 2014, is $69.8 million and $36.0 million, respectively.

Goodwill and Intangible Asset73

Goodwill and Intangible Assets (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Life	18 years
Gross Amount	$ 381.4	$ 381.4
Accumulated Amortization	$ (167.3)	(123.9)
Customer relationships
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Life	21 years
Gross Amount	$ 243.7	243.7
Accumulated Amortization	$ (97.5)	(68.4)
Supplier agreements
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Acquired Finite-Lived Intangible Assets, 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]
Acquired Finite-Lived Intangible Assets, Weighted Average Life	16 years
Gross Amount	$ 46.6	46.6
Accumulated Amortization	$ (10.7)	(4.9)
Trade secrets
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Life	13 years
Gross Amount	$ 52.7	52.7
Accumulated Amortization	$ (23.4)	(16.7)
Patents
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Life	12 years
Gross Amount	$ 1.6	1.6
Accumulated Amortization	$ (1.4)	(1.3)
Non-competition agreements
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Life	4 years
Gross Amount	$ 8.8	8.8
Accumulated Amortization	$ (8.8)	(7.3)
Distributor agreements
Schedule of Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Acquired Finite-Lived Intangible Assets, 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]
Acquired Finite-Lived Intangible Assets, Weighted Average Life	19 years
Gross Amount	$ 4.5	4.5
Accumulated Amortization	$ (2)	$ (1.8)

Goodwill and Intangible Asset74

Goodwill and Intangible Assets (Details 2) $ in Millions	Dec. 31, 2015USD ($)
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
2,016	$ 37.2
2,017	32.3
2,018	27.3
2,019	22.8
2,020	$ 18.8

Goodwill and Intangibles (Detai

Goodwill and Intangibles (Details Textual) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Impairment (2)		$ (33.8)	[1]	$ (36)	[1]	$ 0
Fair Value Inputs, Discount Rate		15.50%
Amortization of Intangible Assets		$ 43.4		40.3		$ 25.6
For Year of 2015 [Member] | Maximum
Finite-Lived Intangible Assets [Line Items]
Fair Value Inputs, Long-term Revenue Growth Rate		(17.00%)
For Year of 2016 and Beyond [Member] | Maximum
Finite-Lived Intangible Assets [Line Items]
Fair Value Inputs, Long-term Revenue Growth Rate		18.00%
For Year of 2016 and Beyond [Member] | Minimum
Finite-Lived Intangible Assets [Line Items]
Fair Value Inputs, Long-term Revenue Growth Rate		(3.00%)
Oilfield Services
Finite-Lived Intangible Assets [Line Items]
Impairment (2)	[1]	$ (33.8)		$ (36)
[1]	(2) Total accumulated goodwill impairment as of December 31, 2015 and 2014, is $69.8 million and $36.0 million, respectively.

Commitments and Contingencies76

Commitments and Contingencies (Operating Leases) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Operating leases, rent expense	$ 67.8	$ 59.9	$ 35.3
Operating Leases, Future Minimum Commitments
2,016	42.8
2,017	37.9
2,018	33.3
2,019	22.2
2,020	16.9
Thereafter	27
Total	$ 180.1

Commitments and Contingencies77

Commitments and Contingencies (Crude Oil Supply, Other Feedstocks and Finished Products) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)D / bblbbl / d
Purchase Obligation, Future Minimum Commitments
2,016	$ 493.6
2,017	149.8
2,018	87.6
2,019	80.3
2,020	0
Thereafter	0
Total	$ 811.3
BP Purchase Agreement
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Initial term	1 year
Automatic renewal term	1 year
Termination notice	90 days
BP Purchase Agreement | Minimum
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Daily required commitment | D / bbl	35,000
BP Purchase Agreement | Maximum
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Daily required commitment | D / bbl	45,000
Limited interest in collateral pledged	$ 100
Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Annual purchase amount	$ 87.5
LVT Feedstock Agreement
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Initial term	10 years
Annual purchase amount	$ 27.5
Naphthenic Lubricating Oils | Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Daily required commitment | bbl / d	3,100
White Mineral Oil | Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Daily required commitment | bbl / d	600

Commitments and Contingencies78

Commitments and Contingencies (Environmental) - USD ($) $ in Millions	Jun. 29, 2012	Dec. 31, 2015	Dec. 31, 2014
Montana
Loss Contingencies [Line Items]
Environmental remediation expense		$ 17.6
WDNR-Superior
Loss Contingencies [Line Items]
Environmental remediation expense		0	$ 0.7
Estimates costs of equipment upgrades and conduct other discrete		4
EPA
Loss Contingencies [Line Items]
Payments for Environmental Liabilities	$ 0.1
LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		$ 6.8	$ 0.6
Environmental settlement		Dec. 23, 2010
Settlement agreement with the LDEQ		Jan. 31, 2012
LDEQ-Shreveport, Cotton Valley & Princeton [Member] | Minimum
Loss Contingencies [Line Items]
Environmental remediation expense		$ 3
LDEQ-Shreveport, Cotton Valley & Princeton [Member] | Maximum
Loss Contingencies [Line Items]
Environmental remediation expense		5
Shreveport
Loss Contingencies [Line Items]
Specified environmental liabilities first		5
Weston Agreement Trust		0.8
Shreveport | Maximum
Loss Contingencies [Line Items]
Specified environmental liabilities first required to contribute up to		1
Capital Expenditure [Member] | Montana
Loss Contingencies [Line Items]
Environmental remediation expense		14.4
Expense [Member] | Montana
Loss Contingencies [Line Items]
Environmental remediation expense		$ 3.2

Commitments and Contingencies79

Commitments and Contingencies (OSHA) - Occupational Safety and Health Administration - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 14, 2011
Loss Contingencies [Line Items]
Environmental remediation expense	$ 0.6	$ 1.1
Notification of penalty			Mar. 14, 2011
Proposed penalty				$ 0.2
Maximum
Loss Contingencies [Line Items]
Expected environmental capital expenditures	$ 1.4

Commitments and Contingencies80

Commitments and Contingencies (Labor Matters) - employee	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk [Line Items]
Number of employees	2,175
Number of Employees Concentration Risk, Percentage	52.20%	45.90%	54.10%
Labor Force Concentration Risk | Workforce Subject to Collective Bargaining Arrangements
Concentration Risk [Line Items]
Number of employees	613
Number of Employees Concentration Risk, Percentage	28.00%
Labor Force Concentration Risk | Workforce Subject to Collective Bargaining Arrangements Expiring within One Year
Concentration Risk [Line Items]
Number of employees	241
Number of Employees Concentration Risk, Percentage	11.00%

Commitments and Contingencies81

Commitments and Contingencies (Standby Letters of Credit) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Revolving Credit Facility [Member]
Loss Contingencies [Line Items]
Letters of credit outstanding amount	$ 66.8	$ 114.3
Maximum | Revolving Credit Facility [Member]
Debt Disclosure [Abstract]
Letter of credit sublimit	$ 600
Letter of credit sublimit percentage	90.00%
Revolving Credit Facility [Member]
Loss Contingencies [Line Items]
Letter of Credit Availability	$ 233.5	$ 310.8
Debt Disclosure [Abstract]
Senior secured revolving credit facility	$ 1,000

Long-Term Debt (Long Term Debt)

Long-Term Debt (Long Term Debt) - USD ($) $ in Millions		Jan. 13, 2015	Dec. 31, 2015	Dec. 31, 2014
Summary of Long-term debt
Less unamortized debt issuance costs			$ (28.9)	$ (34.7)
Total long-term debt			1,773.4	1,678.8
Notes Payable, Related Parties, Current			73.5	0
Less current portion of long-term debt			1.7	0.6
Long-term Debt, Excluding Current Maturities			$ 1,698.2	$ 1,678.2
Senior Notes [Abstract]
Lease Expiration Date			Oct. 31, 2034
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate			3.30%	2.60%
Summary of Long-term debt
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rates of 3.3% and 2.6% at December 31, 2015 and 2014, respectively			$ 111	$ 150.8
9.625% Notes
Debt Instrument [Line Items]
Stated Interest Rate Percentage			9.625%	9.625%
Summary of Long-term debt
Borrowings under Senior Notes			$ 0	$ 275
Senior Notes [Abstract]
Effective Interest Rate Percentage			10.10%	10.10%
6.50% Notes
Debt Instrument [Line Items]
Stated Interest Rate Percentage			6.50%	6.50%
Summary of Long-term debt
Borrowings under Senior Notes			$ 900	$ 900
Senior Notes [Abstract]
Effective Interest Rate Percentage			6.80%	6.70%
Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 8.0% for each year ended December 31, 2015 and 2014 (1)
Debt Instrument [Line Items]
Stated Interest Rate Percentage			7.625%	7.625%
Summary of Long-term debt
Borrowings under Senior Notes	[1]		$ 352.9	$ 352.5
Senior Notes [Abstract]
Effective Interest Rate Percentage			8.00%	8.00%
7.75% Notes
Debt Instrument [Line Items]
Stated Interest Rate Percentage			7.75%	7.75%
Summary of Long-term debt
Borrowings under Senior Notes			$ 325	$ 0
Senior Notes [Abstract]
Effective Interest Rate Percentage			8.00%	8.00%
Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034
Summary of Long-term debt
Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034			$ 46.4	$ 43.6
Less unamortized discounts
Summary of Long-term debt
Less unamortized discounts			$ (6.5)	(8.4)
The Heritage Group [Member]
Debt Instrument [Line Items]
Stated Interest Rate Percentage			6.00%
Senior Notes [Abstract]
Effective Interest Rate Percentage			6.00%
Fair Value Hedging [Member] | Interest Expense [Member]
Senior Notes [Abstract]
Liabilities, Fair Value Adjustment			$ 2.9	2.5
Designated as Hedging Instrument | Interest Rate Swap [Member] | Fair Value Hedging [Member] | Interest Expense [Member]
Senior Notes [Abstract]
Liabilities, Fair Value Adjustment		$ 3.3	0	$ (2.5)
Uncommitted prepayment [Member]
Summary of Long-term debt
Notes Payable, Related Parties			$ 27
[1]	(1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.9 million and $2.5 million as of December 31, 2015 and 2014, respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge).

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (2023 Notes) - 7.75% Notes	Mar. 27, 2015
April 15, 2018 through April 14, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	105.813%
April 15, 2019 through April 14, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	103.875%
April 15, 2020 through April 14, 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	101.938%
April 15, 2021 & Thereafter [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%

Long-Term Debt Long-Term Debt84

Long-Term Debt Long-Term Debt (2021 Notes) - 6.50% Notes	Mar. 30, 2014
April 15, 2017 through April 14, 2018 [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption Price, Percentage	103.25%
April 15, 2018 through April 14, 2019 [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption Price, Percentage	101.625%
April 15, 2019 & Thereafter [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%

Long-Term Debt Long-Term Debt85

Long-Term Debt Long-Term Debt (2022 Notes) - 7.625% Notes	Nov. 26, 2013
January 15, 2018 through January 14, 2019 [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption Price, Percentage	103.813%
January 15, 2019 through January 14, 2020 [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption Price, Percentage	101.906%
After January 15, 2020 [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%

Long-Term Debt (Revolver)

Long-Term Debt (Revolver) - Revolving Credit Facility [Member]	12 Months Ended
	Dec. 31, 2015
Prime | Greater than 66%
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Prime | Between 33% and 66%
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
Prime | Less than 33%
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Libor | Greater than 66%
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Libor | Between 33% and 66%
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Libor | Less than 33%
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%

Long-Term Debt Long-Term Debt87

Long-Term Debt Long-Term Debt (Capital Leases) $ in Millions	Dec. 31, 2015USD ($)
Capital Leased Assets [Line Items]
2,016	$ 8.2
2,017	7.9
2,018	7.8
2,019	7.4
2,020	6.9
Thereafter	96.2
Total minimum lease payments	134.4
Less amount representing interest	88
Capital lease obligations	46.4
Less obligations due within one year	1.7
Long-term capital lease obligations	$ 44.7

Long-Term Debt (Maturities of L

Long-Term Debt (Maturities of Long-Term Debt) $ in Millions	Dec. 31, 2015USD ($)
Maturities of long-term debt
2,016	$ 76.7
2,017	1.6
2,018	1.5
2,019	112.3
2,020	0.9
Thereafter	1,614.4
Total	$ 1,807.4

Long-Term Debt (Details Textual

Long-Term Debt (Details Textual)

Apr. 28, 2015USD ($)

Apr. 27, 2015USD ($)

Mar. 27, 2015USD ($)

Mar. 13, 2015shares

Jan. 13, 2015USD ($)

Mar. 30, 2014USD ($)

Nov. 26, 2013USD ($)

Apr. 02, 2013shares

[1]

Jan. 08, 2013shares

[2]

Jun. 29, 2012USD ($)

Dec. 31, 2015USD ($)bblshares

Dec. 31, 2014USD ($)shares

Dec. 31, 2013USD ($)

Long Term Debt Textual [Abstract]

Accumulated amortization, deferred debt issuance costs

$ 8,100,000

$ 4,300,000

Partners' Capital Account, Units, Sold in Public Offering | shares

6,000,000

6,037,500

5,750,000

432,167

134,955

Repayments of borrowings — senior notes

$ (275,000,000)

$ (500,000,000)

$ (100,000,000)

Gains (Losses) on Extinguishment of Debt

(46,600,000)

(89,900,000)

$ (14,600,000)

Imputed Interest

1,500,000

Property, plant and equipment, gross

2,263,300,000

1,930,500,000

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

$ 544,100,000

466,100,000

TexStar pipeline capacity | bbl

30,000

TexStar contract period

20 years

TexStar Capital Lease Obligation

$ 39,400,000

39,300,000

TexStar Depreciation

$ 2,000,000

$ 300,000

Minimum

Long Term Debt Textual [Abstract]

TexStar KNPS Expected Delivery Capacity | bbl

12,000

7.75% Notes

Long Term Debt Textual [Abstract]

Senior Notes, Issuance Date

Mar. 27, 2015

Senior Notes Issued, Gross

$ 325,000,000

Maturity date

Apr. 15, 2023

Debt Instrument Percentage of Discount Price

99.257%

Proceeds from debt

$ 317,000,000

Interest and principal payments of debt instruments

semiannually

Redemption Percentage

35.00%

Redemption Price

107.75%

Minimum Percentage of Senior Notes Outstanding After Redemption Date

65.00%

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

180 days

Stated Interest Rate Percentage

7.75%

7.75%

6.50% Notes

Long Term Debt Textual [Abstract]

Senior Notes, Issuance Date

Mar. 31, 2014

Senior Notes Issued, Gross

$ 900,000,000

Maturity date

Apr. 15, 2021

Debt Instrument Percentage of Discount Price

100.00%

100.00%

Proceeds from debt

$ 884,000,000

Interest and principal payments of debt instruments

semiannually

Redemption Percentage

35.00%

Redemption Price

106.50%

Minimum Percentage of Senior Notes Outstanding After Redemption Date

65.00%

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

180 days

Stated Interest Rate Percentage

6.50%

6.50%

9.375% Notes

Long Term Debt Textual [Abstract]

Extinguishment of Debt, Amount

$ 500,000,000

7.625% Notes

Long Term Debt Textual [Abstract]

Senior Notes, Issuance Date

Nov. 26, 2013

Senior Notes Issued, Gross

$ 350,000,000

Maturity date

Jan. 15, 2022

Debt Instrument Percentage of Discount Price

98.494%

Proceeds from debt

$ 337,400,000

Interest and principal payments of debt instruments

semiannually

Redemption Percentage

35.00%

Redemption Price

107.625%

Minimum Percentage of Senior Notes Outstanding After Redemption Date

65.00%

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

180 days

Stated Interest Rate Percentage

7.625%

7.625%

9.625% Notes

Long Term Debt Textual [Abstract]

Senior Notes, Issuance Date

Jun. 29, 2012

Senior Notes Issued, Gross

$ 275,000,000

Maturity date

Aug. 1, 2020

Debt Instrument Percentage of Discount Price

98.25%

Proceeds from debt

$ 262,500,000

Extinguishment of Debt, Amount

$ 178,800,000

$ 96,200,000

Stated Interest Rate Percentage

9.625%

9.625%

Revolving Credit Facility [Member]

Long Term Debt Textual [Abstract]

Maturity date

Jul. 14, 2019

Interest and principal payments of debt instruments

quarterly

Senior secured revolving credit facility

$ 1,000,000,000

Incremental Uncommitted Expansion Feature

$ 500,000,000

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

0.125%

Line of Credit Facility, Current Borrowing Capacity

$ 411,300,000

Line of Credit Facility, Amount Outstanding

111,000,000

$ 150,800,000

Available for additional borrowings based on specified availability limitations

$ 233,500,000

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

greater of (a) 12.5% of the Borrowing Base (as defined in the revolving credit agreement) then in effect and (b) $45.0 million, 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

Revolving Credit Facility [Member] | Maximum

Long Term Debt Textual [Abstract]

Unutilized commitments fee to the lender under the revolving credit facility

0.375%

Revolving Credit Facility [Member] | Minimum

Long Term Debt Textual [Abstract]

Unutilized commitments fee to the lender under the revolving credit facility

0.25%

Senior Notes [Member]

Long Term Debt Textual [Abstract]

Gains (Losses) on Extinguishment of Debt

$ 46,600,000

Senior Notes [Member] | Maximum

Long Term Debt Textual [Abstract]

Fixed charge coverage ratio

1.9

The Heritage Group [Member]

Long Term Debt Textual [Abstract]

Debt Instrument, Periodic Payment, Principal

$ 15,000,000

Stated Interest Rate Percentage

6.00%

Prime Rate | Revolving Credit Facility [Member]

Long Term Debt Textual [Abstract]

Debt Instrument, Basis Spread on Variable Rate

75.00%

London Interbank Offered Rate (LIBOR) | Revolving Credit Facility [Member]

Long Term Debt Textual [Abstract]

Debt Instrument, Basis Spread on Variable Rate

175.00%

Fair Value Hedging [Member] | Interest Expense [Member]

Long Term Debt Textual [Abstract]

Liabilities, Fair Value Adjustment

$ 2,900,000

2,500,000

Interest Rate Swap [Member] | Designated as Hedging Instrument | Fair Value Hedging [Member] | Interest Expense [Member]

Long Term Debt Textual [Abstract]

Liabilities, Fair Value Adjustment

$ 3,300,000

0

(2,500,000)

Assets under capital leases

Long Term Debt Textual [Abstract]

Property, plant and equipment, gross

49,000,000

48,900,000

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

3,900,000

$ 5,700,000

Uncommitted prepayment [Member]

Long Term Debt Textual [Abstract]

Notes Payable, Related Parties

27,000,000

Unsecured note payable [Member]

Long Term Debt Textual [Abstract]

Notes Payable, Related Parties

$ 48,000,000

[1]

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

[2]

(3) 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.

Derivatives (Offsetting Derivat

Derivatives (Offsetting Derivative Assets) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 1.4	$ 181.6
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(1.4)	(158.4)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	23.2
Designated as Hedging Instrument
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	18.4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(14.4)
Derivative Asset	0	4
Not Designated as Hedging Instrument
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.4	163.2
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(1.4)	(144)
Derivative Asset	0	19.2
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	31.4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(111.2)
Derivative Asset	0	(79.8)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Basis Swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0.4	0.8
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(0.4)	0
Derivative Asset	0	0.8
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Percent Basis Swaps [Member]
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0.2	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(0.2)	(0.2)
Derivative Asset	0	(0.2)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Options [Member]
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0.8	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(0.8)	0
Derivative Asset	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Gasoline swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	2.4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(0.4)
Derivative Asset	0	2
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Diesel Swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	116.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(19.1)
Derivative Asset	0	97
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Diesel Crack Spread Swaps [Member]
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	4.5
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Asset	0	4.5
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Jet Fuel Swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	7.9
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(5.2)
Derivative Asset	0	2.7
Commodity Contract [Member] | Not Designated as Hedging Instrument | Specialty Product | Platinum Swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(0.1)
Derivative Asset	0	(0.1)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Specialty Product | Natural Gas Swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(7.2)
Derivative Asset	0	(7.2)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Specialty Product | Natural Gas Collars
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(0.6)
Derivative Asset	0	(0.5)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Designated as Hedging Instrument | Fuel Product | Crude Oil Swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(10)
Derivative Asset	0	(10)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Designated as Hedging Instrument | Fuel Product | Gasoline swaps
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	15.9
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(4.4)
Derivative Asset	0	11.5
Fair Value Hedging [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument | Fuel Product | Interest Rate Swap [Member]
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	2.5
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Asset	$ 0	$ 2.5

Derivatives (Offsetting Deriv91

Derivatives (Offsetting Derivative Liabilities) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (35.3)	$ (164)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	1.4	158.4
Derivative Liability	(33.9)	(5.6)
Designated as Hedging Instrument
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(13.8)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	14.4
Derivative Liability	0	0.6
Not Designated as Hedging Instrument
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(35.3)	(150.2)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	1.4	144
Derivative Liability	(33.9)	(6.2)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(5.2)	(102.4)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	111.2
Derivative Liability	(5.2)	8.8
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Basis Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(0.7)	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.4	0
Derivative Liability	(0.3)	0
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Percent Basis Swaps [Member]
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(6.9)	(0.2)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.2	0.2
Derivative Liability	(6.7)	0
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Options [Member]
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1.1)	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.8	0
Derivative Liability	(0.3)	0
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Gasoline swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(1)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0.4
Derivative Liability	0	(0.6)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Gasoline Crack Spread Swaps [Member]
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(4.3)	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(4.3)	0
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Diesel Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(28.1)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	19.1
Derivative Liability	0	(9)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Jet Fuel Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(5.2)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	5.2
Derivative Liability	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Natural Gas Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1.3)	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(1.3)	0
Commodity Contract [Member] | Not Designated as Hedging Instrument | Specialty Product | Natural Gas Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(14.9)	(12.1)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	7.2
Derivative Liability	(14.9)	(4.9)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Specialty Product | Natural Gas Collars
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(0.9)	(1.1)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0.6
Derivative Liability	(0.9)	(0.5)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Specialty Product | Platinum Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(0.1)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0.1
Derivative Liability	0	0
Cash Flow Hedging [Member] | Commodity Contract [Member] | Designated as Hedging Instrument | Fuel Product | Crude Oil Swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(13.8)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	10
Derivative Liability	0	(3.8)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Designated as Hedging Instrument | Fuel Product | Gasoline swaps
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	4.4
Derivative Liability	$ 0	$ 4.4

Derivatives (Cash Flow Hedges)

Derivatives (Cash Flow Hedges) - Cash Flow Hedging [Member] - Designated as Hedging Instrument - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	$ (7.3)	$ 114.2
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion)	12.1	37
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	0.5	(2.2)
Commodity Contract [Member] | Fuel Product | Crude Oil Swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(5.6)	(185.8)
Commodity Contract [Member] | Fuel Product | Crude Oil Swaps | Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion)	(170.3)	44.2
Commodity Contract [Member] | Fuel Product | Crude Oil Swaps | Unrealized Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	(0.2)	4.8
Commodity Contract [Member] | Fuel Product | Gasoline swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	5.7	56.3
Commodity Contract [Member] | Fuel Product | Gasoline swaps | Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion)	44.7	(1.4)
Commodity Contract [Member] | Fuel Product | Gasoline swaps | Unrealized Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	0.7	(7.6)
Commodity Contract [Member] | Fuel Product | Diesel Swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(8.8)	220
Commodity Contract [Member] | Fuel Product | Diesel Swaps | Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion)	121.6	(6.7)
Commodity Contract [Member] | Fuel Product | Diesel Swaps | Unrealized Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	0	0
Commodity Contract [Member] | Fuel Product | Jet Fuel Swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	1.4	23.7
Commodity Contract [Member] | Fuel Product | Jet Fuel Swaps | Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion)	13.1	(0.9)
Commodity Contract [Member] | Fuel Product | Jet Fuel Swaps | Unrealized Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	0	0.6
Commodity Contract [Member] | Specialty Product | Crude Oil Swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	0	0
Commodity Contract [Member] | Specialty Product | Crude Oil Swaps | Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Loss (Effective Portion)	3	1.8
Commodity Contract [Member] | Specialty Product | Crude Oil Swaps | Unrealized Realized
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	$ 0	$ 0

Derivatives (Cash Flow Hedges c

Derivatives (Cash Flow Hedges classified in AOCIL) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive income (loss)	$ (1.6)	$ 13.7	$ (53.4)
2,016
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	6.4
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive income (loss)	$ 6.4	$ 25.8	$ (51.4)

Derivatives Derivatives (Fair V

Derivatives Derivatives (Fair Value Hedges) - Fair Value Hedging [Member] - Interest Expense [Member] - USD ($) $ in Millions	Jan. 13, 2015	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Liabilities, Fair Value Adjustment		$ 2.9	$ 2.5
Interest Rate Swap [Member] | Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative		0.5	2.5
Liabilities, Fair Value Adjustment	$ 3.3	0	(2.5)
Interest Rate Contract [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative		0.5	2.5
Liabilities, Fair Value Adjustment		$ 0	$ (2.5)

Derivatives (Not Designated as

Derivatives (Not Designated as Hedges) - Commodity Contract [Member] - Not Designated as Hedging Instrument - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 7.5	$ 32.5
Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(39.4)	12.9
Crude Oil Swaps | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(67.6)	(48.5)
Crude Oil Swaps | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	52	(61.9)
Crude Oil Basis Swaps | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1.1	5.7
Crude Oil Basis Swaps | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(7.8)	0.1
Crude Oil Percent Basis Swaps [Member] | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(3.2)	0
Crude Oil Percent Basis Swaps [Member] | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0.2	0
Crude Oil Options [Member] | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	6.1	0
Crude Oil Options [Member] | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.3)	0
Gasoline swaps | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(20)	(2.2)
Gasoline swaps | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.7)	10.1
Gasoline Crack Spread Swaps [Member] | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(5.5)	0
Gasoline Crack Spread Swaps [Member] | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(4.3)	0
Diesel Swaps | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	82.3	76.3
Diesel Swaps | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(68.7)	71.5
Jet Fuel Swaps | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1.6	3.2
Jet Fuel Swaps | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1.6)	0.7
Diesel Crack Spread Swaps [Member] | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	24.3	(3.6)
Diesel Crack Spread Swaps [Member] | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	4.5
Jet Fuel Crack Swaps [Member] | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(0.1)
Jet Fuel Crack Swaps [Member] | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Diesel Percent Basis Crack Spread Swaps [Member] | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.1)	0
Diesel Percent Basis Crack Spread Swaps [Member] | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(4.5)	0
Diesel Crack Spread Collars | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	1
Diesel Crack Spread Collars | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(0.1)
Gasoline Crack Spread Collars | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(0.4)
Gasoline Crack Spread Collars | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Platinum Swaps | Specialty Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.8)	0
Platinum Swaps | Specialty Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0.1	(0.1)
Natural Gas Swaps | Fuel Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Natural Gas Swaps | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1.3)	0
Natural Gas Swaps | Specialty Product | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(10.7)	1.1
Natural Gas Swaps | Specialty Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (2.5)	$ (11.9)

Derivatives (Natural Gas Swaps

Derivatives (Natural Gas Swaps - Specialty Product) - Commodity Contract [Member] - Natural Gas Swaps - Specialty Product - Not Designated as Hedging Instrument	Dec. 31, 2015bbl$ / MMBtu	Dec. 31, 2014bbl$ / MMBtu
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	10,830,000	14,380,000
$/MMBtu | $ / MMBtu	4.05	4.18
First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,580,000
$/MMBtu | $ / MMBtu	4.24
Second Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,380,000
$/MMBtu | $ / MMBtu	4.26
Third Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,380,000
$/MMBtu | $ / MMBtu	4.26
Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,540,000
$/MMBtu | $ / MMBtu	4.14
Calendar Year 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	4,950,000	1,830,000
$/MMBtu | $ / MMBtu	3.85	4.28
First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		1,770,000
$/MMBtu | $ / MMBtu		4.09
Second Quarter 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		1,500,000
$/MMBtu | $ / MMBtu		4.11
Third Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		1,500,000
$/MMBtu | $ / MMBtu		4.11
Fourth Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		1,900,000
$/MMBtu | $ / MMBtu		4.12
Calendar Year 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		5,880,000
$/MMBtu | $ / MMBtu		4.22

Derivatives Derivatives (Natura

Derivatives Derivatives (Natural Gas Collars - Specialty Product) - Specialty Product - Commodity Contract [Member] - Not Designated as Hedging Instrument - Natural Gas Collars	Dec. 31, 2015bbl$ / MMBtu	Dec. 31, 2014bbl$ / MMBtu
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	600,000	1,520,000
Average Bought Call ($/Bbl)	4.25	4.25
Average Sold Put ($/Bbl)	3.89	3.84
First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	180,000
Average Bought Call ($/Bbl)	4.25
Average Sold Put ($/Bbl)	3.89
Second Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	180,000
Average Bought Call ($/Bbl)	4.25
Average Sold Put ($/Bbl)	3.89
Third Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	180,000
Average Bought Call ($/Bbl)	4.25
Average Sold Put ($/Bbl)	3.89
Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	60,000
Average Bought Call ($/Bbl)	4.25
Average Sold Put ($/Bbl)	3.89
First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		240,000
Average Bought Call ($/Bbl)		4.25
Average Sold Put ($/Bbl)		3.79
Second Quarter 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		240,000
Average Bought Call ($/Bbl)		4.25
Average Sold Put ($/Bbl)		3.79
Third Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		240,000
Average Bought Call ($/Bbl)		4.25
Average Sold Put ($/Bbl)		3.79
Fourth Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		200,000
Average Bought Call ($/Bbl)		4.25
Average Sold Put ($/Bbl)		3.85
Calendar Year 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		600,000
Average Bought Call ($/Bbl)		4.25
Average Sold Put ($/Bbl)		3.89

Derivatives (Crude Oil Swaps)

Derivatives (Crude Oil Swaps) - Commodity Contract [Member] - Fuel Product	Dec. 31, 2015bbl$ / bbl	Dec. 31, 2014bbl$ / bbl
Crude Oil Swap Purchases | Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	747,840	3,510,628
Average Swap ($/Bbl) | $ / bbl	53.24	81.89
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	29,120
Barrels per Day Purchased	320
Average Swap ($/Bbl) | $ / bbl	44.06
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Second Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	29,120
Barrels per Day Purchased	320
Average Swap ($/Bbl) | $ / bbl	44.06
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Third Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	29,440
Barrels per Day Purchased	320
Average Swap ($/Bbl) | $ / bbl	44.06
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	29,440
Barrels per Day Purchased	320
Average Swap ($/Bbl) | $ / bbl	44.06
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Calendar Year 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	630,720
Barrels per Day Purchased	1,728
Average Swap ($/Bbl) | $ / bbl	54.94
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		1,674,000
Barrels per Day Purchased		18,600
Average Swap ($/Bbl) | $ / bbl		89.55
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Second Quarter 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		91,000
Barrels per Day Purchased		1,000
Average Swap ($/Bbl) | $ / bbl		89.89
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Third Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		386,400
Barrels per Day Purchased		4,200
Average Swap ($/Bbl) | $ / bbl		69.20
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Fourth Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		386,400
Barrels per Day Purchased		4,200
Average Swap ($/Bbl) | $ / bbl		69.20
Crude Oil Swap Purchases | Not Designated as Hedging Instrument | Calendar Year 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		972,828
Barrels per Day Purchased		2,658
Average Swap ($/Bbl) | $ / bbl		78.02
Crude Oil Swap Sales | Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		1,674,000
Average Swap ($/Bbl) | $ / bbl		84.21
Crude Oil Swap Sales | Not Designated as Hedging Instrument | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		1,674,000
Barrels per Day Sold		18,600
Average Swap ($/Bbl) | $ / bbl		84.21
Cash Flow Hedging [Member] | Crude Oil Swap Purchases | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		315,000
Average Swap ($/Bbl) | $ / bbl		97.71
Cash Flow Hedging [Member] | Crude Oil Swap Purchases | Designated as Hedging Instrument | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		315,000
Barrels per Day Purchased		3,500
Average Swap ($/Bbl) | $ / bbl		97.71

Derivatives (Crude Oil Basis Sw

Derivatives (Crude Oil Basis Swaps) - Commodity Contract [Member] - Fuel Product - Not Designated as Hedging Instrument	Dec. 31, 2015bbl$ / bbl	Dec. 31, 2014bbl$ / bbl
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	732,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	182,000
Barrels per Day Purchased	2,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | Second Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	182,000
Barrels per Day Purchased	2,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | Third Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	184,000
Barrels per Day Purchased	2,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	184,000
Barrels per Day Purchased	2,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	2.40
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	731,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	(13.90)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	91,000
Barrels per Day Purchased	1,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Second Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	91,000
Barrels per Day Purchased	1,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Third Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	92,000
Barrels per Day Purchased	1,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	92,000
Barrels per Day Purchased	1,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Calendar Year 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	365,000
Barrels per Day Purchased	1,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl	(13.70)
Crude Oil Basis Swaps Purchased [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		118,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl		(22.40)
Crude Oil Basis Swaps Purchased [Member] | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		118,000
Barrels per Day Purchased		2,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl		(22.40)

Derivatives Derivatives (Crude

Derivatives Derivatives (Crude Oil Percent Basis Swaps) - Commodity Contract [Member] - Crude Oil Percent Basis Swaps Purchased [Member] - Fuel Product - Not Designated as Hedging Instrument - bbl	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,658,000	368,000
Derivative, Fixed Percentage to Publicly Traded Future	73.40%	73.00%
First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	728,000
Barrels per Day Purchased	8,000
Derivative, Fixed Percentage to Publicly Traded Future	73.50%
Second Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	728,000
Barrels per Day Purchased	8,000
Derivative, Fixed Percentage to Publicly Traded Future	73.50%
Third Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	736,000
Barrels per Day Purchased	8,000
Derivative, Fixed Percentage to Publicly Traded Future	73.50%
Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	736,000
Barrels per Day Purchased	8,000
Derivative, Fixed Percentage to Publicly Traded Future	73.50%
Calendar Year 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	730,000
Barrels per Day Purchased	2,000
Derivative, Fixed Percentage to Publicly Traded Future	73.00%
Third Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		184,000
Barrels per Day Purchased		2,000
Derivative, Fixed Percentage to Publicly Traded Future		73.00%
Fourth Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		184,000
Barrels per Day Purchased		2,000
Derivative, Fixed Percentage to Publicly Traded Future		73.00%

Derivatives (Derivatives Crude

Derivatives (Derivatives Crude Oil Options) - Not Designated as Hedging Instrument - Fuel Product - Commodity Contract [Member] - Crude Oil Call Options Bought [Member]	Dec. 31, 2015bbl$ / bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	350,000
Average Bought Call ($/Bbl) | $ / bbl	55
Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	350,000
Barrels per Day Purchased	11,290
Average Bought Call ($/Bbl) | $ / bbl	55

Derivatives (Gasoline Swaps)

Derivatives (Gasoline Swaps) - Commodity Contract [Member] - Fuel Product	Dec. 31, 2014bbl$ / bbl
Gasoline Swaps Sold [Member] | Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	45,000
Average Swap ($/Bbl) | $ / bbl	111.72
Gasoline Swaps Sold [Member] | Not Designated as Hedging Instrument | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	45,000
Barrels per Day Sold	500
Average Swap ($/Bbl) | $ / bbl	111.72
Gasoline Swaps Purchased [Member] | Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	45,000
Average Swap ($/Bbl) | $ / bbl	78.12
Gasoline Swaps Purchased [Member] | Not Designated as Hedging Instrument | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	45,000
Barrels per Day Purchased	500
Average Swap ($/Bbl) | $ / bbl	78.12
Cash Flow Hedging [Member] | Gasoline Swaps Sold [Member] | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	315,000
Average Swap ($/Bbl) | $ / bbl	109.68
Cash Flow Hedging [Member] | Gasoline Swaps Sold [Member] | Designated as Hedging Instrument | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	315,000
Barrels per Day Sold	3,500
Average Swap ($/Bbl) | $ / bbl	109.68

Derivatives Derivatives (Gasoli

Derivatives Derivatives (Gasoline Crack Spread Swaps) - Not Designated as Hedging Instrument - Commodity Contract [Member] - Fuel Product - Gasoline Crack Spread Swaps [Member]	Dec. 31, 2015bbl$ / bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	873,000
Average Swap ($/Bbl) | $ / bbl	8.98
First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	873,000
Barrels per Day Sold	9,593
Average Swap ($/Bbl) | $ / bbl	8.98

Derivatives (Diesel Swaps)

Derivatives (Diesel Swaps) - Commodity Contract [Member] - Fuel Product - Not Designated as Hedging Instrument	Dec. 31, 2014bbl$ / bbl
Diesel Swaps Purchased
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,449,000
Average Swap ($/Bbl) | $ / bbl	105.78
Diesel Swaps Purchased | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,449,000
Barrels per Day Purchased	16,100
Average Swap ($/Bbl) | $ / bbl	105.78
Diesel Swaps Sold [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,099,000
Average Swap ($/Bbl) | $ / bbl	108.38
Diesel Swaps Sold [Member] | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,449,000
Barrels per Day Sold	16,100
Average Swap ($/Bbl) | $ / bbl	116.27
Diesel Swaps Sold [Member] | Second Quarter 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	91,000
Barrels per Day Sold	1,000
Average Swap ($/Bbl) | $ / bbl	117.92
Diesel Swaps Sold [Member] | Third Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	322,000
Barrels per Day Sold	3,500
Average Swap ($/Bbl) | $ / bbl	95.04
Diesel Swaps Sold [Member] | Fourth Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	322,000
Barrels per Day Sold	3,500
Average Swap ($/Bbl) | $ / bbl	95.04
Diesel Swaps Sold [Member] | Calendar Year 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	915,000
Barrels per Day Sold	2,500
Average Swap ($/Bbl) | $ / bbl	104.32

Derivatives (Diesel Percent Bas

Derivatives (Diesel Percent Basis Crack Spread Swaps) - Commodity Contract [Member] - Diesel Percent Basis Crack Spread Swaps Sold [Member] - Fuel Product - Not Designated as Hedging Instrument	Dec. 31, 2014bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2,475,000
Derivative, Fixed Percentage to Publicly Traded Future	32.20%
Third Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	414,000
Barrels per Day Sold	4,500
Derivative, Fixed Percentage to Publicly Traded Future	33.20%
Fourth Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	414,000
Barrels per Day Sold	4,500
Derivative, Fixed Percentage to Publicly Traded Future	33.20%
Calendar Year 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,647,000
Barrels per Day Sold	4,500
Derivative, Fixed Percentage to Publicly Traded Future	31.70%

Derivatives (Jet Fuel Swaps)

Derivatives (Jet Fuel Swaps) - Commodity Contract [Member] - Fuel Product - Not Designated as Hedging Instrument	Dec. 31, 2014bbl$ / bbl
Jet Fuel Swaps Purchased
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	180,000
Average Swap ($/Bbl) | $ / bbl	100.91
Jet Fuel Swaps Purchased | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	180,000
Barrels per Day Purchased	2,000
Average Swap ($/Bbl) | $ / bbl	100.91
Jet Fuel Swaps Sold
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	180,000
Average Swap ($/Bbl) | $ / bbl	115.65
Jet Fuel Swaps Sold | First Quarter 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	180,000
Barrels per Day Sold	2,000
Average Swap ($/Bbl) | $ / bbl	115.65

Derivatives Derivatives (Nat107

Derivatives Derivatives (Natural Gas Swaps - Fuel Product) - Commodity Contract [Member] - Not Designated as Hedging Instrument - Fuel Product - Natural Gas Swaps	Dec. 31, 2015bbl$ / MMBtu
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,602,000
Average Swap ($/Bbl) | $ / MMBtu	3.01
First Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	603,000
Average Swap ($/Bbl) | $ / MMBtu	3.01
Second Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	603,000
Average Swap ($/Bbl) | $ / MMBtu	2.99
Third Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	606,000
Average Swap ($/Bbl) | $ / MMBtu	3.03
Fourth Quarter 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	790,000
Average Swap ($/Bbl) | $ / MMBtu	3.02

Derivatives Derivatives (Platin

Derivatives Derivatives (Platinum Swaps)	Dec. 31, 2014
Commodity Option [Member] | Not Designated as Hedging Instrument | Fuel Product | Platinum Swaps | Calendar Year 2015
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,900

Derivatives (Details Textual)

Derivatives (Details Textual) $ in Millions	Jan. 13, 2015USD ($)	Nov. 26, 2013	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)bbl	Dec. 31, 2013USD ($)
Derivative [Line Items]
Derivative, Counterparty			0	5
Derivative Asset, Fair Value, Amount Not Offset Against Collateral			$ 0	$ 23.2
Collateral Already Posted, Aggregate Fair Value			0	0
Accumulated other comprehensive income (loss)			(1.6)	13.7	$ (53.4)
Derivative, Notional Amount			200
7.625% Notes
Derivative [Line Items]
Debt Instrument, Maturity Date		Jan. 15, 2022
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Derivative [Line Items]
Accumulated other comprehensive income (loss)			6.4	$ 25.8	$ (51.4)
Commodity Contract [Member] | Not Designated as Hedging Instrument | Fuel Product | Crude Oil Basis Swaps Purchased [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl				118,000
Interest Expense [Member] | Fair Value Hedging [Member]
Derivative [Line Items]
Liabilities, Fair Value Adjustment			2.9	$ 2.5
Interest Expense [Member] | Fair Value Hedging [Member] | Designated as Hedging Instrument | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Gain on Derivative			0.5	2.5
Liabilities, Fair Value Adjustment	$ 3.3		$ 0	$ (2.5)

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative liabilities:
Total derivative liabilities	$ (33.9)	$ (5.6)
Level 1
Derivative assets:
Pension plan investments	0.4	0.2
Level 2
Derivative assets:
Pension plan investments	47.1	49.4
Fair Value, Measurements, Recurring
Derivative assets:
Total derivative assets	0	23.2
Pension plan investments	47.5	49.6
Total recurring assets at fair value	47.5	72.8
Derivative liabilities:
Total derivative liabilities	(33.9)	(5.6)
RINS Obligation	(88.4)	(16.3)
Liability Awards	0	(4.7)
Total recurring liabilities at fair value	(122.3)	(26.6)
Fair Value, Measurements, Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Pension plan investments	0.4	0.2
Total recurring assets at fair value	0.4	0.2
Derivative liabilities:
Total derivative liabilities	0	0
RINS Obligation	0	0
Liability Awards	0	(4.7)
Total recurring liabilities at fair value	0	(4.7)
Fair Value, Measurements, Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Pension plan investments	47.1	49.4
Total recurring assets at fair value	47.1	49.4
Derivative liabilities:
Total derivative liabilities	0	0
RINS Obligation	(88.4)	(16.3)
Liability Awards	0	0
Total recurring liabilities at fair value	(88.4)	(16.3)
Fair Value, Measurements, Recurring | Level 3
Derivative assets:
Total derivative assets	0	23.2
Pension plan investments	0	0
Total recurring assets at fair value	0	23.2
Derivative liabilities:
Total derivative liabilities	(33.9)	(5.6)
RINS Obligation	0	0
Liability Awards	0	0
Total recurring liabilities at fair value	(33.9)	(5.6)
Fair Value, Measurements, Recurring | Crude Oil Swaps
Derivative assets:
Total derivative assets	0	(89.8)
Derivative liabilities:
Total derivative liabilities	(5.2)	5
Fair Value, Measurements, Recurring | Crude Oil Swaps | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Swaps | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Swaps | Level 3
Derivative assets:
Total derivative assets	0	(89.8)
Derivative liabilities:
Total derivative liabilities	(5.2)	5
Fair Value, Measurements, Recurring | Crude Oil Basis Swaps
Derivative assets:
Total derivative assets	0	0.8
Derivative liabilities:
Total derivative liabilities	(0.3)	0
Fair Value, Measurements, Recurring | Crude Oil Basis Swaps | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Basis Swaps | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Basis Swaps | Level 3
Derivative assets:
Total derivative assets	0	0.8
Derivative liabilities:
Total derivative liabilities	(0.3)	0
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps [Member]
Derivative assets:
Total derivative assets	0	(0.2)
Derivative liabilities:
Total derivative liabilities	(6.7)	0
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps [Member] | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps [Member] | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps [Member] | Level 3
Derivative assets:
Total derivative assets	0	(0.2)
Derivative liabilities:
Total derivative liabilities	(6.7)	0
Fair Value, Measurements, Recurring | Crude Oil Options [Member]
Derivative liabilities:
Total derivative liabilities	(0.3)	0
Fair Value, Measurements, Recurring | Crude Oil Options [Member] | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Options [Member] | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Options [Member] | Level 3
Derivative liabilities:
Total derivative liabilities	(0.3)	0
Fair Value, Measurements, Recurring | Gasoline swaps
Derivative assets:
Total derivative assets	0	13.5
Derivative liabilities:
Total derivative liabilities	0	3.8
Fair Value, Measurements, Recurring | Gasoline swaps | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline swaps | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline swaps | Level 3
Derivative assets:
Total derivative assets	0	13.5
Derivative liabilities:
Total derivative liabilities	0	3.8
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps [Member]
Derivative liabilities:
Total derivative liabilities	(4.3)	0
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps [Member] | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps [Member] | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps [Member] | Level 3
Derivative liabilities:
Total derivative liabilities	(4.3)	0
Fair Value, Measurements, Recurring | Diesel Swaps
Derivative assets:
Total derivative assets	0	97
Derivative liabilities:
Total derivative liabilities	0	(9)
Fair Value, Measurements, Recurring | Diesel Swaps | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Diesel Swaps | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Diesel Swaps | Level 3
Derivative assets:
Total derivative assets	0	97
Derivative liabilities:
Total derivative liabilities	0	(9)
Fair Value, Measurements, Recurring | Diesel Crack Spread
Derivative assets:
Total derivative assets	0	4.5
Fair Value, Measurements, Recurring | Diesel Crack Spread | Level 1
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Diesel Crack Spread | Level 2
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Diesel Crack Spread | Level 3
Derivative assets:
Total derivative assets	0	4.5
Fair Value, Measurements, Recurring | Jet Fuel Swaps
Derivative assets:
Total derivative assets	0	2.7
Fair Value, Measurements, Recurring | Jet Fuel Swaps | Level 1
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Jet Fuel Swaps | Level 2
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Jet Fuel Swaps | Level 3
Derivative assets:
Total derivative assets	0	2.7
Fair Value, Measurements, Recurring | Natural Gas Swaps
Derivative assets:
Total derivative assets	0	(7.2)
Derivative liabilities:
Total derivative liabilities	(16.2)	(4.9)
Fair Value, Measurements, Recurring | Natural Gas Swaps | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Natural Gas Swaps | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Natural Gas Swaps | Level 3
Derivative assets:
Total derivative assets	0	(7.2)
Derivative liabilities:
Total derivative liabilities	(16.2)	(4.9)
Fair Value, Measurements, Recurring | Natural Gas Collars
Derivative assets:
Total derivative assets	0	(0.5)
Derivative liabilities:
Total derivative liabilities	(0.9)	(0.5)
Fair Value, Measurements, Recurring | Natural Gas Collars | Level 1
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Natural Gas Collars | Level 2
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Natural Gas Collars | Level 3
Derivative assets:
Total derivative assets	0	(0.5)
Derivative liabilities:
Total derivative liabilities	(0.9)	(0.5)
Fair Value, Measurements, Recurring | Platinum Swaps
Derivative assets:
Total derivative assets	0	(0.1)
Fair Value, Measurements, Recurring | Platinum Swaps | Level 1
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Platinum Swaps | Level 2
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Platinum Swaps | Level 3
Derivative assets:
Total derivative assets	0	(0.1)
Fair Value, Measurements, Recurring | Interest Rate Swap [Member]
Derivative assets:
Total derivative assets	0	2.5
Fair Value, Measurements, Recurring | Interest Rate Swap [Member] | Level 1
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Interest Rate Swap [Member] | Level 2
Derivative assets:
Total derivative assets	0	0
Fair Value, Measurements, Recurring | Interest Rate Swap [Member] | Level 3
Derivative assets:
Total derivative assets	$ 0	$ 2.5

Fair Value Measurements (Det111

Fair Value Measurements (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Unrealized loss on derivative instruments	$ (39.5)	$ (0.6)
Change in fair value of cash flow hedges	(7.3)	114.2	$ (36.9)
Level 3
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Fair value at January 1,	17.6	(54.8)
Realized Gain Loss on Derivative Instruments	(8.1)	(43.8)
Unrealized loss on derivative instruments	(39.5)	(0.6)
Interest Income (Expense), Net	(0.5)	(0.8)
Change in fair value of cash flow hedges	(7.3)	114.2
Settlements	3.9	3.4
Transfers in (out) of Level 3	0	0
Fair value at December 31,	$ (33.9)	$ 17.6	$ (54.8)

Fair Value Measurements (Det112

Fair Value Measurements (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Capital Lease Obligations [Member]
Financial Instrument:
Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034	$ 46.4	$ 43.6
Fair Value | Level 1
Financial Instrument:
Notes Payable, Fair Value Disclosure	1,095.8	630
Fair Value | Level 2
Financial Instrument:
Notes Payable, Fair Value Disclosure	294.1	803.3
Fair Value | Level 3
Financial Instrument:
Lines of Credit, Fair Value Disclosure		143.3
Fair Value | Revolving Credit Facility [Member] | Level 3
Financial Instrument:
Lines of Credit, Fair Value Disclosure	105.1
Carrying Value | Level 1
Financial Instrument:
Notes Payable, Fair Value Disclosure	1,230.8	606.6
Carrying Value | Level 2
Financial Instrument:
Notes Payable, Fair Value Disclosure	317.6	885.3
Carrying Value | Level 3
Financial Instrument:
Notes Payable, Fair Value Disclosure	73.5	0
Lines of Credit, Fair Value Disclosure	105.1	143.3
Carrying Value | Capital Lease Obligations [Member] | Level 3
Financial Instrument:
Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034	$ 46.4	$ 43.6

Fair Value Measurements (Det113

Fair Value Measurements (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gain on Sale of RINs	$ 55.4	$ 14.5
RINs Expense	94.2	23.9
Fair Value Measurements (Textual) [Abstract]
Derivative Credit Risk Valuation Adjustment, Derivative Liabilities	$ 1.2	0.1
Derivative Credit Risk Valuation Adjustment, Derivative Assets		2
Reviews for goodwill impairment annually on	Oct. 1, 2015
Shreveport and San Antonio Refineries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gain on Sale of RINs		$ 18.2

Partners' Capital Partner's 114

Partners' Capital Partner's Capital (Details 1)	12 Months Ended
	Dec. 31, 2015$ / shares
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	$ 0.495
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	$ 0.495
Second Target Distribution | Maximum
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Incentive Distribution, Distribution Per Unit	$ 0.563
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	$ 0.563
Third Target Distribution | Maximum
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Incentive Distribution, Distribution Per Unit	$ 0.675
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	$ 0.675
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 Partner's 115

Partners' Capital Partner's Capital (Details 2) - USD ($) $ / shares in Units, $ in Millions	Mar. 13, 2015		Apr. 02, 2013		Jan. 08, 2013		Jan. 08, 2013		Feb. 24, 2011	Dec. 11, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Offering of Common Units [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	6,000,000		6,037,500	[1]	5,750,000	[2]					432,167	134,955
Stock Price, Offering Price Per Share	$ 26.75		$ 37.50		$ 31.81		$ 31.81
Proceeds from Issuance of Common Limited Partners Units	$ 153.9	[3]	$ 217.3	[3]	$ 175.2	[3]				$ 10.2	$ 164.1	$ 3.6	$ 392.5
General Partners' Contributed Capital	3.3	[4]	4.6	[4]	3.8	[4]	$ 3.8	[4]			0.2	0.1
Offering Costs, Partnership Interests	$ 6.4		$ 9.1		$ 7.4		$ 7.4				$ 0.1	$ 0.1
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest									2.00%
Overallotment Option [Member]
Public Offering of Common Units [Line Items]
Partners' Capital Account, Units, Sold in Public Offering			787,500				750,000
Firm Units [Member]
Public Offering of Common Units [Line Items]
Partners' Capital Account, Units, Sold in Public Offering					5,000,000
[1]	(4) Includes the full exercise of the overallotment option of 787,500 common units which closed on April 4, 2013.
[2]	(3) 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.
[3]	(1) Proceeds are net of underwriting discounts, commissions and expenses but before the general partner’s capital contribution.
[4]	(2) The Company’s general partner contributions were made to retain its 2% general partner interest.

Partners' Capital Partner's 116

Partners' Capital Partner's Capital (Details Textuals) - USD ($) $ / shares in Units, $ in Millions	Mar. 13, 2015		Apr. 02, 2013		Jan. 08, 2013		Dec. 11, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capital Unit [Line Items]
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%
Payments of Capital Distribution								$ 224.6	$ 210.2	$ 201.6
General partner's incentive distribution rights								$ 16.8	$ 15.4	14.7
Partners' Capital Account, Units, Sold in Public Offering	6,000,000		6,037,500	[1]	5,750,000	[2]		432,167	134,955
Equity Placement Agreement aggregate offering price								$ 300
Proceeds from Issuance of Common Limited Partners Units	$ 153.9	[3]	$ 217.3	[3]	$ 175.2	[3]	$ 10.2	164.1	$ 3.6	$ 392.5
Offering Costs, Partnership Interests	6.4		9.1		7.4			0.1	0.1
General Partners' Contributed Capital	$ 3.3	[4]	$ 4.6	[4]	$ 3.8	[4]		$ 0.2	$ 0.1
Limited Partners' Minimum Vote Required for Removal of General Partner								66.67%
Partners' Capital, After Distribution Required Cash Amount								$ 45
Partners' Capital, Distribution, Fixed Charge Coverage Ratio Threshold								1.75
Stock Price, Offering Price Per Share	$ 26.75		$ 37.50		$ 31.81
Maximum | 6.50% Notes
Capital Unit [Line Items]
Partners' Capital, Distribution Amount, Below Fixed Charge Coverage Ratio Threshold								$ 225
Maximum | 7.625% Notes
Capital Unit [Line Items]
Partners' Capital, Distribution Amount, Below Fixed Charge Coverage Ratio Threshold								210
Maximum | 7.75% Notes
Capital Unit [Line Items]
Partners' Capital, Distribution Amount, Below Fixed Charge Coverage Ratio Threshold								$ 225
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								12.50%
Investor [Member]
Capital Unit [Line Items]
Partners' Capital Account, Units								59,623,920
Affiliated Entity [Member]
Capital Unit [Line Items]
Partners' Capital Account, Units								16,260,480
Limited Partners
Capital Unit [Line Items]
Limited Partners' Capital Account, Units Outstanding								75,884,400	69,452,233
General Partner
Capital Unit [Line Items]
Partners' Capital Account, Units								1,548,660
[1]	(4) Includes the full exercise of the overallotment option of 787,500 common units which closed on April 4, 2013.
[2]	(3) 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.
[3]	(1) Proceeds are net of underwriting discounts, commissions and expenses but before the general partner’s capital contribution.
[4]	(2) The Company’s general partner contributions were made to retain its 2% general partner interest.

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) - Nonvested Phantom Units - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of Phantom Units
Nonvested at beginning of period	502,120	688,256	835,927
Granted	343,533	477,527	483,044
Vested	(321,741)	(280,263)	(276,115)
Forfeited	(103,188)	(383,400)	(354,600)
Nonvested at end of period	420,724	502,120	688,256
Weighted-Average Grant Date Fair Value
Nonvested at beginning of period	$ 26.48	$ 23.70	$ 27.57
Granted	21.70	25.97	27.73
Vested	23.54	23.72	24.22
Forfeited	23.94	25.59	30.60
Nonvested at end of period	$ 24.27	$ 26.48	$ 23.70

Unit-Based Compensation (Det118

Unit-Based Compensation (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for grant under the Plan	3,883,960
Vested phantom unit grants
Unit-Based Compensation (Textual) [Abstract]
Compensation expense related to vested phantom unit grants	$ 7.5	$ 5.5	$ 4.8
Vested phantom unit grants, liability awards
Unit-Based Compensation (Textual) [Abstract]
Compensation expense related to vested phantom unit grants	5	2.5	1.6
Nonvested phantom units
Unit-Based Compensation (Textual) [Abstract]
Unrecognized compensation costs related to nonvested phantom unit grants	$ 9.6	12.2
Unit-Based Compensation nonvested phantom compensation costs are expected to be recognized over a weighted-average period	3 years
Fair value of phantom units vested during the period	$ 7	6.7	$ 6.7
Nonvested phantom units, liability awards [Member]
Unit-Based Compensation (Textual) [Abstract]
Compensation expense related to vested phantom unit grants		$ 10.5
Long-Term Incentive Plan | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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, 2015
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, Employer Matching Contribution, Percent of Match	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Incremental Percentage Point	1.00%
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, Employer Matching Contribution, Percent of Match	50.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Incremental Percentage Point	1.00%

Employee Benefit Plans (Deta120

Employee Benefit Plans (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Defined Contribution Plan, Cost Recognized	$ 5.9	$ 5.4	$ 4.1
Employer discretionary contribution amount	$ 0	$ 1.2	$ 0.9

Employee Benefit Plans (Deta121

Employee Benefit Plans (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Employer contribution	$ 1.5	$ 1.5
Estimated future employer contributions in next fiscal year	1.9
Plan curtailment	$ 0.9	$ 0
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]
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	3 years
Montana Plan | Domestic Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	36 months
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 (Deta122

Employee Benefit Plans (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of amounts recognized in the consolidated balance sheets:
Accumulated other comprehensive loss	$ (6.8)	$ (11.9)
Pension Plans, Defined Benefit
Change in projected benefit obligation:
Benefit obligation at beginning of year	69.3	57.2
Service cost	0.5	0.4	$ 0.4
Interest cost	2.6	2.6	2.4
Plan curtailment	(0.9)	0
Benefits paid	(2.6)	(2.5)
Actuarial (gain) loss	(8.6)	11.7
Administrative expense	0	(0.1)
Benefit obligation at end of year	60.3	69.3	57.2
Change in plan assets:
Fair value of plan assets at beginning of year	49.6	45.8
Benefit payments	(2.6)	(2.5)
Actual return on assets	(1)	4.9
Administrative expense	0	(0.1)
Employer contribution	1.5	1.5
Fair value of plan assets at end of year	47.5	49.6	$ 45.8
Funded status — benefit obligation in excess of plan assets	(12.8)	(19.7)
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	(12.8)	(19.7)
Unrecognized net actuarial loss	6.8	11.9
Accumulated other comprehensive loss	6.8	11.9
Net amount recognized at end of year	(6)	(7.8)
Other Postretirement Benefit Plan [Member]
Change in projected benefit obligation:
Benefit obligation at beginning of year	0.3
Benefit obligation at end of year	$ 0.2	$ 0.3

Employee Benefit Plans (Deta123

Employee Benefit Plans (Details 4) - Pension Plans, Defined Benefit - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 60.3	$ 68.4
Accumulated benefit obligation in excess of fair value of plan assets, accumulated benefit obligation	60.3	68.4
Accumulated benefit obligation in excess of fair value of plan assets, fair value of plan assets	$ 47.5	$ 49.6

Employee Benefit Plans (Deta124

Employee Benefit Plans (Details 5) - Pension Plans, Defined Benefit - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations in Excess of Plan Assets, Projected Benefit Obligation	$ 60.3	$ 69.3
Projected Benefit Obligations in Excess of Plan Assets, Fair Value of Plan Assets	$ 47.5	$ 49.6

Employee Benefit Plans (Deta125

Employee Benefit Plans (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans, Defined Benefit
Components of net periodic pension and other post retirement benefits cost
Service cost	$ 0.5	$ 0.4	$ 0.4
Interest cost	2.6	2.6	2.4
Expected return on assets	(3.3)	(3.1)	(2.9)
Amortization of net loss	0.8	0.3	0.8
Curtailment gain recognized	(0.9)	0	0
Net periodic benefit cost (income)	(0.3)	0.2	$ 0.7
Other Postretirement Benefit Plan [Member]
Components of net periodic pension and other post retirement benefits cost
Net periodic benefit cost (income)	$ 0.4	$ 0

Employee Benefit Plans (Deta126

Employee Benefit Plans (Details 7) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Total recognized in other comprehensive (income) loss	$ (4.7)	$ 9.6	$ (9.6)
Classified in accumulated other comprehensive loss	(6.8)	(11.9)
Amounts that will be amortized from accumulated other comprehensive income in next fiscal year	0.4
Pension Plans, Defined Benefit
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net (gain) loss	(4.3)	9.9	(8.8)
Amortization or settlement recognition of net loss	(0.8)	(0.3)	(0.8)
Total recognized in other comprehensive (income) loss	(5.1)	9.6	$ (9.6)
Classified in accumulated other comprehensive loss	$ 6.8	$ 11.9

Employee Benefit Plans (Deta127

Employee Benefit Plans (Details 8) - Pension Plans, Defined Benefit		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Penreco Plan
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate		4.30%	3.92%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate		3.92%	4.78%	3.86%
Expected return on plan assets	[1]	6.75%	6.75%	6.75%
Superior Plan
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate		4.27%	3.86%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate		3.86%	4.66%	3.75%
Expected return on plan assets	[1]	6.75%	6.75%	6.75%
Montana Plan
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate		4.21%	4.13%
Rate of compensation increase			3.00%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate		4.13%	4.97%	4.03%
Expected return on plan assets	[1]	6.75%	6.75%	6.75%
Rate of compensation increase		3.00%	3.00%	3.00%
[1]	(1) The Company considered the historical returns, the future expectation for returns for each asset class and fair value of the plan assets, 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.

Employee Benefit Plans (Deta128

Employee Benefit Plans (Details 9)	12 Months Ended
	Dec. 31, 2015
Equity funds
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target Allocation Minimum	15.00%
Target Allocation Maximum	25.00%
Target Allocation	20.00%
Foreign equities
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target Allocation Minimum	15.00%
Target Allocation Maximum	25.00%
Target Allocation	20.00%
Fixed income
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target Allocation Minimum	55.00%
Target Allocation Maximum	65.00%
Target Allocation	60.00%

Employee Benefit Plans (Deta129

Employee Benefit Plans (Details 10) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
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	$ 0.4	$ 0.2
Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 47.1	$ 49.4
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	1.00%	0.00%
Cash and cash equivalents | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 0.4	$ 0.2
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	20.00%	20.00%
Equity funds | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 0	$ 0
Equity funds | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 9.6	$ 10
Foreign equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	19.00%	19.00%
Foreign equities | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 0	$ 0
Foreign equities | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 9.2	$ 9.4
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	60.00%	61.00%
Fixed income | Level 1
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 0	$ 0
Fixed income | Level 2
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 28.3	$ 30

Employee Benefit Plans (Deta130

Employee Benefit Plans (Details 11) - Pension Plans, Defined Benefit $ in Millions	Dec. 31, 2015USD ($)
Defined Benefit Plan Disclosure [Line Items]
2,016	$ 2.8
2,017	3
2,018	3
2,019	3.1
2,020	3.3
2021 to 2025	17.6
Total	$ 32.8

Accumulated Other Comprehens131

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	$ 13.7	$ (53.4)
Other comprehensive income (loss) before reclassifications	(3.6)	103.8
Amounts reclassified from accumulated other comprehensive income (loss)	(11.7)	(36.7)
Total other comprehensive income (loss)	(15.3)	67.1	$ (27.9)
Ending balance: Accumulated other comprehensive loss	(1.6)	13.7	(53.4)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	25.8	(51.4)
Other comprehensive income (loss) before reclassifications	(7.3)	114.2
Amounts reclassified from accumulated other comprehensive income (loss)	(12.1)	(37)
Total other comprehensive income (loss)	(19.4)	77.2
Ending balance: Accumulated other comprehensive loss	6.4	25.8	(51.4)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	(11.5)	(1.9)
Other comprehensive income (loss) before reclassifications	4.3	(9.9)
Amounts reclassified from accumulated other comprehensive income (loss)	0.4	0.3
Total other comprehensive income (loss)	4.7	(9.6)
Ending balance: Accumulated other comprehensive loss	(6.8)	(11.5)	(1.9)
Accumulated Translation Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	(0.6)	(0.1)
Other comprehensive income (loss) before reclassifications	(0.6)	(0.5)
Amounts reclassified from accumulated other comprehensive income (loss)	0	0
Total other comprehensive income (loss)	(0.6)	(0.5)
Ending balance: Accumulated other comprehensive loss	$ (1.2)	$ (0.6)	$ (0.1)

Accumulated Other Comprehens132

Accumulated Other Comprehensive Income (Loss) (Details 1) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total other comprehensive income (loss)		$ (15.3)	$ 67.1	$ (27.9)
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)		(19.4)	77.2
Accumulated Defined Benefit Plans Adjustment
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total other comprehensive income (loss)		4.7	(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		179.4	(9)
Cost of Goods Sold		(167.3)	46
Total other comprehensive income (loss)		12.1	37
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	[1]	(0.8)	(0.3)
Total other comprehensive income (loss)		$ (0.8)	$ (0.3)
[1]	(1) This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 12 for additional information.

Income Taxes Income Taxes (Deta

Income Taxes Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal	$ 0.1	$ 0.2	$ 0
State	0	0.2	0.4
Total	0.1	0.4	0.4
Federal	(26.5)	(1.5)	0
State	(2)	0.3	0
Total	(28.5)	(1.2)	0
Total income tax expense (benefit)	$ (28.4)	$ (0.8)	$ 0.4

Income Taxes Income Taxes (D134

Income Taxes Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal income tax rate	35.00%	35.00%	35.00%
Partnership earnings not subject to tax	(13.80%)	(22.40%)	(35.00%)
State income taxes, net of federal income tax effect	0.60%	(0.40%)	11.40%
State tax rate change	0.20%	0.00%	0.00%
Impact of non-deductible goodwill	(5.00%)	(11.50%)	0.00%
Anchor LLC conversions	0.30%	0.00%	0.00%
Other items, net	(0.40%)	0.00%	(1.10%)
Effective tax rate	16.90%	0.70%	10.30%

Income Taxes Income Taxes (D135

Income Taxes Income Taxes (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Inventory	$ 0	$ 2.3
Net operating loss carryforwards	0.8	3.7
Total deferred income tax assets	0.8	6
Intangible assets	(0.1)	(22)
Deferred Tax Liabilities, Unrealized Currency Transaction Gains	0.5	0
Property, plant and equipment	(2)	(14)
Total deferred income tax liabilities	(2.6)	(36)
Net deferred income tax liability	$ (1.8)	$ (30)

Income Taxes Income Taxes (Text

Income Taxes Income Taxes (Textuals) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Operating Loss Carryforwards	$ 2.1
Net operating loss carryforwards	$ 0.8	$ 3.7

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Earnings Per Unit [Abstract]
Net Income (Loss), Net of Tax, Per Outstanding Limited Partnership Unit, Diluted	$ (1.56)	$ (0.68)	$ (0.02)	$ 0.27	$ (0.95)	$ 0.08	$ (0.17)	$ (0.76)	$ (2.05)		$ (1.80)		$ (0.17)
Numerator for basic and diluted earnings per limited partner unit:
Net income (loss)	$ (116.8)	$ (48.9)	$ 2.5	$ 23.8	$ (63.5)	$ 9.4	$ (8.3)	$ (49.8)	$ (139.4)	[1]	$ (112.2)	[1]	$ 3.5
General partner’s interest in net income (loss)									2.8		2.2		(0.1)
General partner's incentive distribution rights									16.8		15.4		14.7
Non-vested share based payments									0		0		0.2
Net income (loss) available to limited partners	$ (118.6)	$ (52.2)	$ (1.7)	$ 19.1	$ (66.2)	$ 5.4	$ (12)	$ (52.6)	$ (153.4)	[1]	$ (125.4)	[1]	$ (11.5)
Denominator for basic and diluted earnings per limited partner unit:
Weighted average limited partner units outstanding — basic	76,124,133	76,112,325	76,092,517	71,232,392	69,775,827	69,684,621	69,604,669	69,622,884	74,896,096		69,671,827		67,938,784
Weighted average limited partner units outstanding — diluted	76,124,133	76,112,325	76,092,517	71,275,452	69,775,827	69,850,685	69,604,669	69,622,884	74,896,096	[2]	69,671,827	[2]	67,938,784	[2]
Limited partners’ interest basic and diluted net loss per unit	$ (1.56)	$ (0.68)	$ (0.02)	$ 0.27	$ (0.95)	$ 0.08	$ (0.17)	$ (0.76)	$ (2.05)		$ (1.80)		$ (0.17)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									400,000		200,000		200,000
[1]	(1) The sum of the four quarters may not equal the total year due to rounding.
[2]	(1) Total diluted weighted average limited partner units outstanding excludes 0.4 million, 0.2 million and 0.2 million potentially dilutive phantom units for the years ended December 31, 2015, 2014 and 2013, respectively.

Transactions with Related Pa138

Transactions with Related Parties Transactions with Related Parties (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Limited Partners
Related Party Transaction [Line Items]
Product sales to related parties	$ 12	$ 9.1	$ 9.7
Trade accounts and other receivables	0.4	1.2
Excluding Legacy Resources
Related Party Transaction [Line Items]
Purchases from related party	21.8	41.1	9
Accounts payable from related parties	2.3	4.3
Legacy Resources
Related Party Transaction [Line Items]
Purchases from related party	0	0.8	1.2
Accounts payable from related parties	0	0
Tobias Insurance Group, Inc
Related Party Transaction [Line Items]
Purchases from related party	0	0.7	0.7
Monument Chemical [Member]
Related Party Transaction [Line Items]
Purchases from related party	0.5
Officer [Member]
Related Party Transaction [Line Items]
Purchases from related party	43	29	$ 6.3
Accounts payable from related parties	$ 10	$ 2.6

Segments and Related Informa139

Segments and Related Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Reportable segment information
Sales	$ 898	$ 1,140	$ 1,156.2	$ 1,018.6	$ 1,339.4	$ 1,675.8	$ 1,434.9	$ 1,341	$ 4,212.8		$ 5,791.1		$ 5,421.4
Income (Loss) from Equity Method Investments									(61.5)		(3.4)		(0.3)
Adjusted EBITDA									257.7		305.9		241.5
Reconciling items to net income:
Depreciation and amortization									174.4		163.1		133.7
Realized gain (loss) on derivatives, not reflected in net income (loss)									(10)		6.6		(1.8)
Asset Impairment Charges									58.1		36		10.5
Unrealized (gain) loss on derivatives									39.5		0.6		(25.7)
Interest expense									104.9		110.8		96.8
Debt extinguishment costs									46.6		89.9		14.6
Non-cash equity based compensation and other non-cash items									12		11.9		9.5
Income tax expense (benefit)									28.4		0.8		(0.4)
Net income (loss)	$ (116.8)	$ (48.9)	$ 2.5	$ 23.8	$ (63.5)	$ 9.4	$ (8.3)	$ (49.8)	(139.4)	[1]	(112.2)	[1]	3.5
Sales Revenue, Segment
Reportable segment information
Sales									4,212.8		5,791.1		5,421.4
Intersubsegment Eliminations
Reportable segment information
Sales									0		0		0
Intersegment Eliminations
Reportable segment information
Sales									(43)		(108.2)		(77.3)
Income (Loss) from Equity Method Investments									0		0		0
Adjusted EBITDA									0		0		0
Reconciling items to net income:
Depreciation and amortization									0		0		0
Realized gain (loss) on derivatives, not reflected in net income (loss)									0		0		0
Asset Impairment Charges									0		0		0
Intersegment Eliminations | Sales Revenue, Segment
Reportable segment information
Sales									0		0		0
Intersegment Eliminations | Intersubsegment Eliminations
Reportable segment information
Sales									(43)		(108.2)		(77.3)
Specialty Product | Operating Segments
Reportable segment information
Sales									1,371.7		1,747.6		1,774.9
Income (Loss) from Equity Method Investments									0		0		0
Adjusted EBITDA									201.7		220.8		194.5
Reconciling items to net income:
Depreciation and amortization									69.2		68.1		66.6
Realized gain (loss) on derivatives, not reflected in net income (loss)									(3)		(1.9)		(0.5)
Asset Impairment Charges									0		0		10.5
Specialty Product | Operating Segments | Sales Revenue, Segment
Reportable segment information
Sales									1,367.8		1,729.2		1,774.9
Specialty Product | Operating Segments | Intersubsegment Eliminations
Reportable segment information
Sales									3.9		18.4		0
Fuel Product | Operating Segments
Reportable segment information
Sales									2,601.6		3,783.2		3,723.8
Income (Loss) from Equity Method Investments									(61.1)		(3.2)		(0.3)
Adjusted EBITDA									81.9		50		47
Reconciling items to net income:
Depreciation and amortization									82.4		80		67.1
Realized gain (loss) on derivatives, not reflected in net income (loss)									(7)		8.5		(1.3)
Asset Impairment Charges									24.3		0		0
Fuel Product | Operating Segments | Sales Revenue, Segment
Reportable segment information
Sales									2,562.5		3,693.4		3,646.5
Fuel Product | Operating Segments | Intersubsegment Eliminations
Reportable segment information
Sales									39.1		89.8		77.3
Oilfield Services | Operating Segments
Reportable segment information
Sales									282.5		368.5		0
Income (Loss) from Equity Method Investments									(0.4)		(0.2)		0
Adjusted EBITDA									(25.9)		35.1		0
Reconciling items to net income:
Depreciation and amortization									22.8		15		0
Realized gain (loss) on derivatives, not reflected in net income (loss)									0		0		0
Asset Impairment Charges											36		0
Oilfield Services | Operating Segments | Sales Revenue, Segment
Reportable segment information
Sales									282.5		368.5		0
Oilfield Services | Operating Segments | Intersubsegment Eliminations
Reportable segment information
Sales									0		0		0
Combined Segments | Operating Segments
Reportable segment information
Sales									4,255.8		5,899.3		5,498.7
Income (Loss) from Equity Method Investments									(61.5)		(3.4)		(0.3)
Adjusted EBITDA									257.7		305.9		241.5
Reconciling items to net income:
Depreciation and amortization									174.4		163.1		133.7
Realized gain (loss) on derivatives, not reflected in net income (loss)									(10)		6.6		(1.8)
Asset Impairment Charges									58.1		36		10.5
Combined Segments | Operating Segments | Sales Revenue, Segment
Reportable segment information
Sales									4,212.8		5,791.1		5,421.4
Combined Segments | Operating Segments | Intersubsegment Eliminations
Reportable segment information
Sales									$ 43		$ 108.2		$ 77.3
[1]	(1) The sum of the four quarters may not equal the total year due to rounding.

Segments and Related Informa140

Segments and Related Information (Details 1) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Major product category sales
Sales	$ 898	$ 1,140	$ 1,156.2	$ 1,018.6	$ 1,339.4	$ 1,675.8	$ 1,434.9	$ 1,341	$ 4,212.8	$ 5,791.1	$ 5,421.4
Concentration Risk, Percentage									52.20%	45.90%	54.10%
Product Concentration Risk
Major product category sales
Sales									$ 4,212.8	$ 5,791.1	$ 5,421.4
Concentration Risk, Percentage									100.00%	100.00%	100.00%
Product Concentration Risk | Specialty Product
Major product category sales
Sales									$ 1,367.8	$ 1,729.2	$ 1,774.9
Concentration Risk, Percentage									32.50%	29.90%	32.70%
Product Concentration Risk | Specialty Product | Lubricating oils
Major product category sales
Sales									$ 575.6	$ 748.4	$ 848.8
Concentration Risk, Percentage									13.70%	12.90%	15.70%
Product Concentration Risk | Specialty Product | Solvents
Major product category sales
Sales									$ 302	$ 485.2	$ 511.7
Concentration Risk, Percentage									7.20%	8.40%	9.40%
Product Concentration Risk | Specialty Product | Waxes
Major product category sales
Sales									$ 136.9	$ 144.1	$ 141
Concentration Risk, Percentage									3.20%	2.50%	2.60%
Product Concentration Risk | Specialty Product | Packaged and synthetic specialty products
Major product category sales
Sales									$ 316.6	$ 313.5	$ 233.6
Concentration Risk, Percentage									7.50%	5.40%	4.30%
Product Concentration Risk | Specialty Product | Other
Major product category sales
Sales									$ 36.7	$ 38	$ 39.8
Concentration Risk, Percentage									0.90%	0.70%	0.70%
Product Concentration Risk | Fuel Product
Major product category sales
Sales									$ 2,562.5	$ 3,693.4	$ 3,646.5
Concentration Risk, Percentage									60.80%	63.70%	67.30%
Product Concentration Risk | Fuel Product | Gasoline
Major product category sales
Sales									$ 1,047.1	$ 1,443.1	$ 1,409.4
Concentration Risk, Percentage									24.90%	24.90%	26.00%
Product Concentration Risk | Fuel Product | Diesel
Major product category sales
Sales									$ 894.8	$ 1,197.4	$ 1,259.2
Concentration Risk, Percentage									21.20%	20.70%	23.30%
Product Concentration Risk | Fuel Product | Jet fuel
Major product category sales
Sales									$ 149.6	$ 199.3	$ 191.4
Concentration Risk, Percentage									3.60%	3.40%	3.50%
Product Concentration Risk | Fuel Product | Asphalt, heavy fuel oils and other
Major product category sales
Sales									$ 471	$ 853.6	$ 786.5
Concentration Risk, Percentage									11.10%	14.70%	14.50%
Product Concentration Risk | Oilfield Services
Major product category sales
Sales									$ 282.5	$ 368.5	$ 0
Concentration Risk, Percentage									6.70%	6.40%	0.00%

Segments and Related Informa141

Segments and Related Information (Details 2)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting [Abstract]
Concentration Risk, Percentage	52.20%	45.90%	54.10%

Quarterly Financial Data (Un142

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Net Income (Loss), Net of Tax, Per Outstanding Limited Partnership Unit, Diluted	$ (1.56)	$ (0.68)	$ (0.02)	$ 0.27	$ (0.95)	$ 0.08	$ (0.17)	$ (0.76)	$ (2.05)		$ (1.80)		$ (0.17)
Sales	$ 898	$ 1,140	$ 1,156.2	$ 1,018.6	$ 1,339.4	$ 1,675.8	$ 1,434.9	$ 1,341	$ 4,212.8		$ 5,791.1		$ 5,421.4
Gross Profit	31.9	164.8	202.7	195.2	123.3	182.6	99	124.8	594.6	[1]	529.7	[1]	410
Net income (loss)	(116.8)	(48.9)	2.5	23.8	(63.5)	9.4	(8.3)	(49.8)	(139.4)	[1]	(112.2)	[1]	3.5
Net income (loss) available to limited partners	$ (118.6)	$ (52.2)	$ (1.7)	$ 19.1	$ (66.2)	$ 5.4	$ (12)	$ (52.6)	$ (153.4)	[1]	$ (125.4)	[1]	$ (11.5)
Limited partners’ interest basic net income (loss) per unit	$ (1.56)	$ (0.68)	$ (0.02)	$ 0.27	$ (0.95)	$ 0.08	$ (0.17)	$ (0.76)	$ (2.05)		$ (1.80)		$ (0.17)
Weighted average limited partner units outstanding — basic	76,124,133	76,112,325	76,092,517	71,232,392	69,775,827	69,684,621	69,604,669	69,622,884	74,896,096		69,671,827		67,938,784
Weighted average limited partner units outstanding — diluted	76,124,133	76,112,325	76,092,517	71,275,452	69,775,827	69,850,685	69,604,669	69,622,884	74,896,096	[2]	69,671,827	[2]	67,938,784	[2]
[1]	(1) The sum of the four quarters may not equal the total year due to rounding.
[2]	(1) Total diluted weighted average limited partner units outstanding excludes 0.4 million, 0.2 million and 0.2 million potentially dilutive phantom units for the years ended December 31, 2015, 2014 and 2013, respectively.

Subsequent Events (Details Text

Subsequent Events (Details Textual) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	Feb. 12, 2016	Feb. 02, 2016	Jan. 19, 2016	Feb. 29, 2016
Fair Value Disclosures [Abstract]
Derivative decrease to fair value				$ (9)
Fair of value net liability				38
Long-term debt increase to fair value				$ (455)
Dividend Declared
Partners' Capital Account, Distributions [Abstract]
Aggregate quarterly distribution			Jan. 19, 2016
Cash distribution per unit			$ 0.685
Dividends Payable			$ 57.4
Dividend Paid
Partners' Capital Account, Distributions [Abstract]
Quarterly Distribution Dividends Payable Amount Per Share			$ 2.74
Dividends Payable			$ 229.6
Distribution paid date	Feb. 12, 2016
Record date for the close of business		Feb. 2, 2016