Calumet Specialty Products Partners (CLMT) 10-K 2 Apr 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Apr. 02, 2018	Jun. 30, 2017
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, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 256.5
Entity Common Stock, Shares Outstanding		76,905,657

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 164.3	$ 4.2
Restricted cash	350	0
Accounts receivable, net:
Trade, less allowance for doubtful accounts of $7.0 million and $0.9 million, respectively	265.4	182.7
Other	88.7	22.2
Total accounts receivable	354.1	204.9
Inventories	314.4	357.8
Derivative assets	0	0.8
Prepaid expenses and other current assets	8.7	10.6
Discontinued operations, current assets	0	62.6
Total current assets	1,191.5	640.9
Property, plant and equipment, net	1,159.2	1,632.4
Investment in unconsolidated affiliates	35	9.6
Goodwill	171.4	177.2
Other intangible assets, net	107.9	133.5
Other noncurrent assets, net	23.8	40.3
Discontinued operations, noncurrent assets	0	91.3
Total assets	2,688.8	2,725.2
Current liabilities:
Accounts payable	282.3	275.9
Accrued interest payable	52.5	52.5
Accrued salaries, wages and benefits	35.9	11.1
Other taxes payable	16.1	20.4
Obligations under inventory financing agreements	103.1	0
Other current liabilities	73.7	99.6
Current portion of long-term debt	354.1	3.5
Derivative liabilities	6	14.8
Discontinued operations, current liabilities	2	20.4
Total current liabilities	925.7	498.2
Pension and postretirement benefit obligations	3.1	11.3
Other long-term liabilities	1.9	3.3
Long-term debt, less current portion	1,638.2	1,993.7
Total liabilities	2,568.9	2,506.5
Commitments and contingencies
Partners’ capital:
Limited partners’ interest (76,788,801 units and 76,392,258 units, issued and outstanding at December 31, 2017 and 2016, respectively)	113.3	211.2
General partner’s interest	13.8	15.8
Accumulated other comprehensive loss	(7.2)	(8.3)
Total partners’ capital	119.9	218.7
Total liabilities and partners’ capital	$ 2,688.8	$ 2,725.2

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Allowance for doubtful accounts	$ 7	$ 0.9
Limited Partners
Limited Partners' Capital Account, Units Issued	76,788,801	76,392,258
Limited partners common units outstanding (in shares)	76,788,801	76,392,258

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Income Statement [Abstract]
Sales	$ 3,763.8		$ 3,474.3		$ 3,930.3
Cost of sales	3,265.6		3,088		3,393.9
Gross profit	498.2	[1]	386.3	[1]	536.4
Operating costs and expenses:
Selling	65.7		69.8		71.8
General and administrative	138.7		105.8		125.9
Transportation	137.1		154.3		153.6
Taxes other than income taxes	24.1		19.3		17.1
Asset impairment	207.3		35.7		0
Gain on sale of business	(236)		0		0
Other	3.3		1.7		10.8
Operating income (loss)	158		(0.3)		157.2
Other income (expense):
Interest expense	(183.1)		(161.7)		(104.9)
Debt extinguishment costs	0		0		(46.6)
Loss on derivative instruments	(9.6)		(4.1)		(31.4)
Loss from unconsolidated affiliates	0		(18.3)		(61.1)
Loss on sale of unconsolidated affiliates	0		(113.4)		0
Other	3.3		1.2		1.6
Total other expense	(189.4)		(296.3)		(242.4)
Net loss from continuing operations before income taxes	(31.4)		(296.6)		(85.2)
Income tax expense (benefit) from continuing operations	(0.1)		0.2		0.2
Net loss from continuing operations	(31.3)		(296.8)		(85.4)
Net loss from discontinued operations	(72.5)		(31.8)		(54)
Allocation of net loss:
Net loss	(103.8)		(328.6)		(139.4)
Less:
General partner’s interest in net loss	(2.1)		(6.6)		(2.8)
General partner's incentive distribution rights	0		0		16.8
Net loss available to limited partners	$ (101.7)		$ (322)	[1]	$ (153.4)
Weighted average limited partner units outstanding:
Weighted Average Number of Shares Outstanding, Basic and Diluted	77,598,950	[2]	77,043,935		74,896,096
Limited partners' interest basic net loss per unit from continuing operations	$ (0.40)		$ (3.77)		$ (1.34)
Limited partners' interest basic net loss per unit from discontinued operations	(0.91)		(0.41)		(0.71)
Limited partners' interest diluted net loss per unit from continuing operations	(0.40)		(3.77)		(1.34)
Limited partners' interest diluted net loss per unit from discontinued operations	(0.91)		(0.41)		(0.71)
Limited partners’ interest basic net income (loss) per unit	(1.31)		(4.18)		(2.05)
Limited partners' interest diluted net income (loss) per unit	(1.31)		(4.18)		(2.05)
Cash distributions declared per limited partner unit	$ 0		$ 0.685		$ 2.74
[1]	The sum of the four quarters may not equal the total year due to rounding.
[2]	Total diluted weighted average limited partner units outstanding excludes 0.2 million, 0.5 million and 0.4 million potentially dilutive phantom units which would be antidilutive for the years ended December 31, 2017, 2016 and 2015, respectively.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (103.8)	$ (328.6)	$ (139.4)
Cash flow hedges:
Cash flow hedge gain reclassified to net loss	0	(6.4)	(12.1)
Change in fair value of cash flow hedges	0	0	(7.3)
Defined benefit pension and retiree health benefit plans	1.1	(0.3)	4.7
Foreign currency translation adjustment	0	0	(0.6)
Total other comprehensive income (loss)	1.1	(6.7)	(15.3)
Comprehensive loss attributable to partners’ capital	$ (102.7)	$ (335.3)	$ (154.7)

Consolidated Statements of Part

Consolidated Statements of Partners' Capital - USD ($) $ in Millions	Total	AOCI Attributable to Parent [Member]	General Partner	Limited Partners
Beginning 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)	0	14	(153.4)
Common units repurchased for phantom unit grants	(5.5)	0	0	(5.5)
Issuance of phantom units	1.9	0	0	1.9
Settlement of tax withholdings on equity-based incentive compensation	(1.5)	0	0	(1.5)
Reclassification of Liability Awards to equity	7.9	0	0	7.9
Amortization of 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
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	(6.7)	(6.7)	0	0
Net income (loss)	(328.6)	0	(6.6)	(322)
Issuance of phantom units	4.1	0	0	4.1
Settlement of tax withholdings on equity-based incentive compensation	(2.4)	0	0	(2.4)
Amortization of phantom units	5.6	0	0	5.6
Contributions from Calumet GP, LLC	0.2	0	0.2	0
Distributions to partners	(57.4)	0	(5.3)	(52.1)
Ending balance at Dec. 31, 2016	218.7	(8.3)	15.8	211.2
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income (loss)	1.1	1.1	0	0
Net income (loss)	(103.8)	0	(2.1)	(101.7)
Settlement of tax withholdings on equity-based incentive compensation	(0.9)	0	0	(0.9)
Amortization of phantom units	4.7	0	0	4.7
Contributions from Calumet GP, LLC	0.1	0	0.1	0
Ending balance at Dec. 31, 2017	$ 119.9	$ (7.2)	$ 13.8	$ 113.3

Consolidated Statements of Cash

Consolidated Statements of Cash Flows $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Statement of Cash Flows [Abstract]
Net loss	$ (103.8)	$ (328.6)	$ (139.4)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Net loss from discontinued operations	72.5	31.8	54
Depreciation and amortization	154.8	152	122.6
Amortization of turnaround costs	24.3	33.2	29
Non-cash interest expense	10.2	9.6	6.6
Non-cash debt extinguishment costs	0	0	9.1
Unrealized (gain) loss on derivative instruments	(3.6)	(19.9)	39.5
Asset impairment	207.3	35.7	0
Equity-based compensation	11.6	5.6	9.8
Lower of cost or market inventory adjustment	(30.6)	(38.4)	67
Loss from unconsolidated affiliates	0	18.3	61.1
Loss on sale of unconsolidated affiliates	0	113.4	0
Gain on sale of business	(236)	0	0
Other non-cash activities	10.2	5.4	10.5
Changes in assets and liabilities:
Accounts receivable	(158.9)	(38.9)	52.6
Inventories	(8.5)	41.5	25
Prepaid expenses and other current assets	(0.8)	(4.2)	0.6
Derivative activity	(0.5)	(19)	(7)
Turnaround costs	(14.5)	(8.7)	(19.3)
Other assets	(0.5)	(0.6)	0
Accounts payable	70.6	18.4	(77.3)
Accrued interest payable	0.9	21.4	(6.5)
Accrued salaries, wages and benefits	18	(17.8)	10.7
Other taxes payable	0.9	3.6	1.8
Other liabilities	(24.2)	(16.6)	74.5
Pension and postretirement benefit obligations	(2.7)	(2)	(2.3)
Net cash (used in) provided by discontinued operating activities	(23.2)	8.9	53.8
Net cash (used in) provided by operating activities	(26.5)	4.1	376.4
Investing activities
Additions to property, plant and equipment	(70)	(139.2)	(332.1)
Investment in unconsolidated affiliates	0	(45.7)	(50.2)
Proceeds from sale of unconsolidated affiliates	0	29	0
Proceeds from sale of property, plant and equipment	0.3	1.7	0.1
Proceeds from sale of business	484.5	0	0
Net cash (used in) provided by discontinued investing activities	38.6	0	(6.8)
Net cash (used in) provided by investing activities	453.4	(154.2)	(389)
Financing activities
Proceeds from borrowings — revolving credit facility	901.2	1,187.1	1,390
Repayments of borrowings — revolving credit facility	(911.2)	(1,287.9)	(1,429.8)
Proceeds from borrowings — senior notes	0	393.1	322.6
Repayments of borrowings — senior notes	0	0	(275)
Proceeds from borrowings — related party note	0	0	75
Repayments of borrowings — related party note	0	(75)	0
Payments on capital lease obligations	(2.5)	(8.5)	(8)
Proceeds from inventory financing	100.1	0	0
Proceeds from (payments on) other financing obligations	(2.3)	8.5	(2.5)
Proceeds from public offerings of common units, net	0	0	164.1
Debt issuance costs	(2.2)	(11.4)	(5.6)
Contributions from Calumet GP, LLC	0.1	0.2	3.5
Distributions to partners	0	(57.4)	(224.6)
Net cash provided by financing activities	83.2	148.7	9.7
Net increase (decrease) in cash, cash equivalents and restricted cash	510.1	(1.4)	(2.9)
Cash, cash equivalents and restricted cash at beginning of year	4.2	5.6	8.5
Cash, cash equivalents and restricted cash at end of year	514.3	4.2	5.6
Cash and cash equivalents	164.3	4.2	5.6
Restricted cash	350	0	0
Supplemental disclosure of cash flow information
Interest paid, net of capitalized interest	163.7	130.2	120.6
Income taxes paid	0.4	1.2	1.1
Non-cash consideration received for the sale of Anchor	25.4	0	0
Non-cash property, plant and equipment additions	9.1	14	56.5
Non-cash capital lease	$ 0	$ 2.3	$ 4.4

Description of the Business

Description of the Business	12 Months Ended
	Dec. 31, 2017
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, 2017 , the Company had 76,788,801 limited partner common units and 1,567,118 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 Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, waxes, and fuel and fuel related products including gasoline, diesel, jet fuel, asphalt and heavy fuel oils. The Company is based in Indianapolis, Indiana and owns specialty and fuel products facilities. The Company owns and leases additional facilities, primarily related to production and marketing of specialty and fuel products, throughout the United States (“U.S.”). Subsequent to the sale of Anchor Drilling Fluids USA, LLC (“Anchor”) on November 21, 2017, the Company manages its business in two reportable segments: specialty products and fuel products. Prior to November 21, 2017, the Company owned and operated Anchor, which provided oilfield services and products in the United States. On November 21, 2017, the Company completed the sale of Anchor. As a result, effective in its fourth quarter of 2017, the Company classified its results of operations for all periods presented to reflect Anchor as a discontinued operation and classified the assets and liabilities of Anchor as discontinued operations . Prior to being reported as discontinued operations, Anchor was included as its own reportable segment as oilfield services. See Note 3 for further discussion.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2017
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 subsidiaries. All intercompany profits, transactions and balances have been eliminated. Investments in significant noncontrolled entities are accounted for either by using the equity method or cost method of accounting. 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, Cash Equivalents and Restricted Cash Cash, cash equivalents and restricted cash include all highly liquid investments with a maturity of three months or less at the time of purchase. The sale of the Superior, Wisconsin refinery (“Superior Refinery”) resulted in restricted cash and was based upon the value of collateral under the Company’s debt agreements. Under the indentures governing the Company’s senior notes, proceeds from Asset Sales (as defined in the indentures) can only be used for, among other things, to repay, redeem or repurchase debt; to make certain acquisitions or investments; and to make capital expenditures. 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 its 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, 2017 2016 2015 Beginning balance $ 0.9 $ 0.9 $ 1.4 Provision 6.1 0.3 — Write-offs, net — (0.3 ) (0.5 ) Ending balance $ 7.0 $ 0.9 $ 0.9 Inventories The cost of inventory is recorded using the last-in, first-out (“LIFO”) method. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. The replacement cost of these inventories, based on current market values, would have been $4.6 million lower and $15.7 million lower as of December 31, 2017 and 2016 , respectively. At December 31, 2017 and 2016 , the Company had $1.4 million and $1.3 million , respectively, of inventory consigned to others. On March 31, 2017 and June 19, 2017, the Company sold inventory comprised of crude oil and refined products to Macquarie Energy North America Trading Inc. (“Macquarie”) under Supply and Offtake Agreements as described in Note 8 — “ Inventory Financing Agreements ” related to the Great Falls and Shreveport refineries, respectively. The crude oil remains in the legal title of Macquarie and is stored in the Company’s refinery storage tanks governed by storage agreements. Legal title to the crude oil passes to the Company at the storage tank outlet. After processing, Macquarie takes title to the refined products stored in the Company’s storage tanks until sold to third parties. While title to certain inventories will reside with Macquarie, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to Macquarie will continue to be included in the Company’s consolidated balance sheets until processed and sold to a third party. The Company is obligated to repurchase the inventory in certain scenarios. The agreements are accounted for similar to a product financing arrangement. Inventories consist of the following (in millions): December 31, 2017 December 31, 2016 Titled Supply & Offtake (1) Total Titled Supply & Offtake (1) Total Raw materials $ 42.0 $ 17.6 $ 59.6 $ 57.4 $ — $ 57.4 Work in process 34.4 23.7 58.1 74.2 — 74.2 Finished goods 139.4 57.3 196.7 226.2 — 226.2 $ 215.8 $ 98.6 $ 314.4 $ 357.8 $ — $ 357.8 (1) Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Refer to Note 8 for further information. Under the LIFO inventory 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, 2017 , 2016 and 2015 , the Company recorded increases (exclusive of lower of cost or market (“LCM”) adjustments) of $3.7 million , $28.5 million and $25.1 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, 2017 and 2016 , the Company recorded decreases in cost of sales in the consolidated statements of operations of $30.6 million and $38.4 million , respectively, due to the LCM valuation. During the year ended December 31, 2015 , the Company recorded an increase in cost of sales in the consolidated statements of operations of $67.0 million due to the LCM 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 10 . On a regular basis, the Company enters into commodity contracts with counterparties for the purchase or sale of crude oil, blendstocks and various finished products. These contracts usually qualify for the normal purchase / normal sale exemption under ASC 815 and, as such, are not measured at fair value. Property, Plant and Equipment Property, plant and equipment are stated on the basis of cost. Depreciation is calculated using the straight-line method over the estimated useful lives. 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, 2017 2016 Land $ 13.8 $ 19.6 Buildings and improvements (10 to 40 years) 36.9 69.0 Machinery and equipment (10 to 20 years) 1,622.8 2,055.3 Furniture and fixtures (5 to 10 years) 61.5 33.2 Assets under capital leases (4 to 26 years) (1) 18.2 51.3 Construction-in-progress 21.4 49.0 1,774.6 2,277.4 Less accumulated depreciation (615.4 ) (645.0 ) $ 1,159.2 $ 1,632.4 (1) Assets under capital leases primarily relate to machinery and equipment. 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 2017 , 2016 and 2015 , the Company incurred $185.2 million , $166.8 million and $133.5 million , respectively, of interest expense of which $2.1 million , $5.1 million and $28.6 million , respectively, was capitalized as a component of property, plant and equipment. The Company has not recorded an asset retirement obligation as of December 31, 2017 or 2016 , because such potential obligations cannot be measured since it is not possible to estimate the settlement dates. During the years ended December 31, 2017 , 2016 and 2015 , the Company recorded $130.0 million , $125.1 million and $93.2 million , respectively, of depreciation expense on its property, plant and equipment. Depreciation expense included $3.9 million , $3.6 million and $2.6 million for the years ended 2017 , 2016 and 2015 , 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, 2017 and 2016 , the Company had $55.8 million and $17.6 million , respectively, of capitalized software costs. As of December 31, 2017 and 2016 , the Company had $20.9 million and $17.2 million , respectively of accumulated depreciation related to the capitalized software costs. During the years ended December 31, 2017 , 2016 and 2015 , the Company recorded $3.3 million , $4.1 million and $4.2 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 Pacific New Investment Limited joint venture as an equity method investment in accordance with ASC 323, Investments — Equity Method and Joint Ventures and is recorded in investments in unconsolidated affiliates in the consolidated balance sheet . 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. The Company accounts for its ownership in Fluid Holding Corp. (“FHC”) as a cost method investment in accordance with ASC 323, Investments — Equity Method and Joint Ventures and is recorded in investments in unconsolidated affiliates in the consolidated balance sheet. The cost method of accounting is applied when the investor does not have the ability to exercise significant influence. Under the cost method, investments are carried at cost and are adjusted only for other-than-temporary declines in fair value, certain distributions and additional investments. Equity method and cost method investments are assessed for other-than-temporary impairment whenever changes in the facts and circumstances indicate an other than temporary loss in value has occurred. During the year ended December 31, 2016 , the Company recorded a $0.2 million impairment charge in loss from unconsolidated affiliates in the consolidated statements of operations. The Company recorded a $24.3 million impairment charge in loss from unconsolidated affiliates in the consolidated statements of operations in 2015 . For further information on the Company’s investment in unconsolidated affiliates, refer to Note 5 . Goodwill Goodwill represents the excess of purchase price over fair value of the net assets acquired in various acquisitions. See Note 6 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) and ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . Under ASC 350, 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 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. Under ASU 2017-04, goodwill impairment testing is done by comparing the fair value of the reporting unit to its carrying value. If the carrying amount exceeds the fair value, the Company would recognize an impairment charge for the amount that the reporting unit's carrying value exceeds the fair value, not to exceed the total amount of goodwill allocated to that reporting unit. 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 the reporting unit, measuring the current value of the reporting unit 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. For more information, refer to Note 6 . Definite-Lived Intangible Assets Definite-lived intangible assets consist of intangible assets associated with customer relationships, tradenames, trade secrets, patents 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 6 . 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 $13.4 million and $35.9 million as of December 31, 2017 and 2016 , respectively. The Company capitalizes these costs and amortizes the costs on a straight-line basis over the lives of the turnaround assets which is generally two to five years. These amounts are net of accumulated amortization of $72.7 million and $101.9 million at December 31, 2017 and 2016 , respectively. Other Current Liabilities Other current liabilities consisted of the following (in millions): December 31, 2017 2016 RINs Obligation $ 59.1 $ 79.3 Other 14.6 20.3 Total $ 73.7 $ 99.6 The Company’s Renewable Identification Numbers (“RINs”) obligation (“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 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. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RINs spot price. The Company recognizes an asset at the end of each reporting period in which it has generated RINs in excess of its RINs Obligation. The asset is initially recorded at 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 sales for the period in the consolidated statements of operations. The value of RINs in excess of the RINs Obligation, if any, would be reflected in other current assets on the consolidated balance sheets. RINs generated in excess of the Company’s current RINs Obligation may be sold or held to offset future RINs Obligations. Any such sales of excess RINs are recorded in cost of sales in the consolidated statements of operations. The assets and liabilities associated with our RINs Obligation are considered recurring fair value measurements. See Note 7 for further information on the Company’s RINs Obligation. 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 the fourth quarter of 2017, the Company identified impairment indicators that suggested the carrying values long-lived assets including property, plant and equipment at the Missouri and San Antonio reporting units within the specialty products and fuel products segments, respectively, may not be recoverable. The primary impairment indicators included recently completed projections of future cash flows and the associated impact on the long-range strategic plan forecasts, lower than expected cash flows attributed to these reporting units and poor local market conditions. Undiscounted cash flow tests performed for these reporting units indicated that the long-lived assets were not recoverable. The fair value of the reporting units was established using a discounted cash flow method which utilized Level 3 inputs in the fair value hierarchy. The principal parameters used to establish fair values included estimates of future margins on products produced and sold, future commodity prices, future capital expenditures and discount rates. As a result of the long-lived asset impairment assessment performed, the Company recorded impairment charges primarily on property, plant and equipment on its Missouri reporting unit of $59.2 million and on its San Antonio reporting unit of $147.0 million for the year ended December 31, 2017 . During 2016, the Company recorded write-downs related to idle fixed assets within the specialty products segments. Non-cash charges of $0.9 million were recorded in asset impairment on the consolidated statement of operations and consolidated statement of cash flows for the year ended December 31, 2016 . No impairments of long-lived assets were recorded in 2015 . 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. Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same statement of operations line). 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, 2017 and 2016 . The Company accounts for income taxes for its corporations 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 value of Liability Awards is updated at each balance sheet date and changes in the fair value of the vested portions of the Liability Awards are recorded as increases or decreases to compensation expense. See Note 13 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 $137.1 million , $154.3 million and $153.6 million , respectively, for the years ended December 31, 2017 , 2016 and 2015 , 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 $6.6 million , $9.9 million and $14.2 million in 2017 , 2016 and 2015 , 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 August 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging (Topic 815) - Targeted Improvements to Accounting for Hedging Activities (“ASU 2017-12”). ASU 2017-12 which improves the financial reporting of hedging relationships to better align risk management activities in financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Company is currently evaluating the adoption of ASU 2017-12 on the Company’s consolidated financial statements. In May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09, Compensation - Stock Compensation (Topic 718) - Scope of Modification Accounting (“ASU 2017-09”). ASU 2017-09 amends prior guidance by further defining when a change to the terms of a share-based award are required to be accounted for as a modification under the rules by providing specific criteria. ASU 2017-09 is effective for annual periods beginning after December 15, 2017. The adoption of ASU 2017-09 will not have an impact on the Company’s consolidated financial statements. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-07, Compensation –

Discontinued Operations Discont

Discontinued Operations Discontinued Operations	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations On November 21, 2017, Calumet Operating, LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Company, completed the sale to a subsidiary of Q’Max Solutions Inc. (“Q’Max”) of all of the issued and outstanding membership interests in Anchor Drilling Fluids USA, LLC, (“Anchor”), for total consideration of approximately $89.6 million (subject to further post-closing adjustments) including a base price $50.0 million , $14.2 million to be paid at various times over the 24 month period following the closing of the transaction for net working capital and other items, and 10% equity ownership in FHC, the parent company of Q’Max (the “Anchor Transaction”). Effective in its fourth quarter of 2017, the Company classified its results of operations for all periods presented to reflect Anchor as a discontinued operation and classified the assets and liabilities of Anchor as discontinued operations . The Company recognized a net loss on sale of $62.6 million in net loss from discontinued operations in the consolidated statements of operations for the year ended December 31, 2017 . Prior to being reported as discontinued operations, Anchor was included as its own reportable segment as oilfield services. As of December 31, 2017 , the Company recorded a $15.1 million receivable in other accounts receivable in the consolidated balance sheet for the remaining payment of the base price and working capital and a $7.1 million receivable in other noncurrent assets, net in the consolidated balance sheet for the remaining payment of working capital. The following table summarizes the results of discontinued operations for each of the periods presented (in millions): Year Ended December 31, 2017 2016 2015 Sales $ 228.6 $ 125.1 $ 282.5 Cost of sales (168.1 ) (103.1 ) (224.3 ) Selling (45.9 ) (40.9 ) (74.2 ) General and administrative (4.5 ) (4.8 ) (9.6 ) Asset impairment — — (33.8 ) Loss on sale of business, net (62.6 ) — — Other (21.0 ) (16.0 ) (23.2 ) Net loss from discontinued operations before income taxes $ (73.5 ) $ (39.7 ) $ (82.6 ) Income tax benefit (1) (1.0 ) (7.9 ) (28.6 ) Net loss from discontinued operations net of income taxes $ (72.5 ) $ (31.8 ) $ (54.0 ) (1) Income tax benefit for 2016 included a $7.8 million tax refund related to federal and state income taxes. The following table summarizes the major classes of assets and liabilities from discontinued operations: December 31, 2016 DISCONTINUED OPERATIONS ASSETS Current assets: Accounts receivable, net $ 33.8 Inventories 28.4 Prepaid expenses and other current assets 0.4 Discontinued operations, current assets 62.6 Property, plant and equipment, net 45.6 Investment in unconsolidated affiliates 0.7 Other intangible assets, net 45.0 Discontinued operations, noncurrent assets 91.3 Discontinued operations, total assets $ 153.9 DISCONTINUED OPERATIONS LIABILITIES Current liabilities: Accounts payable $ 19.6 Accrued salaries, wages and benefits 0.4 Other taxes payable 0.4 Discontinued operations, current liabilities $ 20.4

Divestitures Divestitures

Divestitures Divestitures	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Divestitures	Divestitures On November 8, 2017, Calumet Refining, LLC, a Delaware limited liability company (formerly known as Calumet Lubricants Co., Limited Partnership, an Indiana limited partnership) (“Calumet Refining”) and a wholly-owned subsidiary of the Company, completed the sale of all of the issued and outstanding membership interests in Calumet Superior, LLC, a Delaware limited liability company (“Superior”), which owns the Superior, Wisconsin refinery (“Superior Refinery”) and associated net working capital, the Superior Refinery’s wholesale marketing business and related assets, including certain owned or leased product terminals, and certain crude gathering assets and pipeline space in North Dakota to Husky Superior Refining Holding Corp., a Delaware corporation (“Husky”) (the “Superior Transaction”). Total consideration was $533.1 million which consisted of a base price of $435.0 million and $98.1 million for net working capital and reimbursement of certain capital spending, subject to further post-closing adjustments. The Superior Refinery is included in the Company’s fuel products segment. The Company recognized a net gain of $236.0 million in gain on sale of business in the consolidated statements of operations for the year ended December 31, 2017 . The Company recorded a $41.0 million (subject to further post-closing adjustments which could increase the receivable to approximately $45.0 million according to the membership interest purchase agreement) receivable in other accounts receivable in the consolidated balance sheets for post-closing working capital adjustments. The Company considered other qualitative and quantitative factors and concluded the Superior Transaction did not represent a strategic shift in the business. However, the Company considers Superior to be an individually significant component of its operations. The following table presents the net income before income taxes for Superior for the periods presented (in millions): Year Ended December 31, 2017 2016 2015 Sales $ 669.1 $ 681.2 $ 856.8 Gross profit $ 110.0 $ 68.5 $ 137.6 Net income before income taxes $ 99.3 $ 54.5 $ 121.0

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliate	12 Months Ended
	Dec. 31, 2017
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 (in millions): Year Ended December 31, 2017 Year Ended December 31, 2016 Investment Percent Ownership Investment Percent Ownership Pacific New Investment Limited $ 9.6 23.8 % $ 9.6 23.8 % Fluid Holding Corp. 25.4 10 % — — % Total $ 35.0 $ 9.6 Dakota Prairie Refining, LLC On June 27, 2016 , the Company consummated the sale of its 50% equity interest in Dakota Prairie Refining, LLC (“Dakota Prairie”) to joint venture partner WBI Energy, Inc. (“WBI”), a wholly owned subsidiary of MDU Resources Group, Inc. (“MDU”). Concurrent with the Company’s sale of its equity interest in Dakota Prairie to WBI, Tesoro Refining & Marketing Company LLC (“Tesoro”) acquired 100% of Dakota Prairie from WBI in a separate transaction that closed on June 27, 2016 . Under the terms of the definitive agreement with WBI, the Company received consideration of $28.5 million , which was offset by the Company’s repayment of $36.0 million in borrowings under Dakota Prairie’s revolving credit facility. In addition, the Company’s $39.4 million letter of credit supporting the Dakota Prairie revolving credit facility was terminated. As part of the transaction, MDU and WBI released the Company from all liabilities arising out of or related to Dakota Prairie. In addition, Tesoro and Dakota Prairie released the Company from all liabilities arising out of the organization, management and operation of Dakota Prairie, subject to certain limited exceptions. Further, WBI agreed to indemnify the Company from all liabilities arising out of or related to Dakota Prairie, subject to certain limited exceptions. As a result of the sale of Dakota Prairie, the Company recorded a loss on sale of unconsolidated affiliate of $113.9 million during the year ended December 31, 2016. During the year ended December 31, 2016, the Company purchased $5.3 million , of crude oil and other feedstocks at cost from Dakota Prairie. There were no accounts payable to Dakota Prairie as of December 31, 2016. During the year ended December 31, 2016, the Company purchased $14.7 million of crude oil on behalf of Dakota Prairie and sold it to Dakota Prairie at cost, which resulted in an immaterial gains each year. There were no receivables due from Dakota Prairie as of December 31, 2016. Pacific New Investment Limited and Shandong Hi-Speed Hainan Development Co., Ltd. On August 5, 2015 , the Company and The Heritage Group (“Heritage Group”), a related party, formed Pacific New Investment Limited (“PACNIL”) for the purpose of investing in a joint venture with Shandong Hi-Speed Materials Group Corporation and China Construction Installation Engineering Co., Ltd. to construct, develop and operate a solvents refinery in mainland China. The joint venture is named Shandong Hi-Speed Hainan Development Co., Ltd. (“Hi-Speed”). The Company invested $4.8 million in June 2016 and $4.8 million in October 2016. As of December 31, 2016, the Company owned an equity interest of approximately 23.8% in PACNIL and through that ownership the Company owned an equity interest of approximately 6% in Hi-Speed. PACNIL formally notified Hi-Speed that it wishes to exit its investment in Hi-Speed. The Company and PACNIL believe they will fully recover their investment in Hi-Speed. The Company accounts for its ownership in PACNIL under the equity method of accounting. As of December 31, 2017 and 2016 , the Company had an investment of $9.6 million in PACNIL, primarily related to the purchase of equity in the Hi-Speed joint venture. Fluid Holding Corp. In connection with the Anchor Transaction, the Company received a 10% investment in FHC as part of the total consideration for Anchor. FHC provides oilfield services and products to customers globally. The Company accounts for its ownership in FHC under the cost method of accounting. As of December 31, 2017 , the Company had an investment of $25.4 million in FHC, which was its estimated fair value using Level 3 inputs as of November 21, 2017. See Note 3 for further information on the Anchor Transaction. 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 were considered Level 3 of the fair value hierarchy. In June 2016, the Company sold its equity interest in New Source Fuels, LLC for an immaterial amount.

Goodwill and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangible Assets	Goodwill and Other Intangible Assets 2017 The Company updated its financial projections in connection with its annual goodwill assessment and determined that its Dickinson reporting unit’s fair value was below its carrying value. An impairment charge of $0.7 million for goodwill related to the specialty products segment was recorded in the consolidated statements of operations within asset impairment. 2016 In April 2016, the board of directors of the Company’s general partner determined to suspend payment of the Company’s quarterly cash distribution to unitholders. The suspension of the quarterly cash distribution caused a sustained decrease in the Company’s common unit price. As a result, the Company determined that these events constituted a triggering event that required the Company to update its financial projections and its goodwill impairment assessment as of April 30, 2016. An impairment charge of $33.4 million for goodwill related to the fuel products segment was 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 and crack spreads. In December 2016, the Missouri reporting unit experienced a significant reduction in orders from a customer of significance which is expected to have an adverse impact on the business. As a result, the Company determined that this event constituted a triggering event that required the Company to update its financial projections and its goodwill impairment assessment in December 2016. An impairment charge of $1.4 million for goodwill related to the specialty products segment was recorded in the consolidated statements of operations within asset impairment. 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, its 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. • 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. 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 for the periods indicated below are as follows (in millions): Specialty Fuel Total Net balance as of December 31, 2015 $ 173.5 $ 38.5 $ 212.0 Impairment (1) (1.4 ) (33.4 ) (34.8 ) Net balance as of December 31, 2016 $ 172.1 $ 5.1 $ 177.2 Impairment (1) (0.7 ) — (0.7 ) Divestiture (2) — (5.1 ) (5.1 ) Net balance as of December 31, 2017 $ 171.4 $ — $ 171.4 (1) Total accumulated goodwill impairment as of December 31, 2017 and 2016 , is $35.5 million and $34.8 million , respectively. (2) Divestiture relates to sale of the Superior Refinery. See Note 4 for additional information. Other intangible assets consist of the following (in millions): Weighted Average Life (Years) December 31, 2017 December 31, 2016 Gross Amount Accumulated Amortization Gross Amount Accumulated Amortization Customer relationships 22 $ 181.3 $ (107.6 ) $ 186.7 $ (97.2 ) Tradenames 11 26.8 (13.8 ) 26.8 (9.9 ) Trade secrets 13 52.7 (35.1 ) 52.7 (29.6 ) Patents 12 1.6 (1.6 ) 1.6 (1.5 ) Royalty agreements 19 6.2 (2.6 ) 6.2 (2.3 ) 19 $ 268.6 $ (160.7 ) $ 274.0 $ (140.5 ) Tradenames, trade secrets, patents 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 to properly match expenses with the undiscounted estimated future cash flows based upon assumed rates of annual customer attrition. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded amortization expense of intangible assets of $24.6 million , $26.9 million and $29.4 million , respectively. As of December 31, 2017 , the Company estimates that amortization of intangible assets for the next five years will be as follows (in millions): Year Amortization Amount 2018 $ 19.9 2019 $ 16.8 2020 $ 14.0 2021 $ 11.5 2022 $ 9.4

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
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, 2017 , 2016 and 2015 was $53.2 million , $56.6 million and $57.6 million , respectively. As of December 31, 2017 , 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 2018 $ 31.4 2019 21.7 2020 16.7 2021 9.5 2022 7.3 Thereafter 10.8 Total $ 97.4 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. 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 $114.0 million . As of December 31, 2017 , 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 2018 $ 297.5 2019 126.7 2020 21.1 2021 21.0 2022 21.0 Thereafter 84.2 Total $ 571.5 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 three months. Based upon this minimum supply quantity, the Company expects to purchase approximately $11.4 million of feedstock for the LVT unit for the term of the contract expiring March 31, 2018 , based on pricing estimates as of December 31, 2017 . 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 regulatory and taxation authorities, such as the EPA, various state environmental regulatory bodies, the Internal Revenue Service, various state and local departments of revenue and the U.S. 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, and such 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 remediated 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 acquisition of the San Antonio refinery, 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. Great Falls Refinery In connection with the acquisition of the Great Falls refinery from Connacher Oil and Gas Limited (“Connacher”), the Company became a party to an existing 2002 Refinery Initiative Consent Decree (the “Great Falls Consent Decree”) with the EPA and the Montana Department of Environmental Quality (the “MDEQ”). The material obligations imposed by the Great Falls 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 Great Falls refinery. The Company believes the majority of damages related to such contamination at the Great Falls refinery are covered by a contractual indemnity provided by HollyFrontier Corporation (“Holly”), the owner and operator of the Great Falls refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Great Falls 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 Great Falls 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 expenditures totaled approximately $18.7 million as of December 31, 2017 , of which $14.6 million was capitalized into the cost of the Company’s recently completed refinery expansion project and $2.4 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 Great Falls refinery under the asset purchase agreement. On November 24, 2015, Holly and the sellers of the Great Falls refinery under the asset purchase agreement filed a motion to dismiss the case pending arbitration. On February 10, 2016, the court ordered that all of the claims be addressed in arbitration. The first phase of the arbitration is scheduled for July 2018. In the event the Company is unsuccessful in the legal dispute with Holly, the Company will be responsible for the remediation expenses. The Company expects that it may incur costs to remediate other environmental conditions at the Great Falls refinery; however, the costs cannot be estimated at this time. 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. 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, Cotton Valley and Princeton 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, as amended (“CAA”), 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 2017 and 2016 , the Company incurred of such capital expenditures approximately $0.7 million and $2.4 million , respectively. The Global Settlement is substantially complete and any remaining capital investment requirements will be incorporated into the Company’s annual capital expenditures budget. The Company does not expect any additional capital expenditures 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. The Company has recorded the $1.0 million liability in the consolidated balance sheets. 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 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 net of amounts internally generated or purchased and the price of those RINs as of the balance sheet date. In February 2017 and in May 2017, the EPA granted certain of the Company’s refineries a “small refinery exemption” under the RFS for the full-year 2016, as provided for under the federal Clean Air Act, as amended (“CAA”). In granting those exemptions, the EPA determined that for the full-year 2016, compliance with the RFS would represent a “disproportionate economic hardship” for these refineries. In October 2016, the EPA granted certain of the Company’s refineries a “small refinery exemption” under the RFS for the full-year 2015, as provided for under the CAA. In granting those exemptions, the EPA determined that for the full-year 2015, compliance with the RFS would represent a “disproportionate economic hardship” for these refineries. In June 2016, the EPA granted certain of the Company’s refineries a “small refinery exemption” under the RFS for the full-year 2014, as provided for under the CAA. In granting those exemptions, the EPA determined that for the full-year 2014, compliance with the RFS would represent a “disproportionate economic hardship” for these refineries. As of December 31, 2017 and 2016 , the Company had a RINs Obligation of $59.1 million and $79.3 million , respectively. Occupational Health and Safety The Company is subject to various laws and regulations relating to occupational health and safety, including the U.S. Occupational Safety and Health Act 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 promote 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. 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 500 employees covered by various collective bargaining agreements, or approximately 31% of its total workforce of approximately 1,600 employees. These agreements have expiration dates of October 31, 2020 , January 31, 2019 , March 31, 2019 and April 30, 2019 . Therefore, the Company has none of its employees who are covered by a collective bargaining agreement which will expire in less than one year and does not expect any work stoppages. Legal Proceedings The Company is subject to 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 the consolidated financial statements but are not individually 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 claims and litigation currently pending cannot be determined, the Company currently does not expect that these proceedings and claims, individually or in the aggregate (including matters for which the Company has recorded accruals), 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. 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, 2017 and 2016 , the Company had outstanding standby letters of credit of $67.3 million and $82.1 million , respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 9 for additional information regarding the Company’s revolving credit facility. At December 31, 2017 and 2016 , 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 ( $900.0 million at December 31, 2017 and December 31, 2016 ) with the consent of the Agent (as defined in the revolving credit agreement). As of December 31, 2017 and 2016 , the Company had availability to issue letters of credit of approximately $252.0 million and approximately $360.8 million , respectively, under its revolving credit facility.

Inventory Financing Agreement I

Inventory Financing Agreement Inventory Financing Agreement	12 Months Ended
	Dec. 31, 2017
Inventory Financing Agreement [Abstract]
Supply And Exchange Agreements [Text Block]	8. Inventory Financing Agreements On March 31, 2017, the Company entered into several agreements with Macquarie to support the operations of the Great Falls refinery (the “Great Falls Supply and Offtake Agreements”). The Great Falls Supply and Offtake Agreements expire on October 31, 2019. On July 27, 2017, the Company amended the Great Falls Supply and Offtake Agreements to provide Macquarie the option to terminate the Great Falls Supply and Offtake Agreements with nine months’ notice any time prior to June 2019. On June 19, 2017, the Company entered into several agreements with Macquarie to support the operations of the Shreveport refinery (the “Shreveport Supply and Offtake Agreements”, and together with the Great Falls Supply and Offtake Agreements, the “Supply and Offtake Agreements”). The Shreveport Supply and Offtake Agreements expire on June 2020; however, Macquarie has the option to terminate the Shreveport Supply and Offtake Agreements with nine months’ notice any time prior to June 2019. At the commencement of the Great Falls Supply and Offtake Agreements, the Company sold to Macquarie inventory comprised of 652,000 barrels of crude oil and refined products valued at $32.2 million . At the commencement of the Shreveport Supply and Offtake Agreements, the Company sold to Macquarie inventory comprised of 987,000 barrels of crude oil and refined products valued at $54.8 million . In addition, the Company incurred approximately $3.1 million of costs related to the Supply and Offtake Agreements. These capitalized costs are recorded in obligations under inventory financing agreements in the Company’s consolidated balance sheets and amortized to interest expense over the term of the agreement. During the terms of the Supply and Offtake Agreements, the Company may purchase crude oil from Macquarie or one of its affiliates. Per the Supply and Offtake Agreements, Macquarie will provide up to 30,000 barrels per day of crude oil to the Great Falls refinery and 60,000 barrels per day of crude oil to the Shreveport refinery. The Company agreed to purchase the crude oil on a just-in-time basis to support the production operations at the Great Falls and Shreveport refineries. Additionally, the Company agreed to sell, and Macquarie agreed to buy, at market prices, refined products produced at the Great Falls and Shreveport refineries. For Shreveport, finished products consisting of finished fuel products (other than jet fuel), lubricants and waxes, Macquarie may (but is not required to) sell such products to the sales intermediation party (“SIP”), and the SIP may (but is not required to) sell such products to Shreveport, as applicable, for sale in turn to third parties. For jet fuel and certain intermediate products, Macquarie may (but is not required to) sell such products to Shreveport for sale thereby to third parties. The Company will then repurchase the refined products from Macquarie or the SIP prior to selling the refined products to third parties. The Supply and Offtake Agreements are subject to minimum and maximum inventory levels. The agreements also provide for the lease to Macquarie of crude oil and certain refined product storage tanks located at the Great Falls and Shreveport refineries and certain offsite locations. Following expiration or termination of the agreements, Macquarie has the option to require the Company to purchase the crude oil and refined product inventories then owned by Macquarie and located at the leased storage tanks at then current market prices. In addition, barrels owned by the Company are pledged as collateral to support the Deferred Payment Arrangement (defined below) obligations under these agreements. While title to certain inventories will reside with Macquarie, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to Macquarie will continue to be included in the Company’s consolidated balance sheets until processed and sold to a third party. Each reporting period, the Company will record liabilities in an amount equal to the amount the Company expects to pay to repurchase the inventory held by Macquarie based on market prices at the termination date included in obligations under inventory financing agreements in the consolidated balance sheets. The Company has determined that the redemption feature on the initially recognized liabilities related to the Supply and Offtake Agreements is an embedded derivative indexed to commodity prices. As such, the Company has accounted for these embedded derivatives at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s consolidated statements of operations. For more information on the valuation of the associated derivatives, see Note 10 - “ Derivatives ” and Note 11 - “ Fair Value Measurements .” The embedded derivatives will be recorded in obligations under inventory financing agreements on the consolidated balance sheets. The cash flow impact of the embedded derivatives will be classified as a change in derivative activity in the financing activities section in the consolidated statements of cash flows. For the year ended December 31, 2017 , the Company incurred $6.8 million of financing costs related to the Supply and Offtake Agreements, which are included in interest expense in the Company’s consolidated statements of operations. The Company has provided collateral of $4.0 million related to the initial purchase of the Great Falls and Shreveport inventory to cover credit risk for future crude oil deliveries and potential liquidation risk if Macquarie exercises its rights and sells the inventory to third parties. The collateral was recorded as a reduction to the obligations under inventory financing agreements pursuant to a master netting agreement. The Supply and Offtake Agreements also include a deferred payment arrangement (“Deferred Payment Arrangement”) whereby the Company can defer payments on just-in-time crude oil purchases from Macquarie owed under the agreements up to the value of the collateral provided ( 90% of the collateral inventory). The deferred amounts under the deferred payment arrangement will bear interest at a rate equal to LIBOR plus 3.25% per annum for both Shreveport and Great Falls. Amounts outstanding under the Deferred Payment Arrangement are included in obligations under inventory financing agreements in the Company’s consolidated balance sheets. Changes in the amount outstanding under the Deferred Payment Arrangement are included within cash flows from financing activities on the consolidated statements of cash flows. As of the year ended December 31, 2017 , the capacity of the Deferred Payment Arrangement was $17.8 million and the Company had $11.3 million deferred payments outstanding.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
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 8.4% and 4.8% at December 31, 2017 and 2016, respectively $ 0.2 $ 10.2 Borrowings under 2021 Secured Notes, interest at a fixed rate of 11.5%, interest payments semiannually, borrowings due January 2021, effective interest rates of 12.3% and 12.2% for the year ended December 31, 2017 and 2016, respectively 400.0 400.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.5%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for each year ended December 31, 2017 and 2016 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, 2017 and 2016 (1) 352.1 352.5 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 each year ended December 31, 2017 and 2016 325.0 325.0 Other 6.6 8.0 Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034 44.0 46.5 Less unamortized debt issuance costs (2) (25.9 ) (33.2 ) Less unamortized discounts (9.7 ) (11.8 ) Total long-term debt 1,992.3 1,997.2 Less current portion of long-term debt (3) 354.1 3.5 $ 1,638.2 $ 1,993.7 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.1 million and $2.5 million as of December 31, 2017 and 2016 , respectively. (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 $21.8 million and $14.5 million at December 31, 2017 and 2016 , respectively. (3) The sale of the Superior Refinery resulted in $350.0 million of restricted cash and was based upon the value of collateral under the Company’s debt agreements. Under the indentures governing the Company’s senior notes, proceeds from Asset Sales (as defined in the indentures) can only be used for, among other things, to repay, redeem or repurchase debt; to make certain acquisitions or investments; and to make capital expenditures. These proceeds need to be used within one year of the Asset Sales (as defined in the indentures) and as such were recorded as current. Senior Notes 11.50% Senior Secured Notes (the “2021 Secured Notes”) On April 20, 2016 , the Company issued and sold $400.0 million in aggregate principal amount of 11.50% Senior Secured Notes due January 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 a discounted price of 98.273 percent of par. Subject to certain exceptions, the 2021 Secured Notes are secured by a lien on all of the fixed assets that secure the Company’s obligations under its secured hedge agreements, including certain present and future real property, fixtures and equipment; all U.S. registered patents and patent license rights, trademarks and trademark license rights, copyrights and copyright license rights and trade secrets; chattel paper, documents and instruments; certain cash deposits in the property, plant and equipment proceeds account; certain books and records; and all accessions and proceeds of any of the foregoing. The Company received net proceeds of approximately $382.5 million net of discount, initial purchasers’ fees and estimated expenses, which it used to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at its facilities and working capital. Interest on the 2021 Secured Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2016. 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, to eligible purchasers at a discounted price of 99.257 percent of par. 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 9.625% senior notes due 2020 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. 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 was completed on March 7, 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, 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 ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc. (subsequently converted to ADF Holdings, LLC and Anchor Drilling Fluids USA, LLC), the redemption of $500.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019 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. 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 Company received net proceeds of approximately $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, the purchase price of the Bel-Ray acquisition and the redemption of $100.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019. Interest on the 2022 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2014. 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. 2021 Secured Notes, 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 Secured, 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 Secured, 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 Secured, 2021, 2022 and 2023 Notes. The indentures governing the 2021 Secured, 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 or, in the case of the 2021 Secured Notes, its unsecured notes; (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 Secured, 2021, 2022 and 2023 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or S&P Global Ratings (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of December 31, 2017 , the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes) was 1.7 . As of December 31, 2017 , the Company was in compliance with all covenants under the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes. Second Amended and Restated Senior Secured Revolving Credit Facility The Company has a $900.0 million senior secured revolving credit facility, subject to borrowing base limitations, which includes a $500.0 million incremental uncommitted expansion feature. Refer to Note 21 for additional information regarding the Company’s revolving credit facility. 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, as of December 31, 2017 , bore interest at a rate equal to either the prime rate plus a basis points margin or the London Interbank Offered Rate (“LIBOR”) plus a basis points margin, at the Company’s option. As of December 31, 2017 , the margin was 50 basis points for prime rate loans and 150 basis points for LIBOR rate loans; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding fiscal 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, 2017 , under the revolving credit facility was approximately $319.0 million . As of December 31, 2017 , the Company had $0.2 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $67.3 million , leaving approximately $252.0 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 (collectively, the “Credit Agreement Collateral”). On April 20, 2016, the Company and certain of its operating subsidiaries as borrowers (collectively, the “Borrowers”) entered into a Second Amendment to Second Amended and Restated Credit Agreement (the “Second Amendment”), by and among the Borrowers, the Agent (as defined below) and the lenders party thereto (including Bank of America, N.A.), amending the Company’s revolving credit facility. The Second Amendment, among other things, amended the revolving credit facility to permit (a) the issuance of the 2021 Secured Notes pursuant to the indenture governing the 2021 Secured Notes and (b) such 2021 Secured Notes to be secured by a lien on the Fixed Asset Collateral (as defined in the Intercreditor Agreement), subject to the terms of the Intercreditor Agreement. On March 31, 2017, the Company amended its revolving credit facility to allow for the entry into the Supply and Offtake Agreements at the Great Falls refinery. The amendment resulted in the release of certain Eligible Inventory (as defined in the revolving credit agreement) from the revolving credit facility as that inventory is now collateral under the Supply and Offtake Agreements. For additional discussion of the Supply and Offtake Agreements, refer to Note 8 . 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 (which amount is subject to increase in proportion to revolving commitment increases), 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 until availability under the revolving credit facility exceeds the greater of the foregoing amounts for 30 consecutive days . See Note 21 for details of the third amended and restated credit agreement. As of December 31, 2017 , 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, 2017 . 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 In connection with the private placement of the 2021 Secured Notes, on April 20, 2016, the Company entered into an amended and restated collateral trust agreement (the “Collateral Trust Agreement”) which governs how the holders of the 2021 Secured Notes and secured hedging counterparties share collateral pledged as security for the payment obligations owed by it to the holders of the 2021 Secured Notes and secured hedging counterparties under their respective master derivatives contracts. The Collateral Trust Agreement limits to $150.0 million the extent to which forward purchase contracts for physical commodities are covered by, and secured under, the Collateral Trust Agreement and the Parity Lien Security Documents (as defined in 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. Intercreditor Agreement The 2021 Secured Notes are not secured by the collateral securing the Company’s revolving credit facility. In connection with the offering of the 2021 Secured Notes, the Collateral Trustee entered into a Second Amended and Restated Intercreditor Agreement (the “Intercreditor Agreement”) among the Collateral Trustee, as fixed asset collateral trustee, Bank of America, N.A., as agent for the lenders under the Company’s revolving credit facility (in such capacity, the “Agent”), the Company and the other grantors named therein, providing for certain access and administrative agreements with respect to the Credit Agreement Collateral and the Fixed Asset Collateral (as defined in the Intercreditor Agreement). Related Party Note Payable On December 30, 2015, the Company entered into an agreement with The Heritage Group, an affiliate of the Company’s general partner, in which The Heritage Group 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 bore interest of 6.0% , with interest payments due on March 31, 2016, June 30, 2016, and July 31, 2016. Principal payments of $15.0 million each were due on May 31, 2016 and June 30, 2016, with the remaining principal amount due before July 31, 2016. The unsecured note payable and the uncommitted prepayment were fully repaid in 2016. The proceeds were used for general partnership purposes. Capital Leases Assets recorded under capital lease obligations are included in property, plant and equipment and total $18.2 million and $51.3 million as of December 31, 2017 and 2016 , respectively. As of December 31, 2017 and 2016 , the Company had recorded $11.4 million and $7.5 million , respectively, in accumulated depreciation for 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 gross obligation under this capital lease agreement as of December 31, 2017 and 2016 was $39.4 million . Total depreciation expense for this lease during each of the years ended December 31, 2017 and 2016 , was $2.0 million . As of December 31, 2017 , the Company had estimated minimum commitments for the payment of total rentals under capital leases relating to continuing and discontinued operations as follows (in millions): Year Capital Leases 2018 $ 9.0 2019 7.4 2020 6.9 2021 6.9 2022 6.9 Thereafter 82.1 Total minimum lease payments 119.2 Less amount representing interest 75.2 Capital lease obligations 44.0 Less obligations due within one year 2.7 Long-term capital lease obligations $ 41.3 Maturities of Long-Term Debt As of December 31, 2017 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2018 $ 354.1 2019 2.9 2020 2.4 2021 953.3 2022 351.2 Thereafter 361.9 Total $ 2,025.8

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2017
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, options and futures, 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 New York Mercantile Exchange 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 and 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 its risk profiles. Such 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 is obligated to repurchase crude oil and refined products from Macquarie at the termination of the Supply and Offtake Agreements in certain scenarios. The Company has determined that the redemption feature on the initially recognized liability related to the Supply and Offtake Agreements is an embedded derivative indexed to commodity prices. As such, the Company has accounted for this embedded derivative at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s consolidated statement of operations. The Company recognizes all derivative instruments at their fair values (see Note 11 ) 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 (in millions): December 31, 2017 December 31, 2016 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 not designated as hedges: Specialty products segment: Natural gas swaps $ — $ — $ — $ 0.1 $ (0.1 ) $ — Fuel products segment: Crude oil swaps 0.3 (0.3 ) — 10.3 (7.4 ) 2.9 Crude oil basis swaps — — — — (2.1 ) (2.1 ) Crude oil percentage basis swaps — — — 0.1 (0.1 ) — Total derivative instruments $ 0.3 $ (0.3 ) $ — $ 10.5 $ (9.7 ) $ 0.8 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 (in millions): December 31, 2017 December 31, 2016 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 not designated as hedges: Specialty products segment: Natural gas swaps $ — $ — $ — $ (1.2 ) $ 0.1 $ (1.1 ) Fuel products segment: Inventory financing obligation (4.4 ) — (4.4 ) — — — Crude oil swaps — 0.3 0.3 (8.2 ) 7.4 (0.8 ) Crude oil basis swaps — — — (7.1 ) 2.1 (5.0 ) Crude oil percentage basis swaps — — — (0.6 ) 0.1 (0.5 ) Gasoline swaps (0.2 ) — (0.2 ) — — — Gasoline crack spread swaps (1.8 ) — (1.8 ) (3.5 ) — (3.5 ) Diesel swaps (0.2 ) — (0.2 ) — — — Diesel crack spread swaps (4.1 ) — (4.1 ) (1.4 ) — (1.4 ) 2/1/1 crack spread swaps — — — (2.5 ) — (2.5 ) Total derivative instruments $ (10.7 ) $ 0.3 $ (10.4 ) $ (24.5 ) $ 9.7 $ (14.8 ) 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, 2017 , the Company had no counterparty relationship in which the derivatives held were net assets. As of December 31, 2016 , the Company had one counterparty in which the derivatives held were net assets. 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 A3 and BBB+ by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark-to-market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed-upon thresholds in its master derivative contracts with these counterparties. No such collateral was held by the Company as of December 31, 2017 or 2016 . Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in prepaid expenses and other current assets 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, 2017 and 2016 , 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 Prior to 2017, the Company accounted for certain derivatives hedging purchases of crude oil and sales of gasoline and diesel as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases were 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. During 2016, the Company reclassified a net gain of $6.4 million from other accumulated other comprehensive loss to net loss. There was no such activity in 2017. 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 natural gas collars, natural gas swaps and certain other crude oil swaps that do not qualify as cash flow hedges for accounting purposes. However, these instruments provide economic hedges of the Company’s crude oil and natural gas purchases and gasoline and diesel sales. The Company recorded the following gains (losses) in its consolidated statements of operations related to its derivative instruments not designated as hedges (in millions): Amount of Gain (Loss) Recognized in Realized Loss on Derivative Instruments Amount of Gain (Loss) Recognized in Unrealized Gain on Derivative Instruments Year Ended December 31, Year Ended December 31, Type of Derivative 2017 2016 2017 2016 Specialty products segment: Natural gas swaps $ (3.6 ) $ (11.3 ) $ 1.0 $ 14.7 Fuel products segment: Inventory financing obligation — — (4.4 ) — Crude oil swaps (1.9 ) 5.3 (1.7 ) 7.3 Crude oil basis swaps 3.2 (4.1 ) 7.1 (5.9 ) Crude oil percentage basis swaps 2.3 (4.3 ) 0.5 5.4 Crude oil options — (2.6 ) — 0.3 Crude oil futures — (2.0 ) — — Gasoline swaps (0.6 ) — (0.2 ) — Gasoline crack spread swaps (6.2 ) (2.5 ) 3.0 (0.5 ) Diesel swaps (0.5 ) — (0.2 ) — Diesel crack spread swaps (5.0 ) (0.4 ) (1.5 ) (2.7 ) 2/1/1 crack spread swaps (0.9 ) (0.8 ) — — Natural gas swaps — (1.3 ) — 1.3 Total $ (13.2 ) $ (24.0 ) $ 3.6 $ 19.9 Derivative Positions — Specialty Products Segment Natural Gas Swap Contracts At December 31, 2016 , 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 2017 1,350,000 $ 3.88 Second Quarter 2017 1,320,000 $ 3.87 Third Quarter 2017 1,320,000 $ 3.87 Fourth Quarter 2017 960,000 $ 3.72 Total 4,950,000 Average price $ 3.85 Derivative Positions — Fuel Products Segment Crude Oil Swap Contracts At December 31, 2017 , 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 2018 28,000 311 $ 48.25 Total 28,000 Average price $ 48.25 At December 31, 2016 , 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 BPD Average Swap First Quarter 2017 320,049 3,556 $ 48.87 Second Quarter 2017 323,605 3,556 $ 48.87 Third Quarter 2017 327,161 3,556 $ 48.87 Fourth Quarter 2017 327,161 3,556 $ 48.87 Total 1,297,976 Average price $ 48.87 At December 31, 2016 , 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 2017 130,320 1,448 $ 41.56 Second Quarter 2017 131,768 1,448 $ 41.56 Third Quarter 2017 133,216 1,448 $ 41.56 Fourth Quarter 2017 133,216 1,448 $ 41.56 Total 528,520 Average price $ 41.56 Crude Oil Basis Swap Contracts The Company entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At December 31, 2016 , 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 2017 630,000 7,000 $ (13.22 ) Second Quarter 2017 637,000 7,000 $ (13.22 ) Third Quarter 2017 644,000 7,000 $ (13.22 ) Fourth Quarter 2017 644,000 7,000 $ (13.22 ) Total 2,555,000 Average differential $ (13.22 ) Crude Oil Percentage Basis Swap Contracts The Company entered into derivative instruments to secure a percentage differential of WCS crude oil to NYMEX WTI. At December 31, 2016 , 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) First Quarter 2017 270,000 3,000 72.3 % Second Quarter 2017 273,000 3,000 72.3 % Third Quarter 2017 276,000 3,000 72.3 % Fourth Quarter 2017 276,000 3,000 72.3 % Total 1,095,000 Average percentage 72.3 % Gasoline Crack Spread Swap Contracts At December 31, 2017 , 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 2018 826,000 9,178 $ 12.27 Total 826,000 Average price $ 12.27 At December 31, 2016 , 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 2017 590,000 6,556 $ 10.21 Total 590,000 Average price $ 10.21 Gasoline Swap Contracts At December 31, 2017 , 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 First Quarter 2018 14,000 156 $ 61.35 Totals 14,000 Average price $ 61.35 Diesel Crack Spread Swap Contracts At December 31, 2017 , the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges: Diesel Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2018 826,000 9,178 $ 17.58 Total 826,000 Average price $ 17.58 At December 31, 2016 , the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges: Diesel Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2017 590,000 6,556 $ 13.67 Total 590,000 Average price $ 13.67 Diesel Swap Contracts At December 31, 2017 , 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 2018 14,000 156 $ 66.35 Totals 14,000 Average price $ 66.35 2/1/1 Crack Spread Swap Contracts At December 31, 2016 , the Company had the following derivatives related to 2/1/1 crack spread sales in its fuel products segment, none of which are designated as hedges: 2/1/1 Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2017 590,000 6,556 $ 11.91 Total 590,000 Average price $ 11.91

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
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 A3 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. 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 counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. As a result of applying the applicable CVA at December 31, 2017 , the Company’s net liabilities changed by an immaterial amount. As a result of applying the CVA at December 31, 2016 , the Company’s net assets were increased by less than $0.1 million and net liabilities were reduced by approximately $0.5 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 10 for further information on derivative instruments. Pension Assets Pension assets are reported at fair value in the accompanying consolidated financial statements. At December 31, 2017 , the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds 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 respective investment sponsors or investment advisers. Plan investments can be redeemed within a short time frame (10 or so business days), if requested. See Note 14 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 is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service. See Note 7 for further information on the Company’s RINs Obligation. Hierarchy of Recurring Fair Value Measurements The Company’s recurring assets and liabilities measured at fair value were as follows (in millions): December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Crude oil swaps $ — $ — $ — $ — $ — $ — $ 2.9 $ 2.9 Crude oil basis swaps — — — — — — (2.1 ) (2.1 ) Total derivative assets — — — — — — 0.8 0.8 Pension Plan investments 0.2 — — 0.2 0.3 — — 0.3 Total recurring assets at fair value $ 0.2 $ — $ — $ 0.2 $ 0.3 $ — $ 0.8 $ 1.1 Liabilities: Derivative liabilities: Inventory financing obligation $ — $ — $ (4.4 ) $ (4.4 ) $ — $ — $ — $ — Crude oil swaps — — 0.3 0.3 — — (0.8 ) (0.8 ) Crude oil basis swaps — — — — — — (5.0 ) (5.0 ) Crude oil percentage basis swaps — — — — — — (0.5 ) (0.5 ) Gasoline crack spread swaps — — (1.8 ) (1.8 ) — — (3.5 ) (3.5 ) Gasoline swaps — — (0.2 ) (0.2 ) — — — — 2/1/1 crack spread swaps — — — — — — (2.5 ) (2.5 ) Diesel swaps — — (0.2 ) (0.2 ) — — — — Diesel crack spread swaps — — (4.1 ) (4.1 ) — — (1.4 ) (1.4 ) Natural gas swaps — — — — — — (1.1 ) (1.1 ) Total derivative liabilities — — (10.4 ) (10.4 ) — — (14.8 ) (14.8 ) RINs Obligation — (59.1 ) — (59.1 ) — (79.3 ) — (79.3 ) Liability Awards (5.6 ) — — (5.6 ) — — — — Total recurring liabilities at fair value $ (5.6 ) $ (59.1 ) $ (10.4 ) $ (75.1 ) $ — $ (79.3 ) $ (14.8 ) $ (94.1 ) The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities (in millions): For the Year Ended December 31, 2017 2016 Fair value at January 1, $ (14.0 ) $ (33.9 ) Realized loss on derivative instruments 13.2 24.0 Unrealized gain on derivative instruments 3.6 19.9 Settlements (13.2 ) (24.0 ) Fair value at December 31, $ (10.4 ) $ (14.0 ) Total gain included in net loss attributable to changes in unrealized gain relating to financial assets and liabilities held as of December 31, $ 3.6 $ 19.9 All settlements from derivative instruments not designated as hedges are recorded in gain (loss) on derivative instruments in the consolidated statements of operations. See Note 10 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. The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 6 for further information on goodwill impairment. The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was required to measure and record such assets at fair value within its consolidated financial statements. See Note 2 for further information on long-lived asset impairment. The Company received an equity interest in FHC in connection with the Anchor Transaction. The Company recorded the FHC investment at its estimated fair value as of November 21, 2017 using Level 3 inputs. 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 company. Estimated Fair Value of Financial Instruments Cash, cash equivalents and restricted cash The carrying value of cash, cash equivalents and restricted cash is each considered to be representative of its fair value. Debt The estimated fair value of long-term debt at December 31, 2017 and 2016 , consists primarily of senior notes. 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 secured 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, capital lease obligations, related party note payable and other obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 9 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, were as follows (in millions): December 31, 2017 December 31, 2016 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,576.5 $ 1,556.4 $ 1,334.1 $ 1,552.2 Senior notes 2 $ 456.4 $ 387.6 $ 458.8 $ 384.5 Revolving credit facility 3 $ 0.2 $ 0.2 $ 6.0 $ 6.0 Capital lease and other obligations 3 $ 50.6 $ 50.6 $ 54.5 $ 54.5

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Partners' Capital	Partners’ Capital Units Outstanding Of the 76,788,801 common units outstanding at December 31, 2017 , 60,422,882 common units were held by the public, with the remaining 16,365,919 common units held by the Company’s affiliates (including members of the Company’s general partner and their families). 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 (which amount is subject to increase in proportion to revolving commitment increases). 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 (which amount is subject to increase in proportion to revolving commitment increases), 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 until availability under the revolving credit facility exceeds the greater of the foregoing amounts for 30 consecutive days. The indenture governing the 2021 Secured Notes, which is the most restrictive indenture, provides that if the Company’s Fixed Charge Coverage Ratio (as defined in the indenture) for the most recently ended four full fiscal quarters is not less than 2.25 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 indenture. If the Company’s Fixed Charge Coverage Ratio for the most recently ended four full fiscal quarters is less than 2.25 to 1.0 but greater than 1.50 to 1.0 , the Company will be able to pay distributions to its unitholders up to an amount equal to a $50.0 million basket. If the Company’s Fixed Charge Coverage Ratio is not greater than 1.50 to 1.0 , the Company will be able to pay distributions to its unitholders in an amount less than Incremental Funds (as defined in the indenture) not previously expended for such distributions. The indenture related to the 2021 Secured Notes is outlined above as it remains the most restrictive of all senior notes indentures with respect to unitholder distributions. The Company’s distribution policy is as defined in its partnership agreement. In April 2016, the board of directors of the Company’s general partner determined to suspend payment of the Company’s quarterly cash distribution to unitholders. The board of directors of the Company’s general partner will continue to evaluate the Company’s ability to reinstate the quarterly cash distribution. The Company made no distributions to its partners for the year ended December 31, 2017 . For the years ended December 31, 2016 and 2015 , the Company made distributions of $57.4 million and $224.6 million , respectively, to its partners. For the years ended December 31, 2017 and 2016 , the general partner was allocated no incentive distribution rights. For the year ended 2015 , the general partner was allocated $16.8 million in incentive distribution rights.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2017
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. 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 at that point were modified to value the awards based upon the closing unit price on that date. This modification did not affect the remaining service period. Phantom Units 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 2016 and 2015 . These phantom units have a four year service period with one-quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant. For the years ended December 31, 2017 , 2016 and 2015 named executive officers were awarded phantom units under the terms of the LTIP, as part of certain employment agreements and arrangements and as part of the Company’s achievement of specified levels of financial performance in fiscal years 2017 and 2015. These phantom units are subject to time-vesting requirements whereby either 25% of the units vest during the fiscal year, and the remainder will vest ratably over the next three years on each December 31 or 100% of the phantom units vest in three years. 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. Performance Units In 2017, the Company granted certain named executive officers and other executives performance units with market performance conditions. The award is eligible to vest during the period commencing January 1, 2017 and ending December 31, 2020. A portion of the performance units are equity-classified awards, in which the fair value was determined on the grant date by application of the Monte Carlo simulation model. In addition, a portion of the performance units are liability-classified awards and the fair value was determined by the market price of the Company’s common units on the grant date to calculate. The Company amortizes this compensation over the service period only if the performance condition is considered probable of occurring. A summary of the Company’s non-vested phantom units and performance units as of December 31, 2017 , and the changes during the years ended December 31, 2017 , 2016 and 2015 , are presented below: Number of Phantom Units Weighted-Average Grant Date Fair Value Nonvested at January 1, 2015 502,120 $ 26.48 Granted 343,533 21.70 Vested (321,741 ) 23.54 Forfeited (103,188 ) 23.94 Nonvested at December 31, 2015 420,724 $ 24.27 Granted 1,880,094 4.57 Vested (1,455,131 ) 6.35 Forfeited (90,854 ) 14.82 Nonvested at December 31, 2016 754,833 $ 9.58 Granted 2,753,507 4.10 Vested (925,199 ) 7.30 Forfeited (47,363 ) 9.73 Nonvested at December 31, 2017 2,535,778 $ 3.11 For the years ended December 31, 2017 , 2016 and 2015 , compensation expense of $11.6 million , $5.6 million and $7.5 million , respectively, was recognized in the consolidated statements of operations related to vested phantom unit grants, including $7.0 million and $5.0 million , attributable to Liability Awards for the years ended December 31, 2017 and 2015 . There was no compensation expense attributable to Liability Awards for the year ended December 31, 2016 . As of December 31, 2017 and 2016 , there was a total of $7.9 million and $7.2 million , respectively, of unrecognized compensation costs related to non-vested phantom unit grants, including $3.3 million , attributable to Liability Awards for the year ended December 31, 2017 . These costs are expected to be recognized over a weighted-average period of approximately 2 years. The total fair value of phantom units vested during the years ended December 31, 2017 , 2016 and 2015 , was $7.2 million , $5.8 million and $7.0 million , respectively.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [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 expense in the consolidated statement of operations (in millions): Year Ended December 31, 2017 2016 2015 401(k) Plan matching contribution expense $ 5.7 $ 6.0 $ 5.0 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”) or (ii) were formerly employees of Montana Refining Company, Inc. and who became employees of the Company as a result of the acquisition of the Great Falls refinery on October 1, 2012 (the “Great Falls Pension Plan” and together with the Penreco Pension Plan, the “Pension Plan”). The Company sold the Superior Refinery in 2017 and Husky assumed the retirement plan covering the Superior employees. Therefore, during 2017, the pension benefit obligation was reduced and certain applicable retirement plan assets were distributed to Husky related to the plan liabilities assumed by Husky. As a result of the completion of the sale of Superior Refinery, the Company was required to remeasure certain pension plan obligations, which resulted in immaterial impact to the consolidated statement of operations. During 2017 , the Company made contributions of $2.3 million to its Pension Plan and expects to make less than $0.1 million in 2018 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 Great Falls 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 acquisition of the Great Falls refinery, 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 Great Falls Pension Plan, which curtailed the collective bargaining employees from accumulating additional benefits subsequent to December 31, 2015. As a result, the Company recorded $0.9 million curtailment gain for the year ended December 31, 2015. The Company recorded no curtailment gain for the years ended December 31, 2017 and December 31, 2016 . 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”) or USW, 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”). 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. The long-term accrued benefit obligation recognized in the consolidated balance sheets for the Penreco Other Plan was $0.2 million as of December 31, 2017 and 2016 . In addition, there was no other post-retirement benefit income related to this plan for years ended December 31, 2017 and 2016 . 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, 2017 2016 Change in projected benefit obligation: Benefit obligation at beginning of year $ 60.9 $ 60.3 Service cost 0.1 0.1 Interest cost 2.3 2.5 Plan settlements — (0.6 ) Benefit payments (2.5 ) (2.5 ) Actuarial loss 4.2 1.1 Reduction due to sale of the Superior Refinery (26.6 ) — Administrative expense (0.1 ) — Benefit obligation at end of year $ 38.3 $ 60.9 Change in plan assets: Fair value of plan assets at beginning of year $ 49.8 $ 47.5 Plan settlements — (0.6 ) Benefit payments (2.5 ) (2.5 ) Actual return on assets 7.4 3.8 Employer contribution 2.3 1.6 Administrative expense $ (0.1 ) $ — Distribution to acquirer of the Superior Refinery (21.5 ) — Fair value of plan assets at end of year $ 35.4 $ 49.8 Funded status — benefit obligation in excess of plan assets $ (2.9 ) $ (11.1 ) Reconciliation of amounts recognized in the consolidated balance sheets: Accrued benefit obligation, long-term $ (2.9 ) $ (11.1 ) Unrecognized net actuarial loss 6.0 7.1 Accumulated other comprehensive loss 6.0 7.1 Net amount recognized at end of year $ 3.1 $ (4.0 ) The accumulated benefit obligation for the Pension Plan was $38.3 million and $60.9 million as of December 31, 2017 and 2016 , respectively. Selected information for the Company’s Pension Plan with an accumulated benefit obligation in excess of plan assets were as follows (in millions): Year Ended December 31, 2017 2016 Accumulated benefit obligation $ 38.3 $ 60.9 Fair value of plan assets $ 35.4 $ 49.8 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, 2017 2016 Projected benefit obligation $ 38.3 $ 60.9 Fair value of plan assets $ 35.4 $ 49.8 The components of net periodic benefit cost (income) were as follows (in millions): Pension Plan Year Ended December 31, 2017 2016 2015 Service cost $ 0.1 $ 0.1 $ 0.5 Interest cost 2.3 2.5 2.6 Expected return on assets (2.9 ) (3.2 ) (3.3 ) Amortization of net loss 0.2 0.1 0.8 Settlement loss recognized 0.7 — — Curtailment gain recognized — — (0.9 ) Net periodic benefit cost (income) $ 0.4 $ (0.5 ) $ (0.3 ) The components of changes recognized in other comprehensive (income) loss for the Pension Plan were as follows (in millions): Pension Plan Year Ended December 31, 2017 2016 2015 Changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net (gain) loss $ (0.2 ) $ 0.4 $ (4.3 ) Amounts recognized as a component of net periodic benefit cost: Amortization or settlement recognition of net loss (0.9 ) (0.1 ) (0.8 ) Total recognized in other comprehensive (income) loss $ (1.1 ) $ 0.3 $ (5.1 ) The portion relating to the Pension Plan classified in accumulated other comprehensive loss includes losses of $6.0 million and $7.1 million as of December 31, 2017 and 2016 , respectively. In 2018 , the estimated amount that will be amortized from accumulated other comprehensive loss includes a net loss of $0.1 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, 2017 and 2016 , were as follows: Benefit Obligations Assumptions 2017 2016 Discount rate for Penreco Pension Plan 3.56 % 4.08 % Discount rate for Superior Pension Plan N/A 4.06 % Discount rate for Great Falls Pension Plan 3.54 % 4.04 % The significant weighted average assumptions used to determine the net periodic benefit cost (income) for the years ended December 31, 2017 , 2016 and 2015 were as follows: Net Periodic Benefit (Income) Cost Assumptions 2017 2016 2015 Discount rate for Penreco Pension Plan 4.08 % 4.30 % 3.92 % Discount rate for Superior Pension Plan 4.06 % 4.27 % 3.86 % Discount rate for Great Falls Pension Plan 4.04 % 4.21 % 4.13 % Expected return on plan assets for Penreco Pension Plan (1) 6.35 % 6.75 % 6.75 % Expected return on plan assets Superior Pension Plan (1) 6.35 % 6.75 % 6.75 % Expected return on plan assets for Great Falls Pension Plan (1) 6.35 % 6.75 % 6.75 % Rate of compensation increase for Great Falls Pension Plan N/A N/A 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 Target 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, 2017 and 2016 , by asset category, are as follows: 2017 2016 Cash and cash equivalents 1 % 1 % Domestic equities 12 % 17 % Foreign equities 12 % 17 % Fixed income 75 % 65 % 100 % 100 % At December 31, 2017 , the Company’s investments associated with its Pension Plan primarily consisted of (i) cash and cash equivalents and (ii) mutual funds. Mutual funds are valued based on the NAV per share (or its equivalent) as a practical expedient to estimate fair value due to the absence of readily available market prices. NAV’s are provided by the respective investment sponsors or investment advisers and are subsequently reviewed and approved by management. In the event management concludes a reported NAV does not reflect fair value or is not determined as of the financial reporting measurement date, the Company will consider whether and when deemed necessary to make an adjustment at the balance sheet date. In determining whether an adjustment to the external valuation is required, the Company will review material factors that could affect the valuation, such as changes to the composition or performance of the underlying investments or comparable investments, overall market conditions, expected sale prices for private investments which are probable of being sold in the short-term and other economic factors that may possibly have a favorable or unfavorable effect on the reported external valuation. See Note 11 for the definition of Level 1. The Company’s Pension Plan assets measured at fair value, were as follows (in millions): Fair Value of Pension Assets at December 31, 2017 2016 Level 1 Total Level 1 Total Cash and cash equivalents $ 0.2 $ 0.2 $ 0.3 $ 0.3 Total plan assets subject to leveling $ 0.2 0.2 $ 0.3 0.3 Plan assets measured at net asset value Domestic equities 4.3 8.6 Foreign equities 4.4 8.7 Fixed income 26.5 32.2 Total plan assets measured at net asset value 35.2 49.5 Total plan assets $ 35.4 $ 49.8 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, 2017 (in millions): Pension Benefits 2018 $ 1.6 2019 1.7 2020 1.8 2021 1.9 2022 1.9 2023 to 2027 10.7 Total $ 19.6

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Comprehensive Income (Loss) Note	Accumulated Other Comprehensive Income (Loss) The table below sets forth a summary of changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2017 and 2016 (in millions): Derivatives Defined Benefit Pension And Retiree Health Benefit Plans Foreign Currency Translation Adjustment Total Accumulated other comprehensive income (loss) at December 31, 2015 $ 6.4 $ (6.8 ) $ (1.2 ) $ (1.6 ) Other comprehensive loss before reclassifications — (0.4 ) — (0.4 ) Amounts reclassified from accumulated other comprehensive income (loss) (6.4 ) 0.1 — (6.3 ) Net current period other comprehensive loss (6.4 ) (0.3 ) — (6.7 ) Accumulated other comprehensive loss at December 31, 2016 $ — $ (7.1 ) $ (1.2 ) $ (8.3 ) Other comprehensive income before reclassifications — 0.2 — 0.2 Amounts reclassified from accumulated other comprehensive loss — 0.9 — 0.9 Net current period other comprehensive income — 1.1 — 1.1 Accumulated other comprehensive loss at December 31, 2017 $ — $ (6.0 ) $ (1.2 ) $ (7.2 ) The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive loss in the Company’s consolidated statements of operations for the years ended December 31, 2017 and 2016 (in millions): Components of Accumulated Other Comprehensive Loss 2017 2016 Location of Gain (Loss) Derivative gains (losses) reflected in gross profit $ — $ 59.7 Sales — (53.3 ) Cost of sales $ — $ 6.4 Total Amortization of defined benefit pension benefit plans: Amortization or settlement recognition of net loss $ (0.9 ) $ (0.1 ) (1) $ (0.9 ) $ (0.1 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 14 for additional information.

Income Taxes Income Taxes

Income Taxes Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	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 immaterial, 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. On December 22, 2017, the President of the United States signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since the operations of a partnership are not subject to federal income tax, and most provisions of the Tax Act are effective for tax years beginning after December 31, 2017, the legislation has no material impact to the Company for 2017. The Company is in the process of analyzing the Tax Act and its possible effect going forward, as it will impact allocations to unitholders. For the year ended December 31, 2017 , an income tax benefit of $0.1 million , as compared to an income tax expense of $0.2 million for the years ended December 31, 2016 and 2015 . As a result of the Company’s analysis, management has determined that the Company does not have any uncertain tax positions.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2017
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 (in millions, except unit and per unit data): Year Ended December 31, 2017 2016 2015 Numerator for basic and diluted earnings per limited partner unit: Net loss from continuing operations $ (31.3 ) $ (296.8 ) $ (85.4 ) Less: General partner’s interest in net loss from continuing operations (0.6 ) (6.0 ) (1.7 ) General partner’s incentive distribution rights — — 16.8 Net loss from continuing operations available to limited partners $ (30.7 ) $ (290.8 ) $ (100.5 ) Net loss from discontinued operations available to limited partners (71.0 ) (31.2 ) (52.9 ) Net loss available to limited partners $ (101.7 ) $ (322.0 ) $ (153.4 ) Denominator for basic and diluted earnings per limited partner unit: Weighted average limited partner units outstanding (1) 77,598,950 77,043,935 74,896,096 Limited partners’ interest basic and diluted net loss per unit: From continuing operations $ (0.40 ) $ (3.77 ) $ (1.34 ) From discontinued operations (0.91 ) (0.41 ) (0.71 ) Limited partners’ interest $ (1.31 ) $ (4.18 ) $ (2.05 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.2 million , 0.5 million and 0.4 million potentially dilutive phantom units which would be antidilutive for the years ended December 31, 2017 , 2016 and 2015 , respectively.

Transactions with Related Parti

Transactions with Related Parties	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Transactions with Related Parties	Transactions with Related Parties During the years ended December 31, 2017 , 2016 and 2015 , the Company had product sales to related parties, excluding the transactions discussed below, of $37.9 million , $13.1 million and $12.0 million , respectively. Trade accounts and other receivables from related parties at December 31, 2017 and 2016 were $0.3 million and $1.1 million , respectively. The Company also had purchases from related parties, excluding transactions discussed below, during the years ended December 31, 2017 , 2016 and 2015 of $7.1 million , $6.4 million and $5.0 million , respectively. Accounts payable to related parties, excluding accounts payable related to the transactions discussed below, at December 31, 2017 and 2016 , were $3.1 million and $1.5 million , respectively. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses. The Company had a general services master services agreement with a third party construction company related to the Great Falls refinery expansion project in which various construction related services were performed during 2016 and 2015 . This third party was related to refinery management. For the years ended December 31, 2016 and 2015 , the Company had capital expenditures of $10.4 million and $43.0 million , respectively, for construction related services. The Company had no capital expenditures and no accounts payable for 2017. Accounts payable under this contract at December 31, 2016 were $2.5 million . During 2015, the Company entered into an agreement for logistic administration/support, general administrative management and fiscal administration services with Monument Chemical, 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 years ended December 31, 2017 and 2016 , the Company paid total commissions and general administrative fees of $1.2 million and $1.3 million , respectively. Accounts payable under this contract at December 31, 2017 and 2016 were immaterial. During the years ended December 31, 2016 and 2015 , the Company entered into various transactions with Dakota Prairie. See Note 5 for further information on Dakota Prairie transactions. During 2016 , the Company entered into a joint venture agreement with The Heritage Group. See Note 5 for further information on the joint venture with The Heritage Group. On December 30, 2015, the Company entered into an agreement with The Heritage Group in which The Heritage Group 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 9 for further information on this agreement.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segments and Related Information	Segments and Related Information a. Segment Reporting The Company manages its business in two 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 and PADD 4 areas within the U.S. Prior to the sale of Anchor, as disclosed in Note 3 , the Company reported an oilfield services segment, which was solely comprised of Anchor. As a result of Anchor’s classification as a discontinued operation, the Company has removed the oilfield services segment. 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 (a non-GAAP financial measure). The Company defines Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense (including debt issuance and extinguishment costs); (b) income taxes; (c) depreciation and amortization; (d) impairment; (e) unrealized losses from mark to market accounting for hedging activities; (f) realized gains under derivative instruments excluded from the determination of net income (loss); (g) 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); (h) debt refinancing fees, premiums and penalties, (i) any net loss realized in connection with an asset sale that was deducted in computing net income (loss) and (j) 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, 2017 Specialty Products Fuel Products Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,300.4 $ 2,463.4 $ 3,763.8 $ — $ 3,763.8 Intersegment sales 0.2 54.8 55.0 (55.0 ) — Total sales $ 1,300.6 $ 2,518.2 $ 3,818.8 $ (55.0 ) $ 3,763.8 Adjusted EBITDA $ 186.5 $ 127.8 $ 314.3 $ — $ 314.3 Reconciling items to net loss: Depreciation and amortization 70.5 108.6 179.1 — 179.1 Impairment charges 60.3 147.0 207.3 — 207.3 Gain on sale of business — (236.0 ) (236.0 ) — (236.0 ) Unrealized gain on derivatives (3.6 ) Interest expense 183.1 Non-cash equity-based compensation and other items 15.8 Income tax benefit (0.1 ) Net loss from continuing operations $ (31.3 ) Year Ended December 31, 2016 Specialty Products Fuel Products Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,252.3 $ 2,222.0 $ 3,474.3 $ — $ 3,474.3 Intersegment sales 2.5 34.5 37.0 (37.0 ) — Total sales $ 1,254.8 $ 2,256.5 $ 3,511.3 $ (37.0 ) $ 3,474.3 Loss from unconsolidated affiliates $ (0.3 ) $ (18.0 ) $ (18.3 ) $ — $ (18.3 ) Adjusted EBITDA $ 188.9 $ (10.1 ) $ 178.8 $ — $ 178.8 Reconciling items to net loss: Depreciation and amortization 74.7 110.5 185.2 — 185.2 Realized gain (loss) on derivatives, not reflected in net loss or settled in a prior period 1.9 (8.3 ) (6.4 ) — (6.4 ) Impairment charges 1.9 34.0 35.9 — 35.9 Loss on sale of unconsolidated affiliate — 113.9 113.9 — 113.9 Unrealized gain on derivatives (19.9 ) Interest expense 161.7 Non-cash equity-based compensation and other items 5.0 Income tax expense 0.2 Net loss from continuing operations $ (296.8 ) Year Ended December 31, 2015 Specialty Fuel Combined Eliminations Consolidated Sales: External customers $ 1,367.8 $ 2,562.5 $ 3,930.3 $ — $ 3,930.3 Intersegment sales 2.9 39.1 42.0 (42.0 ) — Total sales $ 1,370.7 $ 2,601.6 $ 3,972.3 $ (42.0 ) $ 3,930.3 Loss from unconsolidated affiliates $ — $ (61.1 ) $ (61.1 ) $ — $ (61.1 ) Adjusted EBITDA $ 201.7 $ 81.9 $ 283.6 $ — $ 283.6 Reconciling items to net loss: Depreciation and amortization 69.2 82.4 151.6 — 151.6 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 24.3 — 24.3 Unrealized loss on derivatives 39.5 Interest expense 104.9 Debt extinguishment costs 46.6 Non-cash equity-based compensation and other items 11.9 Income tax expense 0.2 Net loss from continuing operations $ (85.4 ) b. Geographic Information International sales accounted for less than 10% of consolidated sales in each of the three years ended December 31, 2017 , 2016 and 2015 . 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. The following table sets forth the major product category sales for each segment (dollars in millions): Year Ended December 31, 2017 2016 2015 Specialty products: Lubricating oils $ 584.2 15.5 % $ 538.7 15.5 % $ 575.6 14.6 % Solvents 274.4 7.3 % 237.7 6.8 % 302.0 7.7 % Waxes 117.2 3.1 % 128.7 3.7 % 136.9 3.5 % Packaged and synthetic specialty products 260.7 6.9 % 244.7 7.0 % 261.5 6.7 % Other 63.9 1.7 % 102.5 3.0 % 91.8 2.3 % Total 1,300.4 34.5 % 1,252.3 36.0 % 1,367.8 34.8 % Fuel products: Gasoline 948.5 25.2 % 844.3 24.3 % 1,047.1 26.6 % Diesel 877.9 23.4 % 808.4 23.3 % 894.8 22.8 % Jet fuel 135.0 3.6 % 117.5 3.4 % 149.6 3.8 % Asphalt, heavy fuel oils and other 502.0 13.3 % 451.8 13.0 % 471.0 12.0 % Total 2,463.4 65.5 % 2,222.0 64.0 % 2,562.5 65.2 % Consolidated sales $ 3,763.8 100.0 % $ 3,474.3 100.0 % $ 3,930.3 100.0 % d. Major Customers During the years ended December 31, 2017 , 2016 and 2015 , the Company had no customer that represented 10% or greater of consolidated sales. e. Major Suppliers During the years ended December 31, 2017 , 2016 and 2015 , the Company had two suppliers that supplied approximately 65.7% , 64.5% and 52.2% , respectively, of its crude oil supply.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
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) 2017 Sales $ 886.5 $ 967.0 $ 1,026.5 $ 883.8 $ 3,763.8 Gross profit 129.5 143.7 127.7 97.3 498.2 Net income (loss) from continuing operations 1.5 12.0 (26.1 ) (18.7 ) (31.3 ) Net income (loss) from discontinued operations (7.7 ) (2.4 ) 2.5 (64.9 ) (72.5 ) Net income (loss) (6.2 ) 9.6 (23.6 ) (83.6 ) (103.8 ) Net income (loss) available to limited partners (6.1 ) 9.2 (23.1 ) (81.9 ) (101.7 ) Limited partners’ interest basic and diluted net income (loss) per unit: From continuing operations $ 0.02 $ 0.15 $ (0.33 ) $ (0.24 ) $ (0.40 ) From discontinued operations (0.10 ) (0.03 ) 0.03 (0.82 ) (0.91 ) Limited partners’ interest $ (0.08 ) $ 0.12 $ (0.30 ) $ (1.06 ) $ (1.31 ) Basic weighted average limited partner units outstanding 77,412,634 77,554,815 77,632,784 77,784,534 Diluted weighted average limited partner units outstanding 78,259,909 77,714,112 77,931,605 77,784,534 First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 2016 Sales $ 680.6 $ 951.6 $ 932.3 $ 909.8 $ 3,474.3 Gross profit 80.3 130.5 103.0 72.5 386.3 Net loss from continuing operations (56.9 ) (135.3 ) (33.1 ) (71.5 ) (296.8 ) Net loss from discontinued operations (10.8 ) (12.6 ) (0.3 ) (8.1 ) (31.8 ) Net loss (67.7 ) (147.9 ) (33.4 ) (79.6 ) (328.6 ) Net loss available to limited partners (66.3 ) (145.0 ) (32.7 ) (78.0 ) (322.0 ) Limited partners’ interest basic and diluted net loss per unit: From continuing operations $ (0.73 ) $ (1.73 ) $ (0.42 ) $ (0.91 ) $ (3.77 ) From discontinued operations (0.14 ) (0.16 ) — (0.10 ) (0.41 ) Limited partners’ interest $ (0.87 ) $ (1.89 ) $ (0.42 ) $ (1.01 ) $ (4.18 ) Basic and diluted weighted average limited partner units outstanding 76,449,841 76,761,504 77,331,347 77,351,593 (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, 2017
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Revolving Credit Facility On February 23, 2018, the Borrowers entered into a Third Amended and Restated Credit Agreement (the “Third Amendment”) with Bank of America, N.A., as a lender and Agent for the lenders, and certain other lenders (with Bank of America, N.A., the “Lenders”). The Third Amendment provides a $600.0 million senior secured revolving credit facility limited by a borrowing base calculation and has an aggregate letter of credit sublimit of $300.0 million , which may be increased with Agent consent to up to 90% of the revolver commitments. The revolving credit facility includes a $25.0 million senior secured first loaned in and last to be repaid out (“FILO”) revolving credit facility. The Third Amendment authorizes incremental uncommitted expansion features in an aggregate of up to $500.0 million pursuant to an increase in the revolver commitments. The Third Amendment also authorizes incremental uncommitted foreign subsidiary credit facilities of up to $50.0 million . The aggregate amount of such incremental revolving loans and foreign subsidiary incremental facilities cannot exceed $500.0 million. Lenders under the Third Amendment have a first priority lien on, among other things, the Company’s accounts receivable and inventory and substantially all of its cash. The Third Amendment matures on February 18, 2023 . The Company may be required to make mandatory prepayments under certain conditions. 2021 Secured Notes On March 8, 2018 , the Company issued a press release announcing that it has called for redemption of all of the 2021 Secured Notes. The redemption date for the Notes is April 9, 2018 , and holders will receive a redemption price of 100.0% of the principal amount of the 2021 Secured Notes, plus accrued and unpaid interest thereon up to, but not including, the Redemption Date, plus a Make Whole Premium (as defined in the Indenture, dated April 20, 2016, governing the 2021 Secured Notes). Form 12b-25 On March 19, 2018, the Company filed a Form 12b-25 with the Securities and Exchange Commission on the basis that the Company had determined that it was unable to file this Annual Report on Form 10-K for the year ended December 31, 2017 by March 16, 2018, the due date for such filing, without unreasonable effort or expense. Renewable Identification Numbers In March 2018, the EPA granted the Company’s fuel products refineries a “small refinery exemption” under the RFS for the full-year 2017, as provided for under the CAA. This exemption included the Superior Refinery for which the Company retained the RINs Obligation for 2017 up to the closing date of the sale of the refinery to Husky. In granting those exemptions, the EPA determined that for the full-year 2017, compliance with the RFS would represent a “disproportionate economic hardship” for these refineries. Acquisition On March 23, 2018, the Company and Heritage Group, a related party, acquired Biosynthetic Technologies, LLC (“Biosynthetic Technologies”), a startup company which developed an intellectual property portfolio for the manufacture of renewable-based and biodegradable esters for $7.0 million . The purchase price was split 50/50 between the Company and Heritage Group. The Company intends to develop and commercialize the renewable esters and is designing a commercial scale test at its existing esters manufacturing plant in Missouri. Fair Value The fair value of the Company’s senior notes has decreased by approximately $34.0 million subsequent to December 31, 2017 .

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Consolidation	The consolidated financial statements reflect the accounts of the Company and its wholly-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, Cash Equivalents and Restricted Cash	Cash, cash equivalents and restricted cash 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 its 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. Under the LIFO inventory method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs.
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 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 natural gas collars, natural gas swaps and certain other crude oil swaps that do not qualify as cash flow hedges for accounting 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, options and futures, 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 New York Mercantile Exchange 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 and 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 its risk profiles. Such 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 is obligated to repurchase crude oil and refined products from Macquarie at the termination of the Supply and Offtake Agreements in certain scenarios. The Company has determined that the redemption feature on the initially recognized liability related to the Supply and Offtake Agreements is an embedded derivative indexed to commodity prices. As such, the Company has accounted for this embedded derivative at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s consolidated statement of operations. The Company recognizes all derivative instruments at their fair values (see Note 11 ) 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. Prior to 2017, the Company accounted for certain derivatives hedging purchases of crude oil and sales of gasoline and diesel as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases were 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. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. 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. 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. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in prepaid expenses and other current assets 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.
Property, Plant and Equipment	Property, plant and equipment are stated on the basis of cost. Depreciation is calculated using the straight-line method over the estimated useful lives. 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 Pacific New Investment Limited joint venture as an equity method investment in accordance with ASC 323, Investments — Equity Method and Joint Ventures and is recorded in investments in unconsolidated affiliates in the consolidated balance sheet . 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. The Company accounts for its ownership in Fluid Holding Corp. (“FHC”) as a cost method investment in accordance with ASC 323, Investments — Equity Method and Joint Ventures and is recorded in investments in unconsolidated affiliates in the consolidated balance sheet. The cost method of accounting is applied when the investor does not have the ability to exercise significant influence. Under the cost method, investments are carried at cost and are adjusted only for other-than-temporary declines in fair value, certain distributions and additional investments. Equity method and cost method investments are assessed for other-than-temporary impairment whenever changes in the facts and circumstances indicate an other than temporary loss in value has occurred. Investments in significant noncontrolled entities are accounted for either by using the equity method or cost method of accounting.
Goodwill and Intangible Assets, Goodwill, Policy	Goodwill represents the excess of purchase price over fair value of the net assets acquired in various acquisitions. See Note 6 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) and ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . Under ASC 350, 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 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. Under ASU 2017-04, goodwill impairment testing is done by comparing the fair value of the reporting unit to its carrying value. If the carrying amount exceeds the fair value, the Company would recognize an impairment charge for the amount that the reporting unit's carrying value exceeds the fair value, not to exceed the total amount of goodwill allocated to that reporting unit. 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 the reporting unit, measuring the current value of the reporting unit 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. 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, its 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. • 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. 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.
Other Intangible Assets	Definite-lived intangible assets consist of intangible assets associated with customer relationships, tradenames, trade secrets, patents 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.
Intangible Assets, Finite-Lived, Policy	Tradenames, trade secrets, patents 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 to properly match expenses with the undiscounted estimated future cash flows based upon assumed rates of annual customer attrition.
Turnaround Costs	The Company capitalizes these costs and amortizes the costs on a straight-line basis over the lives of the turnaround assets which is generally two to five years. Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs
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.
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.
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 accounts for income taxes for its corporations 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. 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.
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.
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	Advertising expenses are reported as selling expenses in the consolidated statements of operations
RINS Obligation	The Company’s Renewable Identification Numbers (“RINs”) obligation (“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 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.
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
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 value of Liability Awards is updated at each balance sheet date and changes in the fair value of the vested portions of the Liability 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. 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 at that point were modified to value the awards based upon the closing unit price on that date. This modification did not affect the remaining service period. Phantom Units 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 2016 and 2015 . These phantom units have a four year service period with one-quarter of the phantom units vesting annually on each December 31 of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant. For the years ended December 31, 2017 , 2016 and 2015 named executive officers were awarded phantom units under the terms of the LTIP, as part of certain employment agreements and arrangements and as part of the Company’s achievement of specified levels of financial performance in fiscal years 2017 and 2015. These phantom units are subject to time-vesting requirements whereby either 25% of the units vest during the fiscal year, and the remainder will vest ratably over the next three years on each December 31 or 100% of the phantom units vest in three years. 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.
Fair Value Measurement, Policy	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. 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 counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. The Company’s 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. Pension assets are reported at fair value in the accompanying consolidated financial statements. At December 31, 2017 , the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds 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 respective investment sponsors or investment advisers. Plan investments can be redeemed within a short time frame (10 or so business days), if requested. 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. The estimated fair value of long-term debt at December 31, 2017 and 2016 , consists primarily of senior notes. 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 secured 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, capital lease obligations, related party note payable and other obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. 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. 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. 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. 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. The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. See Note 6 for further information on goodwill impairment. The Company periodically evaluates the carrying value of long-lived assets to be held and used, including definite-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. All settlements from derivative instruments not designated as hedges are recorded in gain (loss) on derivative instruments in the consolidated statements of operations. The carrying value of cash, cash equivalents and restricted cash is each considered to be representative of its fair value.
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 (a non-GAAP financial measure). The Company defines Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense (including debt issuance and extinguishment costs); (b) income taxes; (c) depreciation and amortization; (d) impairment; (e) unrealized losses from mark to market accounting for hedging activities; (f) realized gains under derivative instruments excluded from the determination of net income (loss); (g) 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); (h) debt refinancing fees, premiums and penalties, (i) any net loss realized in connection with an asset sale that was deducted in computing net income (loss) and (j) 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.
New Accounting Pronouncements	In August 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging (Topic 815) - Targeted Improvements to Accounting for Hedging Activities (“ASU 2017-12”). ASU 2017-12 which improves the financial reporting of hedging relationships to better align risk management activities in financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Company is currently evaluating the adoption of ASU 2017-12 on the Company’s consolidated financial statements. In May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09, Compensation - Stock Compensation (Topic 718) - Scope of Modification Accounting (“ASU 2017-09”). ASU 2017-09 amends prior guidance by further defining when a change to the terms of a share-based award are required to be accounted for as a modification under the rules by providing specific criteria. ASU 2017-09 is effective for annual periods beginning after December 15, 2017. The adoption of ASU 2017-09 will not have an impact on the Company’s consolidated financial statements. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost (“ASU 2017-07”). The changes to the standard require employers to report the service cost component in the same line item as other compensation costs arising from services rendered by employees during the reporting period. The other components of net benefit costs will be presented in the statement of operations separately from the service cost and outside of a subtotal of operating income (loss). In addition, only the service cost component may be eligible for capitalization where applicable. ASU 2017-07 is effective for annual periods beginning after December 15, 2017. The adoption of ASU 2017-07 will not have an impact on the Company’s consolidated financial statements. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (“ASU 2017-04”), in which the guidance on testing for goodwill was updated by the elimination of Step 2 in the determination on whether goodwill should be considered impaired. The annual and/or interim assessments are still required to be completed. Further, the guidance eliminates the requirement to assess reporting units with zero or negative carrying values, however, the carrying values for all reporting units must be disclosed. ASU 2017-04 is effective for fiscal years (including interim periods) beginning after December 15, 2019, with early adoption permitted. The adopted ASU 2017-04 and applied it to its annual goodwill impairment assessment in 2017. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805) - Clarifying the Definition of a Business (“ASU 2017-01”). The guidance provides criteria for use in determining when to conclude a “set” (as defined in the original guidance) being acquired or disposed in a transaction is not a business. Where the criteria are not met, more stringent screening has been provided to define a set as a business without an output, as more narrowly defined within the guidance. ASU 2017-01 is effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption permitted. The adoption of ASU 2017-01 will not have an impact on the Company’s consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes the lease accounting requirements in Accounting Standards Codification (“ASC”) Topic 840, Leases . ASU 2016-02 provides principles for the recognition, measurement, presentation and disclosure of leases for both lessees and lessors. The new standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the principle of whether or not the lease is effectively a financed purchase by the lessee. This classification will determine whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the lease, respectively. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than twelve months regardless of classification. Leases with a term of twelve months or less will be accounted for similar to existing guidance for operating leases. In December 2017 and January 2018, the FASB released ASU 2017-13 and ASU 2018-01, respectively, which contain modifications to ASU 2016-02. The amendments in these standards are effective for fiscal years (including interim periods) beginning after December 15, 2018, with early adoption permitted and modified retrospective application required. The Company is currently evaluating the impact of these standards on its consolidated financial statements. In January 2016, the FASB issued 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 (loss) 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 (loss). Additionally, ASU 2016-01 changes the presentation and disclosure requirements for financial instruments. The amendments in this standard are generally effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The adoption of ASU 2016-01 is not expected to have an impact on the Company’s consolidated financial statements. In May 2014, the FASB issued Accounting Standards Codification 606, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), which supersedes the revenue recognition requirements in Accounting Standard Codification Topic 605, Revenue Recognition . The new accounting standard 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. In order to apply this core principle, companies will apply the following five steps in determining the amount of revenues to recognize: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management’s judgment and an analysis of the contract’s material terms and conditions. The Company adopted the new standard on January 1, 2018 using a modified retrospective approach, which required it to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity, if necessary. In accordance with this approach, the Company’s consolidated revenues for periods prior to January 1, 2018 will not be revised. The Company’s implementation activities related to ASC 606 are complete and we will not have any material differences in the amount or timing of revenues as a result of the adoption of ASC 606. The Company’s largest revenue streams consist of orders received from our customers for crude-oil based specialty products and fuel and fuel related products, generally based on market prices. These revenues are recognized at a point in time upon transfer of control of the product in accordance with contractual terms. In addition, the Company has identified some agreements with distributors within the specialty products segment that are subject to rebate and incentive programs that could contain elements of material rights and/or variable consideration. These elements did not result in a material change to how revenue is recognized for these agreements. As a result of adopting the new standard, there will be changes to the Company’s disclosures based on the additional requirements prescribed by ASC 606. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities.

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Allowance for Doubtful Accounts Activity	The activity in the allowance for doubtful accounts was as follows (in millions): December 31, 2017 2016 2015 Beginning balance $ 0.9 $ 0.9 $ 1.4 Provision 6.1 0.3 — Write-offs, net — (0.3 ) (0.5 ) Ending balance $ 7.0 $ 0.9 $ 0.9
Inventories	Inventories consist of the following (in millions): December 31, 2017 December 31, 2016 Titled Supply & Offtake (1) Total Titled Supply & Offtake (1) Total Raw materials $ 42.0 $ 17.6 $ 59.6 $ 57.4 $ — $ 57.4 Work in process 34.4 23.7 58.1 74.2 — 74.2 Finished goods 139.4 57.3 196.7 226.2 — 226.2 $ 215.8 $ 98.6 $ 314.4 $ 357.8 $ — $ 357.8 (1) Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Refer to Note 8 for further information
Property, Plant and Equipment	Property, plant and equipment, including depreciable lives, consisted of the following (in millions): December 31, 2017 2016 Land $ 13.8 $ 19.6 Buildings and improvements (10 to 40 years) 36.9 69.0 Machinery and equipment (10 to 20 years) 1,622.8 2,055.3 Furniture and fixtures (5 to 10 years) 61.5 33.2 Assets under capital leases (4 to 26 years) (1) 18.2 51.3 Construction-in-progress 21.4 49.0 1,774.6 2,277.4 Less accumulated depreciation (615.4 ) (645.0 ) $ 1,159.2 $ 1,632.4
Other Current Liabilities	Other current liabilities consisted of the following (in millions): December 31, 2017 2016 RINs Obligation $ 59.1 $ 79.3 Other 14.6 20.3 Total $ 73.7 $ 99.6

Discontinued Operations Disco31

Discontinued Operations Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table summarizes the results of discontinued operations for each of the periods presented (in millions): Year Ended December 31, 2017 2016 2015 Sales $ 228.6 $ 125.1 $ 282.5 Cost of sales (168.1 ) (103.1 ) (224.3 ) Selling (45.9 ) (40.9 ) (74.2 ) General and administrative (4.5 ) (4.8 ) (9.6 ) Asset impairment — — (33.8 ) Loss on sale of business, net (62.6 ) — — Other (21.0 ) (16.0 ) (23.2 ) Net loss from discontinued operations before income taxes $ (73.5 ) $ (39.7 ) $ (82.6 ) Income tax benefit (1) (1.0 ) (7.9 ) (28.6 ) Net loss from discontinued operations net of income taxes $ (72.5 ) $ (31.8 ) $ (54.0 )

Divestitures (Tables)

Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Noncash or Part Noncash Divestitures [Table Text Block]	The following table presents the net income before income taxes for Superior for the periods presented (in millions): Year Ended December 31, 2017 2016 2015 Sales $ 669.1 $ 681.2 $ 856.8 Gross profit $ 110.0 $ 68.5 $ 137.6 Net income before income taxes $ 99.3 $ 54.5 $ 121.0

Investment in Unconsolidated 33

Investment in Unconsolidated Affiliate Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	The following table summarizes the Company’s investments in unconsolidated affiliates (in millions): Year Ended December 31, 2017 Year Ended December 31, 2016 Investment Percent Ownership Investment Percent Ownership Pacific New Investment Limited $ 9.6 23.8 % $ 9.6 23.8 % Fluid Holding Corp. 25.4 10 % — — % Total $ 35.0 $ 9.6

Goodwill and Other Intangible34

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Changes in goodwill balances for the periods indicated below are as follows (in millions): Specialty Fuel Total Net balance as of December 31, 2015 $ 173.5 $ 38.5 $ 212.0 Impairment (1) (1.4 ) (33.4 ) (34.8 ) Net balance as of December 31, 2016 $ 172.1 $ 5.1 $ 177.2 Impairment (1) (0.7 ) — (0.7 ) Divestiture (2) — (5.1 ) (5.1 ) Net balance as of December 31, 2017 $ 171.4 $ — $ 171.4 (1) Total accumulated goodwill impairment as of December 31, 2017 and 2016 , is $35.5 million and $34.8 million , respectively. (2) Divestiture relates to sale of the Superior Refinery
Schedule of Other Intangible Assets	Other intangible assets consist of the following (in millions): Weighted Average Life (Years) December 31, 2017 December 31, 2016 Gross Amount Accumulated Amortization Gross Amount Accumulated Amortization Customer relationships 22 $ 181.3 $ (107.6 ) $ 186.7 $ (97.2 ) Tradenames 11 26.8 (13.8 ) 26.8 (9.9 ) Trade secrets 13 52.7 (35.1 ) 52.7 (29.6 ) Patents 12 1.6 (1.6 ) 1.6 (1.5 ) Royalty agreements 19 6.2 (2.6 ) 6.2 (2.3 ) 19 $ 268.6 $ (160.7 ) $ 274.0 $ (140.5 )
Schedule of Estimated Future Amortization Expense	As of December 31, 2017 , the Company estimates that amortization of intangible assets for the next five years will be as follows (in millions): Year Amortization Amount 2018 $ 19.9 2019 $ 16.8 2020 $ 14.0 2021 $ 11.5 2022 $ 9.4

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Fiscal Year Maturity Schedule	As of December 31, 2017 , 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 2018 $ 31.4 2019 21.7 2020 16.7 2021 9.5 2022 7.3 Thereafter 10.8 Total $ 97.4
Purchase Commitment, Fiscal Year Maturity Schedule	As of December 31, 2017 , 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 2018 $ 297.5 2019 126.7 2020 21.1 2021 21.0 2022 21.0 Thereafter 84.2 Total $ 571.5

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
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 8.4% and 4.8% at December 31, 2017 and 2016, respectively $ 0.2 $ 10.2 Borrowings under 2021 Secured Notes, interest at a fixed rate of 11.5%, interest payments semiannually, borrowings due January 2021, effective interest rates of 12.3% and 12.2% for the year ended December 31, 2017 and 2016, respectively 400.0 400.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.5%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for each year ended December 31, 2017 and 2016 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, 2017 and 2016 (1) 352.1 352.5 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 each year ended December 31, 2017 and 2016 325.0 325.0 Other 6.6 8.0 Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034 44.0 46.5 Less unamortized debt issuance costs (2) (25.9 ) (33.2 ) Less unamortized discounts (9.7 ) (11.8 ) Total long-term debt 1,992.3 1,997.2 Less current portion of long-term debt (3) 354.1 3.5 $ 1,638.2 $ 1,993.7 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.1 million and $2.5 million as of December 31, 2017 and 2016 , respectively. (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 $21.8 million and $14.5 million at December 31, 2017 and 2016 , respectively.
Schedule of basis spread	As of December 31, 2017 , the margin was 50 basis points for prime rate loans and 150 basis points for LIBOR rate loans; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding fiscal 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, 2017 , the Company had estimated minimum commitments for the payment of total rentals under capital leases relating to continuing and discontinued operations as follows (in millions): Year Capital Leases 2018 $ 9.0 2019 7.4 2020 6.9 2021 6.9 2022 6.9 Thereafter 82.1 Total minimum lease payments 119.2 Less amount representing interest 75.2 Capital lease obligations 44.0 Less obligations due within one year 2.7 Long-term capital lease obligations $ 41.3
Maturities of long-term debt	As of December 31, 2017 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2018 $ 354.1 2019 2.9 2020 2.4 2021 953.3 2022 351.2 Thereafter 361.9 Total $ 2,025.8

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2017
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 (in millions): December 31, 2017 December 31, 2016 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 not designated as hedges: Specialty products segment: Natural gas swaps $ — $ — $ — $ 0.1 $ (0.1 ) $ — Fuel products segment: Crude oil swaps 0.3 (0.3 ) — 10.3 (7.4 ) 2.9 Crude oil basis swaps — — — — (2.1 ) (2.1 ) Crude oil percentage basis swaps — — — 0.1 (0.1 ) — Total derivative instruments $ 0.3 $ (0.3 ) $ — $ 10.5 $ (9.7 ) $ 0.8
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 (in millions): December 31, 2017 December 31, 2016 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 not designated as hedges: Specialty products segment: Natural gas swaps $ — $ — $ — $ (1.2 ) $ 0.1 $ (1.1 ) Fuel products segment: Inventory financing obligation (4.4 ) — (4.4 ) — — — Crude oil swaps — 0.3 0.3 (8.2 ) 7.4 (0.8 ) Crude oil basis swaps — — — (7.1 ) 2.1 (5.0 ) Crude oil percentage basis swaps — — — (0.6 ) 0.1 (0.5 ) Gasoline swaps (0.2 ) — (0.2 ) — — — Gasoline crack spread swaps (1.8 ) — (1.8 ) (3.5 ) — (3.5 ) Diesel swaps (0.2 ) — (0.2 ) — — — Diesel crack spread swaps (4.1 ) — (4.1 ) (1.4 ) — (1.4 ) 2/1/1 crack spread swaps — — — (2.5 ) — (2.5 ) Total derivative instruments $ (10.7 ) $ 0.3 $ (10.4 ) $ (24.5 ) $ 9.7 $ (14.8 )
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 related to its derivative instruments not designated as hedges (in millions): Amount of Gain (Loss) Recognized in Realized Loss on Derivative Instruments Amount of Gain (Loss) Recognized in Unrealized Gain on Derivative Instruments Year Ended December 31, Year Ended December 31, Type of Derivative 2017 2016 2017 2016 Specialty products segment: Natural gas swaps $ (3.6 ) $ (11.3 ) $ 1.0 $ 14.7 Fuel products segment: Inventory financing obligation — — (4.4 ) — Crude oil swaps (1.9 ) 5.3 (1.7 ) 7.3 Crude oil basis swaps 3.2 (4.1 ) 7.1 (5.9 ) Crude oil percentage basis swaps 2.3 (4.3 ) 0.5 5.4 Crude oil options — (2.6 ) — 0.3 Crude oil futures — (2.0 ) — — Gasoline swaps (0.6 ) — (0.2 ) — Gasoline crack spread swaps (6.2 ) (2.5 ) 3.0 (0.5 ) Diesel swaps (0.5 ) — (0.2 ) — Diesel crack spread swaps (5.0 ) (0.4 ) (1.5 ) (2.7 ) 2/1/1 crack spread swaps (0.9 ) (0.8 ) — — Natural gas swaps — (1.3 ) — 1.3 Total $ (13.2 ) $ (24.0 ) $ 3.6 $ 19.9
Natural Gas Swap Contracts | Specialty Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	At December 31, 2016 , 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 2017 1,350,000 $ 3.88 Second Quarter 2017 1,320,000 $ 3.87 Third Quarter 2017 1,320,000 $ 3.87 Fourth Quarter 2017 960,000 $ 3.72 Total 4,950,000 Average price $ 3.85
Crude Oil Swaps | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Crude Oil Swap Contracts At December 31, 2017 , 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 2018 28,000 311 $ 48.25 Total 28,000 Average price $ 48.25 At December 31, 2016 , 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 BPD Average Swap First Quarter 2017 320,049 3,556 $ 48.87 Second Quarter 2017 323,605 3,556 $ 48.87 Third Quarter 2017 327,161 3,556 $ 48.87 Fourth Quarter 2017 327,161 3,556 $ 48.87 Total 1,297,976 Average price $ 48.87 At December 31, 2016 , 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 2017 130,320 1,448 $ 41.56 Second Quarter 2017 131,768 1,448 $ 41.56 Third Quarter 2017 133,216 1,448 $ 41.56 Fourth Quarter 2017 133,216 1,448 $ 41.56 Total 528,520 Average price $ 41.56
Crude Oil Basis Swaps | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	At December 31, 2016 , 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 2017 630,000 7,000 $ (13.22 ) Second Quarter 2017 637,000 7,000 $ (13.22 ) Third Quarter 2017 644,000 7,000 $ (13.22 ) Fourth Quarter 2017 644,000 7,000 $ (13.22 ) Total 2,555,000 Average differential $ (13.22 )
Crude Oil Percent Basis Swaps | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	At December 31, 2016 , 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) First Quarter 2017 270,000 3,000 72.3 % Second Quarter 2017 273,000 3,000 72.3 % Third Quarter 2017 276,000 3,000 72.3 % Fourth Quarter 2017 276,000 3,000 72.3 % Total 1,095,000 Average percentage 72.3 %
Gasoline Crack Spread Swaps | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	Gasoline Crack Spread Swap Contracts At December 31, 2017 , 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 2018 826,000 9,178 $ 12.27 Total 826,000 Average price $ 12.27 At December 31, 2016 , 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 2017 590,000 6,556 $ 10.21 Total 590,000 Average price $ 10.21
Gasoline Swaps | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	At December 31, 2017 , 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 First Quarter 2018 14,000 156 $ 61.35 Totals 14,000 Average price $ 61.35
Diesel Crack Spread Swaps | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	At December 31, 2017 , the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges: Diesel Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2018 826,000 9,178 $ 17.58 Total 826,000 Average price $ 17.58 At December 31, 2016 , the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges: Diesel Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2017 590,000 6,556 $ 13.67 Total 590,000 Average price $ 13.67
Diesel Swaps | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	At December 31, 2017 , 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 2018 14,000 156 $ 66.35 Totals 14,000 Average price $ 66.35
2-1-1- Crack Spread Swap | Fuel Product
Derivative [Line Items]
Schedule of Outstanding Derivative Positions	At December 31, 2016 , the Company had the following derivatives related to 2/1/1 crack spread sales in its fuel products segment, none of which are designated as hedges: 2/1/1 Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2017 590,000 6,556 $ 11.91 Total 590,000 Average price $ 11.91

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Hierarchy of Recurring Fair Value Measurements	The Company’s recurring assets and liabilities measured at fair value were as follows (in millions): December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Crude oil swaps $ — $ — $ — $ — $ — $ — $ 2.9 $ 2.9 Crude oil basis swaps — — — — — — (2.1 ) (2.1 ) Total derivative assets — — — — — — 0.8 0.8 Pension Plan investments 0.2 — — 0.2 0.3 — — 0.3 Total recurring assets at fair value $ 0.2 $ — $ — $ 0.2 $ 0.3 $ — $ 0.8 $ 1.1 Liabilities: Derivative liabilities: Inventory financing obligation $ — $ — $ (4.4 ) $ (4.4 ) $ — $ — $ — $ — Crude oil swaps — — 0.3 0.3 — — (0.8 ) (0.8 ) Crude oil basis swaps — — — — — — (5.0 ) (5.0 ) Crude oil percentage basis swaps — — — — — — (0.5 ) (0.5 ) Gasoline crack spread swaps — — (1.8 ) (1.8 ) — — (3.5 ) (3.5 ) Gasoline swaps — — (0.2 ) (0.2 ) — — — — 2/1/1 crack spread swaps — — — — — — (2.5 ) (2.5 ) Diesel swaps — — (0.2 ) (0.2 ) — — — — Diesel crack spread swaps — — (4.1 ) (4.1 ) — — (1.4 ) (1.4 ) Natural gas swaps — — — — — — (1.1 ) (1.1 ) Total derivative liabilities — — (10.4 ) (10.4 ) — — (14.8 ) (14.8 ) RINs Obligation — (59.1 ) — (59.1 ) — (79.3 ) — (79.3 ) Liability Awards (5.6 ) — — (5.6 ) — — — — Total recurring liabilities at fair value $ (5.6 ) $ (59.1 ) $ (10.4 ) $ (75.1 ) $ — $ (79.3 ) $ (14.8 ) $ (94.1 )
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 (in millions): For the Year Ended December 31, 2017 2016 Fair value at January 1, $ (14.0 ) $ (33.9 ) Realized loss on derivative instruments 13.2 24.0 Unrealized gain on derivative instruments 3.6 19.9 Settlements (13.2 ) (24.0 ) Fair value at December 31, $ (10.4 ) $ (14.0 ) Total gain included in net loss attributable to changes in unrealized gain relating to financial assets and liabilities held as of December 31, $ 3.6 $ 19.9
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, were as follows (in millions): December 31, 2017 December 31, 2016 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,576.5 $ 1,556.4 $ 1,334.1 $ 1,552.2 Senior notes 2 $ 456.4 $ 387.6 $ 458.8 $ 384.5 Revolving credit facility 3 $ 0.2 $ 0.2 $ 6.0 $ 6.0 Capital lease and other obligations 3 $ 50.6 $ 50.6 $ 54.5 $ 54.5

Partners' Capital Partner's Cap

Partners' Capital Partner's Capital (Tables)	12 Months Ended
	Dec. 31, 2017
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 %

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
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 and performance units as of December 31, 2017 , and the changes during the years ended December 31, 2017 , 2016 and 2015 , are presented below: Number of Phantom Units Weighted-Average Grant Date Fair Value Nonvested at January 1, 2015 502,120 $ 26.48 Granted 343,533 21.70 Vested (321,741 ) 23.54 Forfeited (103,188 ) 23.94 Nonvested at December 31, 2015 420,724 $ 24.27 Granted 1,880,094 4.57 Vested (1,455,131 ) 6.35 Forfeited (90,854 ) 14.82 Nonvested at December 31, 2016 754,833 $ 9.58 Granted 2,753,507 4.10 Vested (925,199 ) 7.30 Forfeited (47,363 ) 9.73 Nonvested at December 31, 2017 2,535,778 $ 3.11

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Schedule of Contribution Expenses	The Company recorded the following 401(k) Plan matching contribution expense in the consolidated statement of operations (in millions): Year Ended December 31, 2017 2016 2015 401(k) Plan matching contribution expense $ 5.7 $ 6.0 $ 5.0
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, 2017 2016 Change in projected benefit obligation: Benefit obligation at beginning of year $ 60.9 $ 60.3 Service cost 0.1 0.1 Interest cost 2.3 2.5 Plan settlements — (0.6 ) Benefit payments (2.5 ) (2.5 ) Actuarial loss 4.2 1.1 Reduction due to sale of the Superior Refinery (26.6 ) — Administrative expense (0.1 ) — Benefit obligation at end of year $ 38.3 $ 60.9 Change in plan assets: Fair value of plan assets at beginning of year $ 49.8 $ 47.5 Plan settlements — (0.6 ) Benefit payments (2.5 ) (2.5 ) Actual return on assets 7.4 3.8 Employer contribution 2.3 1.6 Administrative expense $ (0.1 ) $ — Distribution to acquirer of the Superior Refinery (21.5 ) — Fair value of plan assets at end of year $ 35.4 $ 49.8 Funded status — benefit obligation in excess of plan assets $ (2.9 ) $ (11.1 ) Reconciliation of amounts recognized in the consolidated balance sheets: Accrued benefit obligation, long-term $ (2.9 ) $ (11.1 ) Unrecognized net actuarial loss 6.0 7.1 Accumulated other comprehensive loss 6.0 7.1 Net amount recognized at end of year $ 3.1 $ (4.0 )
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets	Selected information for the Company’s Pension Plan with an accumulated benefit obligation in excess of plan assets were as follows (in millions): Year Ended December 31, 2017 2016 Accumulated benefit obligation $ 38.3 $ 60.9 Fair value of plan assets $ 35.4 $ 49.8
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, 2017 2016 Projected benefit obligation $ 38.3 $ 60.9 Fair value of plan assets $ 35.4 $ 49.8
Components of Net Periodic Pension Cost	The components of net periodic benefit cost (income) were as follows (in millions): Pension Plan Year Ended December 31, 2017 2016 2015 Service cost $ 0.1 $ 0.1 $ 0.5 Interest cost 2.3 2.5 2.6 Expected return on assets (2.9 ) (3.2 ) (3.3 ) Amortization of net loss 0.2 0.1 0.8 Settlement loss recognized 0.7 — — Curtailment gain recognized — — (0.9 ) Net periodic benefit cost (income) $ 0.4 $ (0.5 ) $ (0.3 )
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 were as follows (in millions): Pension Plan Year Ended December 31, 2017 2016 2015 Changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net (gain) loss $ (0.2 ) $ 0.4 $ (4.3 ) Amounts recognized as a component of net periodic benefit cost: Amortization or settlement recognition of net loss (0.9 ) (0.1 ) (0.8 ) Total recognized in other comprehensive (income) loss $ (1.1 ) $ 0.3 $ (5.1 )
Schedule of Assumptions Used	The significant weighted average assumptions used to determine the benefit obligations for the years ended December 31, 2017 and 2016 , were as follows: Benefit Obligations Assumptions 2017 2016 Discount rate for Penreco Pension Plan 3.56 % 4.08 % Discount rate for Superior Pension Plan N/A 4.06 % Discount rate for Great Falls Pension Plan 3.54 % 4.04 % The significant weighted average assumptions used to determine the net periodic benefit cost (income) for the years ended December 31, 2017 , 2016 and 2015 were as follows: Net Periodic Benefit (Income) Cost Assumptions 2017 2016 2015 Discount rate for Penreco Pension Plan 4.08 % 4.30 % 3.92 % Discount rate for Superior Pension Plan 4.06 % 4.27 % 3.86 % Discount rate for Great Falls Pension Plan 4.04 % 4.21 % 4.13 % Expected return on plan assets for Penreco Pension Plan (1) 6.35 % 6.75 % 6.75 % Expected return on plan assets Superior Pension Plan (1) 6.35 % 6.75 % 6.75 % Expected return on plan assets for Great Falls Pension Plan (1) 6.35 % 6.75 % 6.75 % Rate of compensation increase for Great Falls Pension Plan N/A N/A 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 Company’s Pension Plan asset allocations, as of December 31, 2017 and 2016 , by asset category, are as follows: 2017 2016 Cash and cash equivalents 1 % 1 % Domestic equities 12 % 17 % Foreign equities 12 % 17 % Fixed income 75 % 65 % 100 % 100 % The Pension Plan’s target asset allocation is currently comprised of the following: Asset Class Range of Target Domestic equities 15–25% 20% Foreign equities 15–25% 20% Fixed income 55–65% 60%
Schedule of Pension Plan assets measured at fair value	The Company’s Pension Plan assets measured at fair value, were as follows (in millions): Fair Value of Pension Assets at December 31, 2017 2016 Level 1 Total Level 1 Total Cash and cash equivalents $ 0.2 $ 0.2 $ 0.3 $ 0.3 Total plan assets subject to leveling $ 0.2 0.2 $ 0.3 0.3 Plan assets measured at net asset value Domestic equities 4.3 8.6 Foreign equities 4.4 8.7 Fixed income 26.5 32.2 Total plan assets measured at net asset value 35.2 49.5 Total plan assets $ 35.4 $ 49.8
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, 2017 (in millions): Pension Benefits 2018 $ 1.6 2019 1.7 2020 1.8 2021 1.9 2022 1.9 2023 to 2027 10.7 Total $ 19.6

Accumulated Other Comprehensi42

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2017
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 years ended December 31, 2017 and 2016 (in millions): Derivatives Defined Benefit Pension And Retiree Health Benefit Plans Foreign Currency Translation Adjustment Total Accumulated other comprehensive income (loss) at December 31, 2015 $ 6.4 $ (6.8 ) $ (1.2 ) $ (1.6 ) Other comprehensive loss before reclassifications — (0.4 ) — (0.4 ) Amounts reclassified from accumulated other comprehensive income (loss) (6.4 ) 0.1 — (6.3 ) Net current period other comprehensive loss (6.4 ) (0.3 ) — (6.7 ) Accumulated other comprehensive loss at December 31, 2016 $ — $ (7.1 ) $ (1.2 ) $ (8.3 ) Other comprehensive income before reclassifications — 0.2 — 0.2 Amounts reclassified from accumulated other comprehensive loss — 0.9 — 0.9 Net current period other comprehensive income — 1.1 — 1.1 Accumulated other comprehensive loss at December 31, 2017 $ — $ (6.0 ) $ (1.2 ) $ (7.2 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive loss in the Company’s consolidated statements of operations for the years ended December 31, 2017 and 2016 (in millions): Components of Accumulated Other Comprehensive Loss 2017 2016 Location of Gain (Loss) Derivative gains (losses) reflected in gross profit $ — $ 59.7 Sales — (53.3 ) Cost of sales $ — $ 6.4 Total Amortization of defined benefit pension benefit plans: Amortization or settlement recognition of net loss $ (0.9 ) $ (0.1 ) (1) $ (0.9 ) $ (0.1 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 14 for additional information.

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Unit [Abstract]
Earnings per Unit	The following table sets forth the computation of basic and diluted earnings per limited partner unit (in millions, except unit and per unit data): Year Ended December 31, 2017 2016 2015 Numerator for basic and diluted earnings per limited partner unit: Net loss from continuing operations $ (31.3 ) $ (296.8 ) $ (85.4 ) Less: General partner’s interest in net loss from continuing operations (0.6 ) (6.0 ) (1.7 ) General partner’s incentive distribution rights — — 16.8 Net loss from continuing operations available to limited partners $ (30.7 ) $ (290.8 ) $ (100.5 ) Net loss from discontinued operations available to limited partners (71.0 ) (31.2 ) (52.9 ) Net loss available to limited partners $ (101.7 ) $ (322.0 ) $ (153.4 ) Denominator for basic and diluted earnings per limited partner unit: Weighted average limited partner units outstanding (1) 77,598,950 77,043,935 74,896,096 Limited partners’ interest basic and diluted net loss per unit: From continuing operations $ (0.40 ) $ (3.77 ) $ (1.34 ) From discontinued operations (0.91 ) (0.41 ) (0.71 ) Limited partners’ interest $ (1.31 ) $ (4.18 ) $ (2.05 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.2 million , 0.5 million and 0.4 million potentially dilutive phantom units which would be antidilutive for the years ended December 31, 2017 , 2016 and 2015 , respectively.

Segments and Related Informat44

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Reportable segment information	Reportable segment information is as follows (in millions): Year Ended December 31, 2017 Specialty Products Fuel Products Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,300.4 $ 2,463.4 $ 3,763.8 $ — $ 3,763.8 Intersegment sales 0.2 54.8 55.0 (55.0 ) — Total sales $ 1,300.6 $ 2,518.2 $ 3,818.8 $ (55.0 ) $ 3,763.8 Adjusted EBITDA $ 186.5 $ 127.8 $ 314.3 $ — $ 314.3 Reconciling items to net loss: Depreciation and amortization 70.5 108.6 179.1 — 179.1 Impairment charges 60.3 147.0 207.3 — 207.3 Gain on sale of business — (236.0 ) (236.0 ) — (236.0 ) Unrealized gain on derivatives (3.6 ) Interest expense 183.1 Non-cash equity-based compensation and other items 15.8 Income tax benefit (0.1 ) Net loss from continuing operations $ (31.3 ) Year Ended December 31, 2016 Specialty Products Fuel Products Combined Segments Eliminations Consolidated Total Sales: External customers $ 1,252.3 $ 2,222.0 $ 3,474.3 $ — $ 3,474.3 Intersegment sales 2.5 34.5 37.0 (37.0 ) — Total sales $ 1,254.8 $ 2,256.5 $ 3,511.3 $ (37.0 ) $ 3,474.3 Loss from unconsolidated affiliates $ (0.3 ) $ (18.0 ) $ (18.3 ) $ — $ (18.3 ) Adjusted EBITDA $ 188.9 $ (10.1 ) $ 178.8 $ — $ 178.8 Reconciling items to net loss: Depreciation and amortization 74.7 110.5 185.2 — 185.2 Realized gain (loss) on derivatives, not reflected in net loss or settled in a prior period 1.9 (8.3 ) (6.4 ) — (6.4 ) Impairment charges 1.9 34.0 35.9 — 35.9 Loss on sale of unconsolidated affiliate — 113.9 113.9 — 113.9 Unrealized gain on derivatives (19.9 ) Interest expense 161.7 Non-cash equity-based compensation and other items 5.0 Income tax expense 0.2 Net loss from continuing operations $ (296.8 ) Year Ended December 31, 2015 Specialty Fuel Combined Eliminations Consolidated Sales: External customers $ 1,367.8 $ 2,562.5 $ 3,930.3 $ — $ 3,930.3 Intersegment sales 2.9 39.1 42.0 (42.0 ) — Total sales $ 1,370.7 $ 2,601.6 $ 3,972.3 $ (42.0 ) $ 3,930.3 Loss from unconsolidated affiliates $ — $ (61.1 ) $ (61.1 ) $ — $ (61.1 ) Adjusted EBITDA $ 201.7 $ 81.9 $ 283.6 $ — $ 283.6 Reconciling items to net loss: Depreciation and amortization 69.2 82.4 151.6 — 151.6 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 24.3 — 24.3 Unrealized loss on derivatives 39.5 Interest expense 104.9 Debt extinguishment costs 46.6 Non-cash equity-based compensation and other items 11.9 Income tax expense 0.2 Net loss from continuing operations $ (85.4 )
Major product category sales	The following table sets forth the major product category sales for each segment (dollars in millions): Year Ended December 31, 2017 2016 2015 Specialty products: Lubricating oils $ 584.2 15.5 % $ 538.7 15.5 % $ 575.6 14.6 % Solvents 274.4 7.3 % 237.7 6.8 % 302.0 7.7 % Waxes 117.2 3.1 % 128.7 3.7 % 136.9 3.5 % Packaged and synthetic specialty products 260.7 6.9 % 244.7 7.0 % 261.5 6.7 % Other 63.9 1.7 % 102.5 3.0 % 91.8 2.3 % Total 1,300.4 34.5 % 1,252.3 36.0 % 1,367.8 34.8 % Fuel products: Gasoline 948.5 25.2 % 844.3 24.3 % 1,047.1 26.6 % Diesel 877.9 23.4 % 808.4 23.3 % 894.8 22.8 % Jet fuel 135.0 3.6 % 117.5 3.4 % 149.6 3.8 % Asphalt, heavy fuel oils and other 502.0 13.3 % 451.8 13.0 % 471.0 12.0 % Total 2,463.4 65.5 % 2,222.0 64.0 % 2,562.5 65.2 % Consolidated sales $ 3,763.8 100.0 % $ 3,474.3 100.0 % $ 3,930.3 100.0 %

Quarterly Financial Data (Una45

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2017 Sales $ 886.5 $ 967.0 $ 1,026.5 $ 883.8 $ 3,763.8 Gross profit 129.5 143.7 127.7 97.3 498.2 Net income (loss) from continuing operations 1.5 12.0 (26.1 ) (18.7 ) (31.3 ) Net income (loss) from discontinued operations (7.7 ) (2.4 ) 2.5 (64.9 ) (72.5 ) Net income (loss) (6.2 ) 9.6 (23.6 ) (83.6 ) (103.8 ) Net income (loss) available to limited partners (6.1 ) 9.2 (23.1 ) (81.9 ) (101.7 ) Limited partners’ interest basic and diluted net income (loss) per unit: From continuing operations $ 0.02 $ 0.15 $ (0.33 ) $ (0.24 ) $ (0.40 ) From discontinued operations (0.10 ) (0.03 ) 0.03 (0.82 ) (0.91 ) Limited partners’ interest $ (0.08 ) $ 0.12 $ (0.30 ) $ (1.06 ) $ (1.31 ) Basic weighted average limited partner units outstanding 77,412,634 77,554,815 77,632,784 77,784,534 Diluted weighted average limited partner units outstanding 78,259,909 77,714,112 77,931,605 77,784,534 First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 2016 Sales $ 680.6 $ 951.6 $ 932.3 $ 909.8 $ 3,474.3 Gross profit 80.3 130.5 103.0 72.5 386.3 Net loss from continuing operations (56.9 ) (135.3 ) (33.1 ) (71.5 ) (296.8 ) Net loss from discontinued operations (10.8 ) (12.6 ) (0.3 ) (8.1 ) (31.8 ) Net loss (67.7 ) (147.9 ) (33.4 ) (79.6 ) (328.6 ) Net loss available to limited partners (66.3 ) (145.0 ) (32.7 ) (78.0 ) (322.0 ) Limited partners’ interest basic and diluted net loss per unit: From continuing operations $ (0.73 ) $ (1.73 ) $ (0.42 ) $ (0.91 ) $ (3.77 ) From discontinued operations (0.14 ) (0.16 ) — (0.10 ) (0.41 ) Limited partners’ interest $ (0.87 ) $ (1.89 ) $ (0.42 ) $ (1.01 ) $ (4.18 ) Basic and diluted weighted average limited partner units outstanding 76,449,841 76,761,504 77,331,347 77,351,593 (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, 2017	Dec. 31, 2016
Limited Partners
Schedule of Capitalization, Equity [Line Items]
Limited partners common units outstanding (in shares)	76,788,801	76,392,258
Limited partners', ownership percentage	98.00%
General Partner
Schedule of Capitalization, Equity [Line Items]
General partner equivalent units outstanding (in shares)	1,567,118
General partner, ownership percentage	2.00%

Summary of Significant Accoun47

Summary of Significant Accounting Policies Cash (Details)	12 Months Ended
	Dec. 31, 2017
Cash and Cash Equivalents [Abstract]
Additional Cash and Cash Equivalent Related Text	P3M

Summary of Significant Accoun48

Summary of Significant Accounting Policies (A/R) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Activity in Allowance for Doubtful Accounts
Beginning balance	$ 0.9	$ 0.9	$ 1.4
Provisions	6.1	0.3	0
Write-offs, net	0	(0.3)	(0.5)
Ending balance	$ 7	$ 0.9	$ 0.9

Summary of Significant Accoun49

Summary of Significant Accounting Policies (Inventories) (Details) - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016
Inventories
Raw materials		$ 59.6	$ 57.4
Work in process		58.1	74.2
Finished goods		196.7	226.2
Inventories total		314.4	357.8
TitledInventory [Member]
Inventories
Raw materials		42	57.4
Work in process		34.4	74.2
Finished goods		139.4	226.2
Inventories total		215.8	357.8
Supply&OfftakeAgreements [Member]
Inventories
Raw materials	[1]	17.6	0
Work in process	[1]	23.7	0
Finished goods	[1]	57.3	0
Inventories total	[1]	$ 98.6	$ 0
[1]	(1) Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Refer to Note 8 for further information.

Summary of Significant Accoun50

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Inventories Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
LIFO Inventory Related Text	last-in, first-out (“LIFO”)
Replacement costs	$ (4.6)	$ (15.7)
Consigned inventory	1.4	1.3
Effect of LIFO Inventory Liquidation on Income	(3.7)	(28.5)	$ (25.1)
Inventory Write-down	$ (30.6)	$ (38.4)	$ 67

Summary of Significant Accoun51

Summary of Significant Accounting Policies (PPE) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment
Property, plant and equipment, gross	$ 1,774.6	$ 2,277.4
Less accumulated depreciation	(615.4)	(645)
Property, plant and equipment, net	1,159.2	1,632.4
Land
Property, Plant and Equipment
Property, plant and equipment, gross	13.8	19.6
Building and improvements
Property, Plant and Equipment
Property, plant and equipment, gross	$ 36.9	69
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
Property, plant and equipment, gross	$ 1,622.8	2,055.3
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
Property, plant and equipment, gross	$ 61.5	33.2
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
Property, plant and equipment, gross	$ 18.2	51.3
Less accumulated depreciation	$ (11.4)	(7.5)
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
Property, plant and equipment, gross	$ 21.4	$ 49

Summary of Significant Accoun52

Summary of Significant Accounting Policies (PPE Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Interest Costs
Interest Costs Incurred	$ 185.2	$ 166.8	$ 133.5
Interest Costs Capitalized in PPE	2.1	5.1	28.6
Depreciation [Abstract]
Depreciation	130	125.1	93.2
Capitalized Computer Software [Abstract]
Capitalized Computer Software, Gross	55.8	17.6
Capitalized Computer Software, Accumulated Amortization	20.9	17.2
Assets under capital leases
Depreciation [Abstract]
Depreciation	$ 3.9	3.6	2.6
Software developed or obtained
Depreciation [Abstract]
Property, Plant and Equipment, Useful Life	5 years
Capitalized Computer Software [Abstract]
Amortization	$ 3.3	$ 4.1	$ 4.2

Summary of Significant Accoun53

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Investment in Unconsolidated Affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Other than Temporary Impairment	$ 0
Pacific New Investment Limited [Member]
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Other than Temporary Impairment		$ 0.2
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Other than Temporary Impairment			$ 24.3

Summary of Significant Accoun54

Summary of Significant Accounting Policies (Goodwill and Indefinite Lived Intangibles) (Details)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Reviews for goodwill impairment annually on	Oct. 1, 2017

Summary of Significant Accoun55

Summary of Significant Accounting Policies (Other Noncurrent Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Capitalized major maintenance and repairs	$ 13.4	$ 35.9
Accumulated amortization, capitalized major maintenance and repairs	$ 72.7	$ 101.9
Other Capitalized Property Plant and Equipment [Member] | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	2 years
Other Capitalized Property Plant and Equipment [Member] | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years

Summary of Significant Accoun56

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
RINs Obligation	$ 59.1	$ 79.3
Other	14.6	20.3
Total	$ 73.7	$ 99.6

Summary of Significant Accoun57

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Impairment of Long-Lived Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets Held-for-use			$ 0
Specialty Product
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets Held-for-use		$ (0.9)
Missouri [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ (59.2)
San Antonio [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ (147)

Summary of Significant Accoun58

Summary of Significant Accounting Policies (Income Taxes) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Unrecognized Tax Benefits	$ 0	$ 0

Summary of Significant Accoun59

Summary of Significant Accounting Policies (Shipping and Handling Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Shipping and handling costs	$ 137.1	$ 154.3	$ 153.6

Summary of Significant Accoun60

Summary of Significant Accounting Policies (Advertising Expenses) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Advertising expense	$ 6.6	$ 9.9	$ 14.2

Summary of Significant Accoun61

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Correction of Immaterial Errors) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Increase to cost of sales									$ 3,265.6	$ 3,088	$ 3,393.9
Income tax expense (benefit) from continuing operations									(0.1)	0.2	0.2
Decrease to Net loss	$ 83.6	$ 23.6	$ (9.6)	$ 6.2	$ 79.6	$ 33.4	$ 147.9	$ 67.7	$ 103.8	328.6	$ 139.4
Accounting For Lower Of Cost Or Market Of Inventory And Income Taxes [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Increase to cost of sales										6.5
Income tax expense (benefit) from continuing operations										(7.8)
Decrease to Net loss										$ (1.3)

Discontinued Operations Disco62

Discontinued Operations Discontinued Operations (Narrative) (Details) - USD ($) $ in Millions	Nov. 21, 2017	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale of business			$ 62.6	$ 0	$ 0
Other accounts receivable			88.7	$ 22.2
Income Tax Refunds, Discontinued Operations		$ 7.8
Anchor
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total consideration	$ 89.6
Base price	50
Working capital adjustment	$ 14.2
Working capital adjustment payment period	24 months
Other accounts receivable			15.1
Nontrade Receivables, Noncurrent			$ 7.1
Fluid Holding Corp
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percent Ownership	10.00%		10.00%	0.00%

Discontinued Operations Disco63

Discontinued Operations Discontinued Operations Results of Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales									$ 228.6	$ 125.1	$ 282.5
Cost of sales									(168.1)	(103.1)	(224.3)
Asset Impairment									0	0	(33.8)
Loss on sale of business									(62.6)	0	0
Other									(21)	(16)	(23.2)
Net income before income taxes									(73.5)	(39.7)	(82.6)
Income tax benefit									(1)	(7.9)	(28.6)
Net loss from discontinued operations net of income tax benefit	$ (64.9)	$ 2.5	$ (2.4)	$ (7.7)	$ (8.1)	$ (0.3)	$ (12.6)	$ (10.8)	(72.5)	(31.8)	(54)
Selling and Marketing Expense [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
SG&A Expense									(45.9)	(40.9)	(74.2)
General and Administrative Expense [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
SG&A Expense									$ (4.5)	$ (4.8)	$ (9.6)

Discontinued Operations Disco64

Discontinued Operations Discontinued Operations Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Accounts receivable, net		$ 33.8
Inventories		28.4
Prepaid expenses and other current assets		0.4
Total discontinued operations, current assets	$ 0	62.6
Property, plant and equipment, net		45.6
Investment in unconsolidated affiliates		0.7
Other intangible assets, net		45
Total discontinued operations, noncurrent assets	0	91.3
Total assets held for sale		153.9
Accounts payable		19.6
Accrued salaries, wages and benefits		0.4
Other taxes payable		0.4
Total discontinued operations, current liabilities	$ 2	$ 20.4

Divestitures (Details)

Divestitures (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015	Nov. 08, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales	$ 883.8	$ 1,026.5	$ 967	$ 886.5	$ 909.8	$ 932.3	$ 951.6	$ 680.6	$ 3,763.8		$ 3,474.3		$ 3,930.3
Gross Profit	97.3	$ 127.7	$ 143.7	$ 129.5	72.5	$ 103	$ 130.5	$ 80.3	498.2	[1]	386.3	[1]	536.4
Gain on sale of business									236		0		0
Net income before income taxes									(73.5)		(39.7)		(82.6)
Other accounts receivable	88.7				$ 22.2				88.7		22.2
Superior
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales									669.1		681.2		856.8
Gross Profit									110		68.5		137.6
Total consideration														$ 533.1
Base price														435
Working capital adjustment														$ 98.1
Gain on sale of business									236
Net income before income taxes									99.3		$ 54.5		$ 121
Other accounts receivable	41								41
Maximum | Superior
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other accounts receivable	$ 45								$ 45
[1]	The sum of the four quarters may not equal the total year due to rounding.

Investment in Unconsolidated 66

Investment in Unconsolidated Affiliate Investment in Unconsolidated Affiliate (Schedule) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Nov. 21, 2017	Dec. 31, 2016	Aug. 05, 2015
Schedule of Equity Method Investments [Line Items]
Investment	$ 35		$ 9.6
Pacific New Investment Limited [Member]
Schedule of Equity Method Investments [Line Items]
Investment	$ 9.6		$ 9.6
Percent Ownership	23.80%		23.80%	23.80%
Fluid Holding Corp
Schedule of Equity Method Investments [Line Items]
Investment	$ 25.4		$ 0
Percent Ownership	10.00%	10.00%	0.00%

Investment in Unconsolidated 67

Investment in Unconsolidated Affiliate (Details Textuals) - USD ($) $ in Millions	Jun. 27, 2016	Jun. 09, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 21, 2017	Oct. 15, 2016	Jun. 30, 2016	Sep. 30, 2015	Aug. 05, 2015
Schedule of Equity Method Investments [Line Items]
Proceeds from sale of unconsolidated affiliates			$ 0	$ 29	$ 0
Repayments of Long-term Lines of Credit			911.2	1,287.9	1,429.8
Loss on sale of unconsolidated affiliates				(113.9)
Investment in unconsolidated affiliates			35	9.6
Investment in Unconsolidated Affiliates, Other than Temporary Impairment			$ 0
Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Percent Ownership	50.00%
Proceeds from sale of unconsolidated affiliates	$ 28.5
Repayments of Long-term Lines of Credit	36
Letters of Credit Outstanding, Amount	$ 39.4
Loss on sale of unconsolidated affiliates				$ (113.9)
Pacific New Investment Limited [Member]
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Percent Ownership			23.80%	23.80%						23.80%
Investment in Unconsolidated Affiliates, Aggregate Cost							$ 4.8	$ 4.8
Investment in unconsolidated affiliates			$ 9.6	$ 9.6
Investment in Unconsolidated Affiliates, Other than Temporary Impairment				$ 0.2
Hi-Speed [Member]
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Percent Ownership										6.00%
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Percent Ownership		23.00%
Contribution amount funded		$ 25
Joint Venture, Ownership Percentage in Entity		100.00%
Investment in unconsolidated affiliates									$ 24.3
Investment in Unconsolidated Affiliates, Other than Temporary Impairment					$ 24.3
Fluid Holding Corp
Schedule of Equity Method Investments [Line Items]
Investment in Unconsolidated Affiliates, Percent Ownership			10.00%	0.00%		10.00%
Investment in unconsolidated affiliates			$ 25.4	$ 0
related party purchases [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Amounts of Transaction				5.3
Due to Related Parties, Current				0
related party sales [Member] | Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Amounts of Transaction				14.7
Trade accounts and other receivables				$ 0

Changes in Goodwill Balances (D

Changes in Goodwill Balances (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Total accumulated goodwill impairment		$ (35.5)	$ (34.8)
Goodwill
Beginning Balance		177.2	212
Impairment (1)	[1]	(0.7)	(34.8)
Goodwill, Written off Related to Sale of Business Unit	[2]	(5.1)
Ending Balance		171.4	177.2
Specialty Product
Goodwill
Beginning Balance		172.1	173.5
Impairment (1)	[1]	(0.7)	(1.4)
Goodwill, Written off Related to Sale of Business Unit		0
Ending Balance		171.4	172.1
Fuel Product
Goodwill
Beginning Balance		5.1	38.5
Impairment (1)	[1]	0	(33.4)
Goodwill, Written off Related to Sale of Business Unit	[2]	(5.1)
Ending Balance		$ 0	$ 5.1
[1]	(1) Total accumulated goodwill impairment as of December 31, 2017 and 2016, is $35.5 million and $34.8 million
[2]	Divestiture relates to sale of the Superior Refinery.

Other Intangible Assets (Detail

Other Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Gross Amount	$ 268.6	$ 274
Accumulated Amortization	$ (160.7)	(140.5)
Weighted Average Life (Years)	19 years
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Gross Amount	$ 181.3	186.7
Accumulated Amortization	$ (107.6)	(97.2)
Weighted Average Life (Years)	22 years
Tradenames
Finite-Lived Intangible Assets [Line Items]
Gross Amount	$ 26.8	26.8
Accumulated Amortization	$ (13.8)	(9.9)
Weighted Average Life (Years)	11 years
Trade secrets
Finite-Lived Intangible Assets [Line Items]
Gross Amount	$ 52.7	52.7
Accumulated Amortization	$ (35.1)	(29.6)
Weighted Average Life (Years)	13 years
Patents
Finite-Lived Intangible Assets [Line Items]
Gross Amount	$ 1.6	1.6
Accumulated Amortization	$ (1.6)	(1.5)
Weighted Average Life (Years)	12 years
Royalty agreements
Finite-Lived Intangible Assets [Line Items]
Gross Amount	$ 6.2	6.2
Accumulated Amortization	$ (2.6)	$ (2.3)
Weighted Average Life (Years)	19 years

Estimated Future Amortization o

Estimated Future Amortization of Intangible Assets (Details) $ in Millions	Dec. 31, 2017USD ($)
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
2,018	$ 19.9
2,019	16.8
2,020	14
2,021	11.5
2,022	$ 9.4

Goodwill and Other Intangible71

Goodwill and Other Intangible Assets (Details Textual) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill impairment losses	[1]	$ 0.7	$ 34.8
Amortization expense of intangible assets		24.6	26.9	$ 29.4
Fuel Product
Goodwill [Line Items]
Goodwill impairment losses	[1]	0	33.4
Specialty Product
Goodwill [Line Items]
Goodwill impairment losses	[1]	$ 0.7	$ 1.4
[1]	(1) Total accumulated goodwill impairment as of December 31, 2017 and 2016, is $35.5 million and $34.8 million

Commitments and Contingencies72

Commitments and Contingencies (Operating Leases) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating leases, rent expense	$ 53.2	$ 56.6	$ 57.6
Operating Leases, Future Minimum Commitments
2,018	31.4
2,019	21.7
2,020	16.7
2,021	9.5
2,022	7.3
Thereafter	10.8
Total	$ 97.4

Commitments and Contingencies73

Commitments and Contingencies (Crude Oil Supply, Other Feedstocks and Finished Products) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)bbl / d
Purchase Obligation, Future Minimum Commitments
2,018	$ 297.5
2,019	126.7
2,020	21.1
2,021	21
2,022	21
Thereafter	84.2
Total	571.5
Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Annual purchase amount	$ 114
LVT Feedstock Agreement
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Initial term	3 months
Annual purchase amount	$ 11.4
Naphthenic Lubricating Oils | Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required | bbl / d	3,100
White Mineral Oil | Houston Refining
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required | bbl / d	600

Commitments and Contingencies74

Commitments and Contingencies (Environmental) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Great Falls [Member]
Loss Contingencies [Line Items]
Environmental remediation expense	$ 18.7
Environmental Costs Recognized, Capitalized in Period	14.6
Great Falls [Member] | Expense [Member]
Loss Contingencies [Line Items]
Environmental remediation expense	2.4
LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense	0.7	$ 2.4
Shreveport
Loss Contingencies [Line Items]
Specified environmental liabilities first	5
Shreveport | Maximum
Loss Contingencies [Line Items]
Specified environmental liabilities first required to contribute up to	1
Fair Value, Measurements, Recurring
Loss Contingencies [Line Items]
Obligations, Fair Value Disclosure	$ 59.1	$ 79.3

Commitments and Contingencies75

Commitments and Contingencies (OSHA) (Details) $ in Millions	Mar. 14, 2011USD ($)
Occupational Safety and Health Administration
Loss Contingencies [Line Items]
Proposed penalty	$ 0.2

Commitments and Contingencies76

Commitments and Contingencies (Labor Matters) (Details)	12 Months Ended
	Dec. 31, 2017employee
Concentration Risk [Line Items]
Number of employees	1,600
Labor Force Concentration Risk | Workforce Subject to Collective Bargaining Arrangements
Concentration Risk [Line Items]
Number of employees	500
Number of Employees Concentration Risk, Percentage	31.00%
Labor Force Concentration Risk | Workforce Subject to Collective Bargaining Arrangements Expiring within One Year
Concentration Risk [Line Items]
Number of employees	0

Commitments and Contingencies77

Commitments and Contingencies (Standby Letters of Credit) (Details) - Revolving Credit Facility [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Letters of credit outstanding amount	$ 67.3	$ 82.1
Letter of Credit Availability	252	360.8
Maximum
Debt Disclosure [Abstract]
Letter of credit sublimit	$ 600	$ 600
Letter of credit sublimit percentage	90.00%	90.00%
Senior secured revolving credit facility	$ 900	$ 900

Inventory Financing Agreement78

Inventory Financing Agreement Inventory Financing Agreement (Details) $ in Millions	Jun. 19, 2017USD ($)bbl / dbbl	Mar. 31, 2017USD ($)bbl / dbbl	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proceeds from inventory financing agreements			$ (100.1)	$ 0	$ 0
Financing Costs			183.1	$ 161.7	$ 104.9
Supply and Offtake Agreements [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Inventory sold (in barrels) | bbl	987,000	652,000
Proceeds from inventory financing agreements	$ 54.8	$ 32.2
Barrels of crude oil per day provided by Macquarie (in barrels per day) | bbl / d	60,000	30,000
Debt Issuance Costs, Current, Net			3.1
Financing Costs			6.8
Deferred payment arrangement, maximum amount			$ 17.8
Deferred payment arrangement, maximum percentage of eligible inventory			90.00%
Deferred payment arrangement, outstanding amount			$ 11.3
Supply and Offtake Agreements [Member] | London Interbank Offered Rate (LIBOR)
Oil and Gas Delivery Commitments and Contracts [Line Items]
Debt Instrument, Basis Spread on Variable Rate			3.25%
Macquarie [Member] | Supply and Offtake Agreements [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Amount retained from initial inventory to cover credit and liquidation risks			$ 4

Long-Term Debt (Long Term Debt)

Long-Term Debt (Long Term Debt) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of Long-term debt
Other Long-term Debt		$ 6.6	$ 8
Less unamortized debt issuance costs	[1]	(25.9)	(33.2)
Total long-term debt		1,992.3	1,997.2
Less current portion of long-term debt (3)		354.1	3.5
Long-term Debt, Excluding Current Maturities		1,638.2	1,993.7
Senior Notes [Abstract]
Restricted cash		350	0	$ 0
Revolving Credit Facility [Member]
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 8.4% and 4.8% at December 31, 2017 and 2016, respectively		$ 0.2	$ 10.2
Debt, Weighted Average Interest Rate		8.40%	4.80%
11.50% Notes
Summary of Long-term debt
Borrowings under Senior Notes		$ 400	$ 400
Senior Notes [Abstract]
Stated Interest Rate Percentage		11.50%	11.50%
Effective Interest Rate Percentage		12.30%	12.20%
6.50% Notes
Summary of Long-term debt
Borrowings under Senior Notes		$ 900	$ 900
Senior Notes [Abstract]
Stated Interest Rate Percentage		6.50%	6.50%
Effective Interest Rate Percentage		6.80%	6.80%
7.625% Notes
Summary of Long-term debt
Borrowings under Senior Notes	[2]	$ 352.1	$ 352.5
Senior Notes [Abstract]
Stated Interest Rate Percentage		7.625%	7.625%
Effective Interest Rate Percentage		8.00%	8.00%
7.75% Notes
Summary of Long-term debt
Borrowings under Senior Notes		$ 325	$ 325
Senior Notes [Abstract]
Stated Interest Rate Percentage		7.75%	7.75%
Effective Interest Rate Percentage		8.00%	8.00%
Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034
Summary of Long-term debt
Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034		$ 44	$ 46.5
Less unamortized discounts
Summary of Long-term debt
Less unamortized discounts		(9.7)	(11.8)
Fair Value Hedging [Member] | Interest Expense [Member]
Senior Notes [Abstract]
Liabilities, Fair Value Adjustment		$ 2.1	$ 2.5
[1]	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 $21.8 million and $14.5 million at December 31, 2017 and 2016, respectively.
[2]	The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.1 million and $2.5 million as of December 31, 2017 and 2016, respectively.

Long-Term Debt (Revolver) (Deta

Long-Term Debt (Revolver) (Details) - Revolving Credit Facility [Member]	12 Months Ended
	Dec. 31, 2017
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 Debt (

Long-Term Debt Long-Term Debt (Capital Leases) (Details) $ in Millions	Dec. 31, 2017USD ($)
Capital Leased Assets [Line Items]
2,018	$ 9
2,019	7.4
2,020	6.9
2,021	6.9
2,022	6.9
Thereafter	82.1
Total minimum lease payments	119.2
Less amount representing interest	75.2
Capital lease obligations	44
Less obligations due within one year	2.7
Long-term capital lease obligations	$ 41.3

Long-Term Debt (Maturities of L

Long-Term Debt (Maturities of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2017USD ($)
Maturities of long-term debt
2,018	$ 354.1
2,019	2.9
2,020	2.4
2,021	953.3
2,022	351.2
Thereafter	361.9
Total	$ 2,025.8

Long-Term Debt (Details Textual

Long-Term Debt (Details Textual)	Apr. 20, 2016USD ($)	Apr. 28, 2015USD ($)	Mar. 27, 2015USD ($)	Mar. 31, 2014USD ($)	Nov. 26, 2013USD ($)	Dec. 31, 2017USD ($)bbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Long Term Debt Textual [Abstract]
Accumulated amortization, deferred debt issuance costs						$ 21,800,000	$ 14,500,000
Repayments of borrowings — senior notes						0	0	$ (275,000,000)
Debt Instrument, Collateral Amount						$ 150,000,000
Imputed Interest								$ 1,500,000
TexStar pipeline capacity | bbl						30,000
TexStar contract period						20 years
TexStar Capital Lease Obligation						$ 39,400,000	39,400,000
TexStar Depreciation						$ 2,000,000	$ 2,000,000
Minimum
Long Term Debt Textual [Abstract]
TexStar KNPS Expected Delivery Capacity | bbl						12,000
11.50% Notes
Long Term Debt Textual [Abstract]
Senior Notes, Issuance Date	Apr. 20, 2016
Senior Notes Issued, Gross	$ 400,000,000
Maturity date	Jan. 15, 2021
Debt Instrument Percentage of Discount Price	98.273%
Proceeds from debt	$ 382,500,000
Interest and principal payments of debt instruments	semiannually
Stated Interest Rate Percentage						11.50%	11.50%
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
Stated Interest Rate Percentage						7.75%	7.75%
6.50% Notes
Long Term Debt Textual [Abstract]
Debt Instrument Percentage of Discount Price				100.00%
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
Proceeds from debt				$ 884,000,000
Interest and principal payments of debt instruments				semiannually
Stated Interest Rate Percentage						6.50%	6.50%
9.375% Notes
Long Term Debt Textual [Abstract]
Repayments of borrowings — senior notes				$ (500,000,000)	$ (100,000,000)
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
Stated Interest Rate Percentage						7.625%	7.625%
9.625% Notes
Long Term Debt Textual [Abstract]
Repayments of borrowings — senior notes		$ (178,800,000)
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						$ 900,000,000	$ 900,000,000
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						$ 319,000,000
Line of Credit Facility, Amount Outstanding						200,000	10,200,000
Available for additional borrowings based on specified availability limitations						$ 252,000,000
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 (which amount is subject to increase in proportion to revolving commitment increases), 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 until availability under the revolving credit facility exceeds the greater of the foregoing amounts for 30 consecutive days
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] | Maximum
Long Term Debt Textual [Abstract]
Fixed charge coverage ratio						1.7
The Heritage Group [Member]
Long Term Debt Textual [Abstract]
Stated Interest Rate Percentage								6.00%
Debt Instrument, Periodic Payment, Principal							15,000,000
Prime Rate | Revolving Credit Facility [Member]
Long Term Debt Textual [Abstract]
Debt Instrument, Basis Spread on Variable Rate						50.00%
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility [Member]
Long Term Debt Textual [Abstract]
Debt Instrument, Basis Spread on Variable Rate						150.00%
Revolving Credit Facility [Member]
Long Term Debt Textual [Abstract]
Letters of Credit Outstanding, Amount						$ 67,300,000	82,100,000
Revolving Credit Facility [Member] | Maximum
Long Term Debt Textual [Abstract]
Senior secured revolving credit facility						900,000,000	900,000,000
Fair Value Hedging [Member] | Interest Expense [Member]
Long Term Debt Textual [Abstract]
Liabilities, Fair Value Adjustment						$ 2,100,000	$ 2,500,000
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

Derivatives (Offsetting Derivat

Derivatives (Offsetting Derivative Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 0.3	$ 10.5
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(0.3)	(9.7)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0.8
Natural Gas Swaps | Not Designated as Hedging Instrument | Specialty Product
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(0.1)
Derivative Asset	0	0
Crude Oil Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0.3	10.3
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(0.3)	(7.4)
Derivative Asset	0	2.9
Crude Oil Basis Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(2.1)
Derivative Asset	0	(2.1)
Crude Oil Percent Basis Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Assets [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0.1
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	(0.1)
Derivative Asset	$ 0	$ 0

Derivatives (Offsetting Deriv85

Derivatives (Offsetting Derivative Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (10.7)	$ (24.5)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.3	9.7
Derivative Liability	(10.4)	(14.8)
Natural Gas Swaps | Not Designated as Hedging Instrument | Specialty Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(1.2)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0.1
Derivative Liability	0	(1.1)
Supply and Offtake Agreements [Member] | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(4.4)	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(4.4)	0
Crude Oil Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(8.2)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0.3	7.4
Derivative Liability	0.3	(0.8)
Crude Oil Basis Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(7.1)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	2.1
Derivative Liability	0	(5)
Crude Oil Percent Basis Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(0.6)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0.1
Derivative Liability	0	(0.5)
Gasoline Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(0.2)	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(0.2)	0
Gasoline Crack Spread Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1.8)	(3.5)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(1.8)	(3.5)
Diesel Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(0.2)	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(0.2)
Diesel Crack Spread Swaps | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(4.1)	(1.4)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(4.1)	(1.4)
2-1-1- Crack Spread Swap | Not Designated as Hedging Instrument | Fuel Product
Offsetting Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(2.5)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	$ 0	$ (2.5)

Derivatives (Not Designated as

Derivatives (Not Designated as Hedges) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Commodity Contract [Member] | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (13.2)	$ (24)
Commodity Contract [Member] | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3.6	19.9
Specialty Product | Natural Gas Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(3.6)	(11.3)
Specialty Product | Natural Gas Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1	14.7
Fuel Product | Natural Gas Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(1.3)
Fuel Product | Natural Gas Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	1.3
Fuel Product | Crude Oil Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1.9)	5.3
Fuel Product | Crude Oil Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1.7)	7.3
Fuel Product | Crude Oil Basis Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3.2	(4.1)
Fuel Product | Crude Oil Basis Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	7.1	(5.9)
Fuel Product | Crude Oil Percent Basis Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	2.3	(4.3)
Fuel Product | Crude Oil Percent Basis Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0.5	5.4
Fuel Product | Crude Oil Options [Member] | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(2.6)
Fuel Product | Crude Oil Options [Member] | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0.3
Fuel Product | Crude Oil Futures [Member] | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(2)
Fuel Product | Crude Oil Futures [Member] | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Fuel Product | Gasoline Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.6)	0
Fuel Product | Gasoline Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.2)	0
Fuel Product | Gasoline Crack Spread Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(6.2)	(2.5)
Fuel Product | Gasoline Crack Spread Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3	(0.5)
Fuel Product | Diesel Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.5)	0
Fuel Product | Diesel Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.2)	0
Fuel Product | Diesel Crack Spread Swaps | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(5)	(0.4)
Fuel Product | Diesel Crack Spread Swaps | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1.5)	(2.7)
Fuel Product | 2-1-1- Crack Spread Swap | Realized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(0.9)	(0.8)
Fuel Product | 2-1-1- Crack Spread Swap | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Supply and Offtake Agreements [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
Supply and Offtake Agreements [Member] | Fuel Product | Unrealized Gain (Loss)
Derivative instruments not designated as cash flow hedges
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (4.4)	$ 0

Derivatives (Natural Gas Swaps

Derivatives (Natural Gas Swaps - Specialty Product) (Details) - Natural Gas Swaps Purchased [Member] - Specialty Product - Not Designated as Hedging Instrument	Dec. 31, 2017bbl	Dec. 31, 2016bbl$ / MMBtu
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	0	4,950,000
$/MMBtu | $ / MMBtu		3.85
First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		1,350,000
$/MMBtu | $ / MMBtu		3.88
Fourth Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		960,000
$/MMBtu | $ / MMBtu		3.72
Second Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		1,320,000
$/MMBtu | $ / MMBtu		3.87
Third Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		1,320,000
$/MMBtu | $ / MMBtu		3.87

Derivatives (Crude Oil Swaps) (

Derivatives (Crude Oil Swaps) (Details) - Fuel Product - Not Designated as Hedging Instrument	Dec. 31, 2017bbl$ / bbl	Dec. 31, 2016bbl$ / bbl
Crude Oil Swap Sales [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	528,520
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Sales [Member] | First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		130,320
Barrels per Day Sold		1,448
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Sales [Member] | Second Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		131,768
Barrels per Day Sold		1,448
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Sales [Member] | Third Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		133,216
Barrels per Day Sold		1,448
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Sales [Member] | Fourth Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		133,216
Barrels per Day Sold		1,448
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Purchases [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	28,000	1,297,976
Average Swap ($/Bbl) | $ / bbl	48.25	48.87
Crude Oil Swap Purchases [Member] | First Quarter 2018
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	28,000
Barrels per Day Purchased	311
Average Swap ($/Bbl) | $ / bbl	48.25
Crude Oil Swap Purchases [Member] | First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		320,049
Barrels per Day Purchased		3,556
Average Swap ($/Bbl) | $ / bbl		48.87
Crude Oil Swap Purchases [Member] | Second Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		323,605
Barrels per Day Purchased		3,556
Average Swap ($/Bbl) | $ / bbl		48.87
Crude Oil Swap Purchases [Member] | Third Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		327,161
Barrels per Day Purchased		3,556
Average Swap ($/Bbl) | $ / bbl		48.87
Crude Oil Swap Purchases [Member] | Fourth Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		327,161
Barrels per Day Purchased		3,556
Average Swap ($/Bbl) | $ / bbl		48.87

Derivatives (Crude Oil Basis Sw

Derivatives (Crude Oil Basis Swaps) (Details) - Crude Oil Basis Swaps - Fuel Product - Not Designated as Hedging Instrument	Dec. 31, 2017bbl	Dec. 31, 2016bbl$ / bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	2,555,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl		(13.22)
Third Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		644,000
Barrels per Day Purchased		7,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl		(13.22)
Fourth Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		644,000
Barrels per Day Purchased		7,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl		(13.22)
First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		630,000
Barrels per Day Purchased		7,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl		(13.22)
Second Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		637,000
Barrels per Day Purchased		7,000
Derivative, Average Swap Differential to Publicly Traded Future | $ / bbl		(13.22)

Derivatives Derivatives (Crude

Derivatives Derivatives (Crude Oil Percent Basis Swaps) (Details) - Crude Oil Percent Basis Swaps Purchased [Member] - Fuel Product - Not Designated as Hedging Instrument - bbl	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	1,095,000
Derivative, Fixed Percentage to Publicly Traded Future		72.30%
First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		270,000
Barrels per Day Purchased		3,000
Derivative, Fixed Percentage to Publicly Traded Future		72.30%
Second Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		273,000
Barrels per Day Purchased		3,000
Derivative, Fixed Percentage to Publicly Traded Future		72.30%
Third Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		276,000
Barrels per Day Purchased		3,000
Derivative, Fixed Percentage to Publicly Traded Future		72.30%
Fourth Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		276,000
Barrels per Day Purchased		3,000
Derivative, Fixed Percentage to Publicly Traded Future		72.30%

Derivatives Derivatives (Gasoli

Derivatives Derivatives (Gasoline Crack Spread Swaps) (Details) - Not Designated as Hedging Instrument - Gasoline Crack Spread Swaps Sold [Member] - Fuel Product	Dec. 31, 2017bbl$ / bbl	Dec. 31, 2016bbl$ / bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	826,000	590,000
Average Swap ($/Bbl) | $ / bbl	12.27	10.21
First Quarter 2018
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	826,000
Barrels per Day Sold	9,178
Average Swap ($/Bbl) | $ / bbl	12.27
First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		590,000
Barrels per Day Sold		6,556
Average Swap ($/Bbl) | $ / bbl		10.21

Derivatives Derivatives (gaso92

Derivatives Derivatives (gasoline swaps) (Details) - Fuel Product - Not Designated as Hedging Instrument - Gasoline swaps	Dec. 31, 2017bbl$ / bbl	Dec. 31, 2016bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	14,000	0
Average Swap ($/Bbl) | $ / bbl	61.35
First Quarter 2018
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	14,000
Barrels per Day Sold	156
Average Swap ($/Bbl) | $ / bbl	61.35

Derivatives Derivatives (Diesel

Derivatives Derivatives (Diesel Crack Spread Swaps) (Details) - Fuel Product - Not Designated as Hedging Instrument - Diesel Crack Spread Swaps	Dec. 31, 2017bbl$ / bbl	Dec. 31, 2016bbl$ / bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	826,000	590,000
Average Swap ($/Bbl) | $ / bbl	17.58	13.67
First Quarter 2018
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	826,000
Barrels per Day Sold	9,178
Average Swap ($/Bbl) | $ / bbl	17.58
First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		590,000
Barrels per Day Sold		6,556
Average Swap ($/Bbl) | $ / bbl		13.67

Derivatives Derivatives (Dies94

Derivatives Derivatives (Diesel Swaps) (Details) - Not Designated as Hedging Instrument - Fuel Product - Diesel Swaps	Dec. 31, 2017bbl$ / bbl	Dec. 31, 2016bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	14,000	0
Average Swap ($/Bbl) | $ / bbl	66.35
First Quarter 2018
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	14,000
Barrels per Day Sold	156
Average Swap ($/Bbl) | $ / bbl	66.35

Derivatives Derivatives (2_1_1

Derivatives Derivatives (2/1/1 Crack Spread Swaps) (Details) - Fuel Product - Not Designated as Hedging Instrument - 2-1-1- Crack Spread Swap	Dec. 31, 2017bbl	Dec. 31, 2016bbl$ / bbl
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	590,000
Average Swap ($/Bbl) | $ / bbl		11.91
First Quarter 2017
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		590,000
Barrels per Day Sold		6,556
Average Swap ($/Bbl) | $ / bbl		11.91

Derivatives (Details Textual) (

Derivatives (Details Textual) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Securities	$ 0	$ 0
Collateral Already Posted, Aggregate Fair Value	$ 0	$ 0
Derivative, Counterparty	0	one
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ 0	$ 0.8
Cash Flow Hedging [Member] | Designated as Hedging Instrument
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0	$ 6.4

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative assets:
Pension plan investments	$ 35.4	$ 49.8
Derivative liabilities:
Total derivative liabilities	(10.4)	(14.8)
Fair Value, Measurements, Recurring
Derivative assets:
Total derivative assets	0	0.8
Pension plan investments	0.2	0.3
Total recurring assets at fair value	0.2	1.1
Derivative liabilities:
Total derivative liabilities	(10.4)	(14.8)
RINS Obligation	(59.1)	(79.3)
Other Liabilities, Fair Value Disclosure	(5.6)	0
Total recurring liabilities at fair value	(75.1)	(94.1)
Fair Value, Measurements, Recurring | Level 1
Derivative assets:
Total derivative assets	0	0
Pension plan investments	0.2	0.3
Total recurring assets at fair value	0.2	0.3
Derivative liabilities:
Total derivative liabilities	0	0
RINS Obligation	0	0
Other Liabilities, Fair Value Disclosure	(5.6)	0
Total recurring liabilities at fair value	(5.6)	0
Fair Value, Measurements, Recurring | Level 2
Derivative assets:
Total derivative assets	0	0
Pension plan investments	0	0
Total recurring assets at fair value	0	0
Derivative liabilities:
Total derivative liabilities	0	0
RINS Obligation	(59.1)	(79.3)
Other Liabilities, Fair Value Disclosure	0	0
Total recurring liabilities at fair value	(59.1)	(79.3)
Fair Value, Measurements, Recurring | Level 3
Derivative assets:
Total derivative assets	0	0.8
Pension plan investments	0	0
Total recurring assets at fair value	0	0.8
Derivative liabilities:
Total derivative liabilities	(10.4)	(14.8)
RINS Obligation	0	0
Other Liabilities, Fair Value Disclosure	0	0
Total recurring liabilities at fair value	(10.4)	(14.8)
Fair Value, Measurements, Recurring | Supply and Offtake Agreements [Member]
Derivative liabilities:
Total derivative liabilities	(4.4)	0
Fair Value, Measurements, Recurring | Supply and Offtake Agreements [Member] | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Supply and Offtake Agreements [Member] | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Supply and Offtake Agreements [Member] | Level 3
Derivative liabilities:
Total derivative liabilities	(4.4)	0
Fair Value, Measurements, Recurring | Crude Oil Swaps
Derivative assets:
Total derivative assets	0	2.9
Derivative liabilities:
Total derivative liabilities	0.3	(0.8)
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	2.9
Derivative liabilities:
Total derivative liabilities	0.3	(0.8)
Fair Value, Measurements, Recurring | Crude Oil Basis Swaps
Derivative assets:
Total derivative assets	0	(2.1)
Derivative liabilities:
Total derivative liabilities	0	(5)
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	(2.1)
Derivative liabilities:
Total derivative liabilities	0	(5)
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps
Derivative liabilities:
Total derivative liabilities	0	(0.5)
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Crude Oil Percent Basis Swaps | Level 3
Derivative liabilities:
Total derivative liabilities	0	(0.5)
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps
Derivative liabilities:
Total derivative liabilities	(1.8)	(3.5)
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline Crack Spread Swaps | Level 3
Derivative liabilities:
Total derivative liabilities	(1.8)	(3.5)
Fair Value, Measurements, Recurring | Gasoline Swaps
Derivative liabilities:
Total derivative liabilities	(0.2)	0
Fair Value, Measurements, Recurring | Gasoline Swaps | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline Swaps | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Gasoline Swaps | Level 3
Derivative liabilities:
Total derivative liabilities	(0.2)	0
Fair Value, Measurements, Recurring | 2-1-1- Crack Spread Swap
Derivative liabilities:
Total derivative liabilities	0	(2.5)
Fair Value, Measurements, Recurring | 2-1-1- Crack Spread Swap | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | 2-1-1- Crack Spread Swap | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | 2-1-1- Crack Spread Swap | Level 3
Derivative liabilities:
Total derivative liabilities	0	(2.5)
Fair Value, Measurements, Recurring | Diesel Swaps
Derivative liabilities:
Total derivative liabilities	(0.2)	0
Fair Value, Measurements, Recurring | Diesel Swaps | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Diesel Swaps | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Diesel Swaps | Level 3
Derivative liabilities:
Total derivative liabilities	(0.2)	0
Fair Value, Measurements, Recurring | Diesel Crack Spread Swaps
Derivative liabilities:
Total derivative liabilities	(4.1)	(1.4)
Fair Value, Measurements, Recurring | Diesel Crack Spread Swaps | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Diesel Crack Spread Swaps | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Diesel Crack Spread Swaps | Level 3
Derivative liabilities:
Total derivative liabilities	(4.1)	(1.4)
Fair Value, Measurements, Recurring | Natural Gas Swaps
Derivative liabilities:
Total derivative liabilities	0	(1.1)
Fair Value, Measurements, Recurring | Natural Gas Swaps | Level 1
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Natural Gas Swaps | Level 2
Derivative liabilities:
Total derivative liabilities	0	0
Fair Value, Measurements, Recurring | Natural Gas Swaps | Level 3
Derivative liabilities:
Total derivative liabilities	0	$ (1.1)
Cash and cash equivalents | Fair Value, Measurements, Recurring | Level 1
Derivative assets:
Pension plan investments	$ 0.2

Fair Value Measurements (Deta98

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Beginning Balance	$ (14)	$ (33.9)
Realized loss on derivative instruments	13.2	24
Unrealized gain on derivative instruments	3.6	19.9
Settlements	13.2	24
Ending Balance	(10.4)	(14)
Total gain included in net loss attributable to changes in unrealized gain	$ 3.6	$ 19.9

Fair Value Measurements (Deta99

Fair Value Measurements (Details 2) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair value | Level 1
Financial Instrument:
Notes Payable, Fair Value Disclosure	$ 1,576.5	$ 1,334.1
Fair value | Level 2
Financial Instrument:
Notes Payable, Fair Value Disclosure	456.4	458.8
Fair value | Revolving Credit Facility [Member] | Level 3
Financial Instrument:
Lines of Credit, Fair Value Disclosure	0.2	6
Fair value | Capital Lease Obligations [Member] | Level 3
Financial Instrument:
Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034	50.6	54.5
Carrying value | Level 1
Financial Instrument:
Notes Payable, Fair Value Disclosure	1,556.4	1,552.2
Carrying value | Level 2
Financial Instrument:
Notes Payable, Fair Value Disclosure	387.6	384.5
Carrying value | Revolving Credit Facility [Member] | Level 3
Financial Instrument:
Lines of Credit, Fair Value Disclosure	0.2	6
Carrying value | Capital Lease Obligations [Member] | Level 3
Financial Instrument:
Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034	$ 50.6	$ 54.5

Fair Value Measurements (Det100

Fair Value Measurements (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Measurements (Textual) [Abstract]
Derivative Credit Risk Valuation Adjustment, Derivative Liabilities	$ 0	$ 0.5
Derivative Credit Risk Valuation Adjustment, Derivative Assets	$ 0	$ 0.1
Reviews for goodwill impairment annually on	Oct. 1, 2017

Partners' Capital Partner's 101

Partners' Capital Partner's Capital (Details 1)	12 Months Ended
	Dec. 31, 2017$ / 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 102

Partners' Capital Partner's Capital (Details Textuals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capital Unit [Line Items]
Regulatory Restrictions on Payment of Dividends	$ 50
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	$ 0	$ 57.4	$ 224.6
General partner's incentive distribution rights	$ 0	$ 0	$ 16.8
Limited Partners' Minimum Vote Required for Removal of General Partner	66.67%
Partners' Capital, Distribution, Fixed Charge Coverage Ratio Threshold	1.5
Lesser of Borrowing Base [Member]
Capital Unit [Line Items]
Partners' Capital, After Distribution Required Threshold Percentage	15.00%
Partners' Capital, After Distribution Required Cash Amount	$ 70
Lesser of Credit Facility Commitments [Member]
Capital Unit [Line Items]
Partners' Capital, After Distribution Required Threshold Percentage	12.50%
Partners' Capital, After Distribution Required Cash Amount	$ 45
Investor [Member]
Capital Unit [Line Items]
General partner equivalent units outstanding (in shares)	60,422,882
Affiliated Entity [Member]
Capital Unit [Line Items]
General partner equivalent units outstanding (in shares)	16,365,919
Limited Partners
Capital Unit [Line Items]
Limited partners common units outstanding (in shares)	76,788,801	76,392,258

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) - Nonvested Phantom Units - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Number of Phantom Units
Nonvested at beginning of period	754,833	420,724	502,120
Granted	2,753,507	1,880,094	343,533
Vested	(925,199)	(1,455,131)	(321,741)
Forfeited	(47,363)	(90,854)	(103,188)
Nonvested at end of period	2,535,778	754,833	420,724
Weighted-Average Grant Date Fair Value
Nonvested at beginning of period	$ 9.58	$ 24.27	$ 26.48
Granted	4.10	4.57	21.70
Vested	7.30	6.35	23.54
Forfeited	9.73	14.82	23.94
Nonvested at end of period	$ 3.11	$ 9.58	$ 24.27

Unit-Based Compensation (Det104

Unit-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 11.6	$ 5.6	$ 7.5
Vested phantom unit grants, liability awards
Unit-Based Compensation (Textual) [Abstract]
Compensation expense related to vested phantom unit grants	7	$ 0	$ 5
Unrecognized compensation costs related to nonvested phantom unit grants	$ 3.3
Nonvested phantom units
Unit-Based Compensation (Textual) [Abstract]
Nonvested performance units	2,535,778	754,833	420,724	502,120
Weighted average fair value on grant date (in dollars per share)	$ 3.11	$ 9.58	$ 24.27	$ 26.48
Unrecognized compensation costs related to nonvested phantom unit grants	$ 7.9	$ 7.2
Unit-Based Compensation nonvested phantom compensation costs are expected to be recognized over a weighted-average period	2 years
Fair value of phantom units vested during the period	$ 7.2	$ 5.8	$ 7
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, 2017
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 (Deta106

Employee Benefit Plans (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Retirement Benefits [Abstract]
Defined Contribution Plan, Cost	$ 5.7	$ 6	$ 5

Employee Benefit Plans (Deta107

Employee Benefit Plans (Details 2) - Pension Plans, Defined Benefit - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Employer contribution	$ 2.3	$ 1.6
Estimated future employer contributions in next fiscal year	0.1
Plan curtailment	$ 0	$ 0	$ (0.9)
Penreco Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	60 months
Montana Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employee's Compensation Period Used in Benefit Calculation	36 months

Employee Benefit Plans (Deta108

Employee Benefit Plans (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in plan assets:
Fair value of plan assets at beginning of year	$ 49.8
Fair value of plan assets at end of year	35.4	$ 49.8
Reconciliation of amounts recognized in the consolidated balance sheets:
Accumulated other comprehensive loss	(6)	(7.1)
Pension Plans, Defined Benefit
Change in projected benefit obligation:
Benefit obligation at beginning of year	60.9	60.3
Service cost	0.1	0.1	$ 0.5
Interest cost	2.3	2.5	2.6
Plan curtailment	0	0	(0.9)
Plan Settlements	0	0.6
Benefit payments	(2.5)	(2.5)
Actuarial loss	4.2	1.1
Reduction due to sale of the Superior Refinery	(26.6)	0
Benefit obligation at end of year	38.3	60.9	60.3
Change in plan assets:
Fair value of plan assets at beginning of year	49.8	47.5
Plan Settlements	0	0.6
Benefit payments	(2.5)	(2.5)
Actual return on assets	7.4	3.8
Employer contribution	2.3	1.6
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Other Change	(0.1)	0
Distribution to acquirer of the Superior Refinery	(21.5)	0
Fair value of plan assets at end of year	35.4	49.8	$ 47.5
Reconciliation of amounts recognized in the consolidated balance sheets:
Accrued benefit obligation, long-term	(2.9)	(11.1)
Unrecognized net actuarial loss	6	7.1
Accumulated other comprehensive loss	6	7.1
Net amount recognized at end of year	3.1	(4)
Other Postretirement Benefits Plan [Member]
Change in projected benefit obligation:
Benefit obligation at beginning of year	0.2
Benefit obligation at end of year	$ 0.2	$ 0.2

Employee Benefit Plans (Deta109

Employee Benefit Plans (Details 4) - Pension Plans, Defined Benefit - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 38.3	$ 60.9
Accumulated benefit obligation in excess of fair value of plan assets, accumulated benefit obligation	38.3	60.9
Accumulated benefit obligation in excess of fair value of plan assets, fair value of plan assets	$ 35.4	$ 49.8

Employee Benefit Plans (Deta110

Employee Benefit Plans (Details 5) - Pension Plans, Defined Benefit - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations in Excess of Plan Assets, Projected Benefit Obligation	$ 38.3	$ 60.9
Projected Benefit Obligations in Excess of Plan Assets, Fair Value of Plan Assets	$ 35.4	$ 49.8

Employee Benefit Plans (Deta111

Employee Benefit Plans (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit
Components of net periodic pension and other post retirement benefits cost
Service cost	$ 0.1	$ 0.1	$ 0.5
Interest cost	2.3	2.5	2.6
Expected return on assets	(2.9)	(3.2)	(3.3)
Amortization of net loss	0.2	0.1	0.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0.7	0	0
Curtailment gain recognized	0	0	(0.9)
Net periodic benefit cost (income)	0.4	(0.5)	$ (0.3)
Other Postretirement Benefits Plan [Member]
Components of net periodic pension and other post retirement benefits cost
Net periodic benefit cost (income)	$ 0	$ 0

Employee Benefit Plans (Deta112

Employee Benefit Plans (Details 7) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Total recognized in other comprehensive (income) loss	$ (1.1)	$ 0.3	$ (4.7)
Classified in accumulated other comprehensive loss	(6)	(7.1)
Amounts that will be amortized from accumulated other comprehensive income in next fiscal year	0.1
Pension Plans, Defined Benefit
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net (gain) loss	(0.2)	0.4	(4.3)
Amortization or settlement recognition of net loss	(0.9)	(0.1)	(0.8)
Total recognized in other comprehensive (income) loss	(1.1)	0.3	$ (5.1)
Classified in accumulated other comprehensive loss	$ 6	$ 7.1

Employee Benefit Plans (Deta113

Employee Benefit Plans (Details 8) - Pension Plans, Defined Benefit		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Penreco Plan
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate		3.56%	4.08%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate		4.08%	4.30%	3.92%
Expected return on plan assets	[1]	6.35%	6.75%	6.75%
Superior Plan [Member]
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate			4.06%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate		4.06%	4.27%	3.86%
Expected return on plan assets	[1]	6.35%	6.75%	6.75%
Montana Plan
Significant Weighted Average Assumptions Used to Determine the Benefit Obligations
Discount rate		3.54%	4.04%
Significant Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate		4.04%	4.21%	4.13%
Expected return on plan assets	[1]	6.35%	6.75%	6.75%
Rate of compensation increase				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.

Employee Benefit Plans (Deta114

Employee Benefit Plans (Details 9)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	1.00%	1.00%
Equity funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Range for Target Allocation, Percentage	20.00%
Defined Benefit Plan, Actual Plan Asset Allocations	12.00%	17.00%
Foreign equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Range for Target Allocation, Percentage	20.00%
Defined Benefit Plan, Actual Plan Asset Allocations	12.00%	17.00%
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Range for Target Allocation, Percentage	60.00%
Defined Benefit Plan, Actual Plan Asset Allocations	75.00%	65.00%
Minimum | Equity funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Percentage	0.15
Minimum | Foreign equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Percentage	0.15
Minimum | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Percentage	0.55
Maximum | Equity funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Percentage	0.25
Maximum | Foreign equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Percentage	0.25
Maximum | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Percentage	0.65

Employee Benefit Plans (Deta115

Employee Benefit Plans (Details 10) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 35.4	$ 49.8
Fair Value, Measurements, Recurring
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0.2	0.3
Level 1 | Fair Value, Measurements, Recurring
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0.2	0.3
Cash and cash equivalents | Level 1 | Fair Value, Measurements, Recurring
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	0.2
Equity funds
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	4.3	8.6
Foreign equities
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	4.4	8.7
Fixed income
Schedule of Pension Plan assets measured at fair value
Fair value of plan assets	$ 26.5	$ 32.2

Employee Benefit Plans (Deta116

Employee Benefit Plans (Details 11) - Pension Plans, Defined Benefit $ in Millions	Dec. 31, 2017USD ($)
Defined Benefit Plan Disclosure [Line Items]
2,018	$ 1.6
2,019	1.7
2,020	1.8
2,021	1.9
2,022	1.9
2023 to 2027	10.7
Total	$ 19.6

Accumulated Other Comprehens117

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	$ (8.3)	$ (1.6)
Other comprehensive income (loss) before reclassifications	0.2	(0.4)
Amounts reclassified from accumulated other comprehensive loss	0.9	(6.3)
Total other comprehensive income (loss)	1.1	(6.7)	$ (15.3)
Ending balance: Accumulated other comprehensive loss	(7.2)	(8.3)	(1.6)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	0	6.4
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive loss	0	(6.4)
Total other comprehensive income (loss)	0	(6.4)
Ending balance: Accumulated other comprehensive loss	0	0	6.4
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	(7.1)	(6.8)
Other comprehensive income (loss) before reclassifications	0.2	(0.4)
Amounts reclassified from accumulated other comprehensive loss	0.9	0.1
Total other comprehensive income (loss)	1.1	(0.3)
Ending balance: Accumulated other comprehensive loss	(6)	(7.1)	(6.8)
Accumulated Translation Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance: Accumulated other comprehensive loss	(1.2)	(1.2)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive loss	0	0
Total other comprehensive income (loss)	0	0
Ending balance: Accumulated other comprehensive loss	$ (1.2)	$ (1.2)	$ (1.2)

Accumulated Other Comprehens118

Accumulated Other Comprehensive Income (Loss) (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total other comprehensive income (loss)	$ 1.1	$ (6.7)	$ (15.3)
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)	0	(6.4)
Accumulated Defined Benefit Plans Adjustment
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total other comprehensive income (loss)	1.1	(0.3)
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	0	59.7
Cost of Goods Sold	0	(53.3)
Total other comprehensive income (loss)	0	6.4
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total other comprehensive income (loss)	(0.9)	(0.1)
Pension Plan
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Amortization or settlement recognition of net loss	$ (0.9)	$ (0.1)	$ (0.8)

Income Taxes Income Taxes (Deta

Income Taxes Income Taxes (Details Textuals) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ (0.1)	$ 0.2	$ 0.2

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net loss from continuing operations	$ (18.7)	$ (26.1)	$ 12	$ 1.5	$ (71.5)	$ (33.1)	$ (135.3)	$ (56.9)	$ (31.3)		$ (296.8)		$ (85.4)
General partner’s interest in net loss from continuing operations									2.1		6.6		2.8
General partner's incentive distribution rights									0		0		16.8
Net income (loss) available to limited partners	$ (81.9)	$ (23.1)	$ 9.2	$ (6.1)	$ (78)	$ (32.7)	$ (145)	$ (66.3)	$ (101.7)		$ (322)	[1]	$ (153.4)
Limited partners' interest basic net loss per unit from continuing operations	$ (0.24)	$ (0.33)	$ 0.15	$ 0.02	$ (0.91)	$ (0.42)	$ (1.73)	$ (0.73)	$ (0.40)		$ (3.77)		$ (1.34)
Limited partners' interest basic net loss per unit from discontinued operations	(0.82)	0.03	(0.03)	(0.10)	(0.10)	0	(0.16)	(0.14)	(0.91)		(0.41)		(0.71)
Limited partners’ interest basic net income (loss) per unit	(1.06)	(0.30)	0.12	(0.08)	(1.01)	(0.42)	(1.89)	(0.87)	(1.31)		(4.18)		(2.05)
Limited partners' interest diluted net loss per unit from continuing operations	(0.24)	(0.33)	0.15	0.02	(0.91)	(0.42)	(1.73)	(0.73)	(0.40)		(3.77)		(1.34)
Limited partners' interest diluted net loss per unit from discontinued operations	(0.82)	0.03	(0.03)	(0.10)	(0.10)	0	(0.16)	(0.14)	(0.91)		(0.41)		(0.71)
Limited partners' interest diluted net income (loss) per unit	$ (1.06)	$ (0.30)	$ 0.12	$ (0.08)	$ (1.01)	$ (0.42)	$ (1.89)	$ (0.87)	$ (1.31)		$ (4.18)		$ (2.05)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									200,000		500,000		400,000
Denominator for basic and diluted earnings per limited partner unit:
Weighted Average Number of Shares Outstanding, Basic and Diluted									77,598,950	[2]	77,043,935		74,896,096
Continuing Operations [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
General partner’s interest in net loss from continuing operations									$ (0.6)		$ (6)		$ (1.7)
Net income (loss) available to limited partners									(30.7)		(290.8)		(100.5)
Discontinued Operations, Disposed of by Sale [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) available to limited partners									$ (71)		$ (31.2)		$ (52.9)
[1]	The sum of the four quarters may not equal the total year due to rounding.
[2]	Total diluted weighted average limited partner units outstanding excludes 0.2 million, 0.5 million and 0.4 million potentially dilutive phantom units which would be antidilutive for the years ended December 31, 2017, 2016 and 2015, respectively.

Transactions with Related Pa121

Transactions with Related Parties Transactions with Related Parties (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Limited Partners
Related Party Transaction [Line Items]
Product sales to related parties	$ 37.9	$ 13.1	$ 12
Trade accounts and other receivables	0.3	1.1
Excluding Legacy Resources
Related Party Transaction [Line Items]
Purchases from related party	7.1	6.4	5
Accounts payable from related parties	3.1	1.5
Monument Chemical [Member]
Related Party Transaction [Line Items]
Purchases from related party	1.2	1.3
Officer [Member]
Related Party Transaction [Line Items]
Purchases from related party	0	10.4	$ 43
Accounts payable from related parties	$ 0	$ 2.5

Segments and Related Informa122

Segments and Related Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reportable segment information
Sales	$ 883.8	$ 1,026.5	$ 967	$ 886.5	$ 909.8	$ 932.3	$ 951.6	$ 680.6	$ 3,763.8	$ 3,474.3	$ 3,930.3
Loss from unconsolidated affiliates									0	(18.3)	(61.1)
Adjusted EBITDA									314.3	178.8	283.6
Reconciling items to net income:
Depreciation and amortization									179.1	185.2	151.6
Realized gain (loss) on derivatives, not reflected in net income (loss)										(6.4)	(10)
Impairment charges									207.3	35.9	24.3
Gain on sale of business									(236)	0	0
Loss on sale of unconsolidated affiliates										113.9
Unrealized (gain) loss on derivatives									(3.6)	(19.9)	39.5
Interest expense									183.1	161.7	104.9
Debt extinguishment costs									0	0	46.6
Non-cash equity-based compensation and other non-cash items									15.8	5	11.9
Income tax expense (benefit)									(0.1)	0.2	0.2
Net loss from continuing operations									(31.3)	(296.8)	(85.4)
Sales Revenue, Segment
Reportable segment information
Sales									3,763.8	3,474.3	3,930.3
Intersubsegment Eliminations
Reportable segment information
Sales									0	0	0
Intersegment Eliminations
Reportable segment information
Sales									(55)	(37)	(42)
Loss from unconsolidated affiliates										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
Impairment charges									0	0	0
Gain on sale of business									0
Loss on sale of unconsolidated affiliates										0
Intersegment Eliminations | Sales Revenue, Segment
Reportable segment information
Sales									0	0	0
Intersegment Eliminations | Intersubsegment Eliminations
Reportable segment information
Sales									(55)	(37)	(42)
Specialty Product | Operating Segments
Reportable segment information
Sales									1,300.6	1,254.8	1,370.7
Loss from unconsolidated affiliates										(0.3)	0
Adjusted EBITDA									186.5	188.9	201.7
Reconciling items to net income:
Depreciation and amortization									70.5	74.7	69.2
Realized gain (loss) on derivatives, not reflected in net income (loss)										1.9	(3)
Impairment charges									60.3	1.9	0
Gain on sale of business									0
Loss on sale of unconsolidated affiliates										0
Specialty Product | Operating Segments | Sales Revenue, Segment
Reportable segment information
Sales									1,300.4	1,252.3	1,367.8
Specialty Product | Operating Segments | Intersubsegment Eliminations
Reportable segment information
Sales									0.2	2.5	2.9
Fuel Product | Operating Segments
Reportable segment information
Sales									2,518.2	2,256.5	2,601.6
Loss from unconsolidated affiliates										(18)	(61.1)
Adjusted EBITDA									127.8	(10.1)	81.9
Reconciling items to net income:
Depreciation and amortization									108.6	110.5	82.4
Realized gain (loss) on derivatives, not reflected in net income (loss)										(8.3)	(7)
Impairment charges									147	34	24.3
Gain on sale of business									(236)
Loss on sale of unconsolidated affiliates										113.9
Fuel Product | Operating Segments | Sales Revenue, Segment
Reportable segment information
Sales									2,463.4	2,222	2,562.5
Fuel Product | Operating Segments | Intersubsegment Eliminations
Reportable segment information
Sales									54.8	34.5	39.1
Combined Segments | Operating Segments
Reportable segment information
Sales									3,818.8	3,511.3	3,972.3
Loss from unconsolidated affiliates										(18.3)	(61.1)
Adjusted EBITDA									314.3	178.8	283.6
Reconciling items to net income:
Depreciation and amortization									179.1	185.2	151.6
Realized gain (loss) on derivatives, not reflected in net income (loss)										(6.4)	(10)
Impairment charges									207.3	35.9	24.3
Gain on sale of business									(236)
Loss on sale of unconsolidated affiliates										113.9
Combined Segments | Operating Segments | Sales Revenue, Segment
Reportable segment information
Sales									3,763.8	3,474.3	3,930.3
Combined Segments | Operating Segments | Intersubsegment Eliminations
Reportable segment information
Sales									$ 55	$ 37	$ 42

Segments and Related Informa123

Segments and Related Information (Details 1) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Major product category sales
Sales	$ 883.8	$ 1,026.5	$ 967	$ 886.5	$ 909.8	$ 932.3	$ 951.6	$ 680.6	$ 3,763.8	$ 3,474.3	$ 3,930.3
Product Concentration Risk
Major product category sales
Sales									$ 3,763.8	$ 3,474.3	$ 3,930.3
Concentration Risk, Percentage									100.00%	100.00%	100.00%
Product Concentration Risk | Specialty Product
Major product category sales
Sales									$ 1,300.4	$ 1,252.3	$ 1,367.8
Concentration Risk, Percentage									34.50%	36.00%	34.80%
Product Concentration Risk | Specialty Product | Lubricating oils
Major product category sales
Sales									$ 584.2	$ 538.7	$ 575.6
Concentration Risk, Percentage									15.50%	15.50%	14.60%
Product Concentration Risk | Specialty Product | Solvents
Major product category sales
Sales									$ 274.4	$ 237.7	$ 302
Concentration Risk, Percentage									7.30%	6.80%	7.70%
Product Concentration Risk | Specialty Product | Waxes
Major product category sales
Sales									$ 117.2	$ 128.7	$ 136.9
Concentration Risk, Percentage									3.10%	3.70%	3.50%
Product Concentration Risk | Specialty Product | Packaged and synthetic specialty products
Major product category sales
Sales									$ 260.7	$ 244.7	$ 261.5
Concentration Risk, Percentage									6.90%	7.00%	6.70%
Product Concentration Risk | Specialty Product | Other
Major product category sales
Sales									$ 63.9	$ 102.5	$ 91.8
Concentration Risk, Percentage									1.70%	3.00%	2.30%
Product Concentration Risk | Fuel Product
Major product category sales
Sales									$ 2,463.4	$ 2,222	$ 2,562.5
Concentration Risk, Percentage									65.50%	64.00%	65.20%
Product Concentration Risk | Fuel Product | Gasoline
Major product category sales
Sales									$ 948.5	$ 844.3	$ 1,047.1
Concentration Risk, Percentage									25.20%	24.30%	26.60%
Product Concentration Risk | Fuel Product | Diesel
Major product category sales
Sales									$ 877.9	$ 808.4	$ 894.8
Concentration Risk, Percentage									23.40%	23.30%	22.80%
Product Concentration Risk | Fuel Product | Jet fuel
Major product category sales
Sales									$ 135	$ 117.5	$ 149.6
Concentration Risk, Percentage									3.60%	3.40%	3.80%
Product Concentration Risk | Fuel Product | Asphalt, heavy fuel oils and other
Major product category sales
Sales									$ 502	$ 451.8	$ 471
Concentration Risk, Percentage									13.30%	13.00%	12.00%

Segments and Related Informa124

Segments and Related Information (Details 2) - supplier	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Disclosure on Geographic Areas, Description of Revenue from External Customers	0	0	0
Segment Reporting, Disclosure of Major Customers	0	0	0
number of major suppliers	2	2	2
Supplier Concentration Risk [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	65.70%	64.50%	52.20%

Quarterly Financial Data (Un125

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Quarterly Financial [Line Items]
Sales	$ 883.8	$ 1,026.5	$ 967	$ 886.5	$ 909.8	$ 932.3	$ 951.6	$ 680.6	$ 3,763.8		$ 3,474.3		$ 3,930.3
Gross Profit	97.3	127.7	143.7	129.5	72.5	103	130.5	80.3	498.2	[1]	386.3	[1]	536.4
Net loss from continuing operations	(18.7)	(26.1)	12	1.5	(71.5)	(33.1)	(135.3)	(56.9)	(31.3)		(296.8)		(85.4)
Net income (loss) from discontinued operations	(64.9)	2.5	(2.4)	(7.7)	(8.1)	(0.3)	(12.6)	(10.8)	(72.5)		(31.8)		(54)
Net income (loss)	(83.6)	(23.6)	9.6	(6.2)	(79.6)	(33.4)	(147.9)	(67.7)	(103.8)		(328.6)		(139.4)
Net income (loss) available to limited partners	$ (81.9)	$ (23.1)	$ 9.2	$ (6.1)	$ (78)	$ (32.7)	$ (145)	$ (66.3)	$ (101.7)		$ (322)	[1]	$ (153.4)
Limited partners' interest basic net income (loss) per unit from continuing operations	$ (0.24)	$ (0.33)	$ 0.15	$ 0.02	$ (0.91)	$ (0.42)	$ (1.73)	$ (0.73)	$ (0.40)		$ (3.77)		$ (1.34)
Limited partners' interest basic net income (loss) per unit from discontinued operations	(0.82)	0.03	(0.03)	(0.10)	(0.10)	0	(0.16)	(0.14)	(0.91)		(0.41)		(0.71)
Limited partners’ interest basic net income (loss) per unit	(1.06)	(0.30)	0.12	(0.08)	(1.01)	(0.42)	(1.89)	(0.87)	(1.31)		(4.18)		(2.05)
Income (Loss) from Continuing Operations, Net of Tax, Per Outstanding Limited Partnership Unit, Diluted	(0.24)	(0.33)	0.15	0.02	(0.91)	(0.42)	(1.73)	(0.73)	(0.40)		(3.77)		(1.34)
Income (Loss) from Discontinued Operations, Net of Tax, Per Outstanding Limited Partnership Unit, Diluted	(0.82)	0.03	(0.03)	(0.10)	(0.10)	0	(0.16)	(0.14)	(0.91)		(0.41)		(0.71)
Limited partners' interest diluted net income (loss) per unit	$ (1.06)	$ (0.30)	$ 0.12	$ (0.08)	$ (1.01)	$ (0.42)	$ (1.89)	$ (0.87)	$ (1.31)		$ (4.18)		$ (2.05)
Weighted average limited partner units outstanding — diluted	77,784,534	77,931,605	77,714,112	78,259,909	77,351,593	77,331,347	76,761,504	76,449,841
Weighted average limited partner units outstanding — basic	77,784,534	77,632,784	77,554,815	77,412,634	77,351,593	77,331,347	76,761,504	76,449,841
[1]	The sum of the four quarters may not equal the total year due to rounding.

Subsequent Events (Details Text

Subsequent Events (Details Textual) - USD ($) $ in Millions	Mar. 08, 2018	Feb. 23, 2018	Apr. 20, 2016	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsequent Event [Member]
Subsequent Event [Line Items]
Payments to Acquire Businesses, Gross				$ 7
Long-term Debt, Increase (Decrease) to Fair Value				$ 34
clmt_FILO [Domain] | Subsequent Event [Member]
Subsequent Event [Line Items]
Senior secured revolving credit facility		$ 25
11.50% Notes
Subsequent Event [Line Items]
Maturity date			Jan. 15, 2021
11.50% Notes | Subsequent Event [Member]
Subsequent Event [Line Items]
Debt Instrument, Redemption Period, Start Date	Mar. 8, 2018
Debt Instrument, Redemption Period, End Date	Apr. 9, 2018
Debt Instrument, Redemption Price, Percentage	100.00%
Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Senior secured revolving credit facility					$ 900	$ 900
Incremental Uncommitted Expansion Feature					$ 500
Maturity date					Jul. 14, 2019
Revolving Credit Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Senior secured revolving credit facility		600
Incremental Uncommitted Expansion Feature		500
Incremental Uncommitted Foreign Expansion Feature		$ 50
Maturity date		Feb. 18, 2023
Maximum | Revolving Credit Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Letter of Credit Sublimit		$ 300
Maximum | Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Senior secured revolving credit facility					$ 900	900
Letter of Credit Sublimit					$ 600	$ 600
Letter of Credit Sublimit Percentage					90.00%	90.00%
Maximum | Revolving Credit Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Letter of Credit Sublimit Percentage		90.00%