Calumet Specialty Products Partners (CLMT) 10-Q 28 Dec 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Dec. 28, 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-Q
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		76,788,801

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 26.5	$ 4.2
Accounts receivable, net:
Trade	338.8	216.4
Other	2.9	22.3
Total accounts receivable	341.7	238.7
Inventories	324.4	386.2
Derivative assets	0.3	0.8
Prepaid expenses and other current assets	15.8	11
Current assets held for sale	125	0
Total current assets	833.7	640.9
Property, plant and equipment, net	1,410.4	1,678
Investment in unconsolidated affiliates	9.9	10.3
Goodwill	172	177.2
Other intangible assets, net	153.9	178.5
Other noncurrent assets, net	18.4	40.3
Noncurrent assets held for sale	215.1	0
Total assets	2,813.4	2,725.2
Current liabilities:
Accounts payable	261.3	295.5
Accrued interest payable	55.4	52.5
Accrued salaries, wages and benefits	32.3	11.5
Other taxes payable	24.1	20.8
Obligations under inventory financing agreements	92.8	0
Other current liabilities	59.7	99.6
Current portion of long-term debt	4.3	3.5
Derivative liabilities	8.3	14.8
Current liabilities held for sale	74.5	0
Total current liabilities	612.7	498.2
Deferred income taxes	1	2.3
Pension and postretirement benefit obligations	3.6	11.3
Other long-term liabilities	0.8	1
Long-term debt, less current portion	1,986.6	1,993.7
Noncurrent liabilities held for sale	7.1	0
Total liabilities	2,611.8	2,506.5
Partners’ capital:
Limited partners’ interest 76,729,706 units and 76,392,258 units, issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	194.3	211.2
General partner’s interest	15.5	15.8
Accumulated other comprehensive loss	(8.2)	(8.3)
Total partners’ capital	201.6	218.7
Total liabilities and partners’ capital	2,813.4	2,725.2
Limited Partner [Member]
Partners’ capital:
Total partners’ capital	194.3	211.2
General Partner [Member]
Partners’ capital:
Total partners’ capital	15.5	$ 15.8
Superior Refinery [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Accounts receivable, net:
Current assets held for sale	125
Noncurrent assets held for sale	215.1
Current liabilities:
Current liabilities held for sale	74.5
Noncurrent liabilities held for sale	$ 7.1

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - Limited Partner [Member] - shares	Sep. 30, 2017	Dec. 31, 2016
Limited partners’ interest units issued (in shares)	76,729,706	76,392,258
Limited partners’ interest units outstanding (in shares)	76,729,706	76,392,258

Unaudited Condensed Consolidate

Unaudited Condensed Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Sales		$ 1,097.4	$ 966.6	$ 3,065.7	$ 2,652.5
Cost of sales		945.9	856.3	2,614.3	2,324.7
Gross profit		151.5	110.3	451.4	327.8
Operating costs and expenses:
Selling		28	26.2	83.7	82.9
General and administrative		41.6	28.2	107	80.6
Transportation		36.1	42.2	117.8	126.4
Taxes other than income taxes		7	4.8	17.4	14.7
Asset Impairment		0	0	0.4	33.4
Other expense		3.8		6.8	1.3
Other Income			(1)
Operating income (loss)		35	9.9	118.3	(11.5)
Other income (expense):
Interest expense		(47.4)	(44.6)	(135.8)	(117.7)
Gain (loss) on derivative instruments		(12)	(6.7)	(5)	3.4
Loss from unconsolidated affiliates		(0.2)	(0.3)	(0.4)	(18.5)
Loss from sale of unconsolidated affiliates		0	0	0	(113.4)
Other		0.9	0.7	1.6	1.6
Total other expense		(58.7)	(50.9)	(139.6)	(244.6)
Net loss before income taxes		(23.7)	(41)	(21.3)	(256.1)
Income tax benefit		(0.1)	(7.6)	(1.1)	(7.1)
Net loss		(23.6)	(33.4)	(20.2)	(249)
Less:
General partner’s interest in net loss		(0.5)	(0.7)	(0.4)	(5)
Net loss available to limited partners		$ (23.1)	$ (32.7)	$ (19.8)	$ (244)
Weighted average limited partner units outstanding:
Basic (in shares)		77,632,784	77,331,347	77,537,531	76,767,975
Diluted (in shares)	[1]	77,632,784	77,331,347	77,537,531	76,767,975
Limited partners' interest basic net loss per unit		$ (0.30)	$ (0.42)	$ (0.25)	$ (3.18)
Limited partners' interest diluted net loss per unit		(0.30)	(0.42)	(0.25)	(3.18)
Cash distributions declared per limited partner unit		$ 0	$ 0	$ 0	$ 0.685
[1]	Total diluted weighted average limited partner units outstanding excludes 0.3 million for the three and nine months ended September 30, 2017 as compared to the 0.1 million and 0.2 million, respectively, of dilutive phantom units for the three and nine months ended September 30, 2016.

Unaudited Condensed Consolidat5

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net loss	$ (23.6)	$ (33.4)	$ (20.2)	$ (249)
Cash flow hedges:
Cash flow hedge gain reclassified to net loss	0	(4.8)	0	(9.2)
Defined Benefit Pension and retiree health benefit plans	0.1	0	0.1	0.1
Total other comprehensive income (loss)	0.1	(4.8)	0.1	(9.1)
Comprehensive loss attributable to partners’ capital	$ (23.5)	$ (38.2)	$ (20.1)	$ (258.1)

Unaudited Condensed Consolidat6

Unaudited Condensed Consolidated Statements of Partners' Capital - 9 months ended Sep. 30, 2017 - USD ($) $ in Millions	Total	General Partner [Member]	Limited Partner [Member]	Accumulated Other Comprehensive Loss [member]
Beginning Balance at Dec. 31, 2016	$ 218.7	$ 15.8	$ 211.2	$ (8.3)
Increase (Decrease) in Partners' Capital [Roll Forward]
Other comprehensive income	0.1	0	0	0.1
Net loss	(20.2)	(0.4)	(19.8)	0
Amortization of phantom units	3.3	0	3.3	0
Settlement of tax withholdings on equity-based incentive compensation	(0.4)	0	(0.4)	0
Contributions from Calumet GP, LLC	0.1	0.1	0	0
Ending Balance at Sep. 30, 2017	$ 201.6	$ 15.5	$ 194.3	$ (8.2)

Unaudited Condensed Consolidat7

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating activities
Net loss	$ (20.2)	$ (249)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization	130.6	127.1
Amortization of turnaround costs	20.4	25.3
Non-cash interest expense	7.6	7.2
Provision for doubtful accounts	0.2	0.4
Unrealized gain on derivative instruments	(2.2)	(23.5)
Asset Impairment	0.4	33.4
(Gain) loss on disposal of fixed assets	3.9	(0.5)
Non-cash equity based compensation	8.4	3.9
Deferred Income Tax Benefit	(0.2)	(0.4)
Lower of cost or market inventory adjustment	(19.1)	(33.3)
Loss from unconsolidated affiliates	0.4	18.5
Loss from sale of unconsolidated affiliates	0	113.4
Other non-cash activities	5	3.7
Changes in assets and liabilities:
Accounts receivable	(155.1)	(69.8)
Inventories	8	16.3
Prepaid expenses and other current assets	(4.8)	(6.6)
Derivative activity	(0.3)	(18.1)
Turnaround costs	(11.3)	(8.7)
Other assets	(0.4)	(0.3)
Accounts payable	37.7	11.6
Accrued interest payable	2.9	24.1
Accrued salaries, wages and benefits	17.6	(17)
Other taxes payable	7.4	5.4
Other liabilities	(39.7)	19.9
Pension and postretirement benefit obligations	(0.5)	(1.8)
Net cash used in operating activities	(3.3)	(18.8)
Investing activities
Additions to property, plant and equipment	(45.6)	(117.3)
Investment in unconsolidated affiliates	0	(41)
Proceeds from Sale of unconsolidated affiliates	0	29
Proceeds from Sale of Property, Plant, and Equipment	0	1.9
Net cash used in investing activities	(45.6)	(127.4)
Financing activities
Proceeds from borrowings — revolving credit facility	781.2	823.2
Repayments of borrowings — revolving credit facility	(791.3)	(934.1)
Proceeds from borrowings - Senior notes	0	393.1
Repayments of borrowings — related party note	0	(55.4)
Payments on capital lease obligations	(6.7)	(6.2)
Proceeds from inventory financing agreements	91.6	0
Other financing activities	(1.1)	6.9
Debt Issuance Costs	(2.2)	(10.1)
Contributions from Calumet GP, LLC	0.1	0.2
Taxes paid for phantom unit grants	(0.4)	(1.8)
Distributions to partners	0	(57.4)
Net cash provided by financing activities	71.2	158.4
Net increase in cash and cash equivalents	22.3	12.2
Cash and cash equivalents at beginning of period	4.2	5.6
Cash and cash equivalents at end of period	26.5	17.8
Supplemental disclosure of non-cash financing and investing activities
Non-cash property, plant and equipment additions	8.9	16.4
Non-cash Capital Lease	$ 0	$ 2.3

Description of the Business

Description of the Business	9 Months Ended
	Sep. 30, 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 September 30, 2017 , the Company had 76,729,706 limited partner common units and 1,565,912 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses. The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums and waxes and fuel and fuel related products including gasoline, diesel, jet fuel, asphalt and heavy fuel oils, in addition to oilfield services and products. The Company owns and leases additional facilities, primarily related to production and distribution of specialty, fuel and oilfield services products, throughout the United States (“U.S.”). The unaudited condensed consolidated financial statements of the Company as of September 30, 2017 and for the three and nine months ended September 30, 2017 and 2016 , included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires 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 unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2016 Annual Report.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Reclassifications Certain amounts in the prior years’ unaudited condensed consolidated financial statements have been reclassified to conform to the current year presentation. Other Current Liabilities Other current liabilities consisted of the following as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 RINs Obligation $ 41.0 $ 79.3 Other 18.7 20.3 Total $ 59.7 $ 99.6 The Company’s 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 unaudited condensed consolidated statements of cash flows. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN 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 condensed 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 unaudited condensed consolidated statements of operations. The assets and liabilities associated with our RINs Obligation are considered recurring fair value measurements. See Note 6 for further information on the Company’s RINs Obligation. 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 unaudited condensed consolidated financial statements. In May 2017, the FASB issued 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 is not expected to have an impact on the Company’s unaudited condensed consolidated financial statements. In March 2017, the FASB issued ASU No. 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 is not expected to have an impact on the Company’s unaudited condensed 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. The amendments in this standard 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 this standard on its unaudited condensed 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 unaudited condensed consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in Accounting Standard Codification Topic 605, Revenue Recognition . ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires enhanced disclosures. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the original effective date by one year to annual and interim periods beginning after December 15, 2017, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. In March, April, May and December 2016, the FASB clarified the implementation guidance on principal versus agent considerations, identifying performance obligations, licensing, collectability, presentation of sales taxes, non-cash consideration, transition, the scope of Topic 606, impairment testing, policy elections over determining the provision for losses on certain types of contracts, the accrual of advertising costs and disclosure requirements. All amendments are effective with the same date as ASU 2014-09. The Company is currently evaluating the impact of these standards on its unaudited condensed consolidated financial statements. The Company is required to adopt ASU 2014-09 as of January 1, 2018, and expects to use the modified retrospective approach. The Company has an implementation work team evaluating contracts from the various revenue streams across all of its business segments to evaluate and implement changes to business processes, systems and controls. Based on the evaluation performed to date, 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. The Company does not believe that these elements would result in a material change to how revenue would be recognized for these agreements upon the adoption of ASU 2014-09 or have a material effect on the Company’s unaudited condensed consolidated financial statements. As a result of adopting the new standard, there will be changes to our 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. The Company continues to analyze the full impact on its operating segments of the adoption of ASU 2014-09, which may result in differences between current revenue recognition practices and those required by ASU 2014-09 that may be material. As part of the Company’s evaluation, it has segregated its revenue streams into categories which will serve as the basis for the continuing accounting analysis on, and documentation of revenues, as it relates to the impact of ASU 2014-09. In addition, the Company continues to actively monitor outstanding issues currently being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the FASB’s Transition Resource Group, since conclusions reached by these groups may impact its application of ASU 2014-09. Correction of Immaterial Errors During the quarter ended September 30, 2016, the Company identified and corrected errors in the accounting for the lower of cost or market of inventory and income taxes that related to the year ended December 31, 2015. These errors primarily related to lower of cost or market (“LCM”) adjustments at its Branded and Packaging operating segment and an adjustment for a tax benefit associated with its decision to liquidate a wholly-owned C corporation as of December 31, 2015, and convert it to an entity which will not be subject to tax. The impact of correcting these items in the third quarter of 2016 increased cost of sales by $6.5 million , increased income tax benefit by $7.8 million and decreased net loss by $1.3 million . The Company concluded that the corrections to the financial statements were immaterial to its financial results for the year ended December 31, 2016 and 2015. 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 by 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. In light of declines in certain markets the Company serves, an evaluation of existing and future capacity, and as part of its annual planning and budgeting process which is currently in progress, the Company will perform an assessment of its major long-lived assets which may result in long-lived asset impairment. The Company will complete its asset recoverability assessment and analyze the conclusions of that assessment in connection with the annual planning and budgeting process. Until these activities are complete, it is not practicable to reasonably estimate the existence or range of potential future impairments related to the Company’s long-lived assets.

Inventories

Inventories	9 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
Inventories	Inventories The cost of inventory is recorded using the last-in, first-out (“LIFO”) method. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. The replacement cost of these inventories, based on current market values, would have been $20.1 million and $14.4 million lower as of September 30, 2017 and December 31, 2016 , respectively. 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 7 — “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. The Company records the inventory owned by Macquarie as inventory with a corresponding obligation on the Company’s condensed consolidated balance sheets because Macquarie maintains the risk of loss until the refined products are sold to third parties and 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): September 30, 2017 December 31, 2016 Titled Inventory Supply and Offtake Agreements (1) Total Titled Inventory Supply and Offtake Agreements (1) Total Raw materials $ 31.1 $ 14.4 $ 45.5 $ 57.4 $ — $ 57.4 Work in process 35.1 24.5 59.6 74.2 — 74.2 Finished goods 174.9 44.4 219.3 254.6 — 254.6 $ 241.1 $ 83.3 $ 324.4 $ 386.2 $ — $ 386.2 (1) Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Refer to Note 7 for further information. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. 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 three months ended September 30, 2017 , the Company recorded a decrease of $11.1 million in cost of sales in the unaudited condensed consolidated statements of operations due to the LCM valuation. During the three months ended September 30, 2016 , the Company recorded an increase of $11.1 million in the unaudited condensed consolidated statements of operations due to the LCM valuation. During the nine months ended September 30, 2017 and 2016 , the Company recorded decreases of $19.1 million and $33.3 million , respectively, in cost of sales in the unaudited condensed consolidated statements of operations due to the LCM valuation.

Divestiture Divestiture

Divestiture Divestiture	9 Months Ended
	Sep. 30, 2017
Superior Divestiture [Abstract]
Divestiture	Superior Divestiture On August 11, 2017, Calumet Lubricants Co., Limited Partnership, an Indiana limited partnership (“Calumet Lubricants”) and a wholly-owned subsidiary of the Company, entered into a membership interest purchase agreement (the “Purchase Agreement”) with Husky Superior Refining Holding Corp., a Delaware corporation (“Husky”), pursuant to which, at the closing, Husky will acquire from Calumet Lubricants (the “Superior Transaction”) all of the issued and outstanding membership interests in Calumet Superior, LLC, a Delaware limited liability company (“Superior”), which owns a refinery located in Superior, Wisconsin (the “Superior Refinery”) and associated inventories, the Superior Refinery’s wholesale marketing business and related assets, including certain owned or leased product terminals, and certain crude gathering assets and line space in North Dakota. Under the Purchase Agreement, Husky has agreed to pay $435.0 million in cash plus an additional payment for net working capital, inventories, and reimbursement of certain capital spending, as determined at closing. The Superior Refinery is included in the Company’s fuel products segment. The Company closed the Superior Transaction on November 8, 2017. Please see Note 15 - “Subsequent Events” for additional information. The Superior assets have been reclassified as assets held for sale within the Company’s condensed consolidated balance sheet at September 30, 2017. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. The Company determined that the carrying value does not exceed the fair value less estimated costs to sell. The following table details the major classes of assets and liabilities of Superior (in millions): September 30, 2017 ASSETS HELD FOR SALE Current assets: Accounts receivable $ 52.1 Inventories 72.9 Total current assets held for sale 125.0 Property, plant and equipment, net 198.2 Goodwill 5.2 Other noncurrent assets, net 11.7 Total noncurrent assets held for sale 215.1 Total assets held for sale $ 340.1 LIABILITIES HELD FOR SALE Current liabilities: Accounts payable $ 66.9 Accrued salaries, wages and benefits 1.9 Other taxes payable 3.8 Other current liabilities 1.9 Total current liabilities held for sale 74.5 Pension and postretirement benefit obligations 7.1 Total noncurrent liabilities held for sale 7.1 Total liabilities held for sale $ 81.6 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 of the asset held for sale for the periods presented (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Net income before income taxes $ 17.0 $ 19.5 $ 82.5 $ 54.5

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	Investment In Unconsolidated Affiliates The following table summarizes the Company’s investments in unconsolidated affiliates as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Investment Percent Ownership Investment Percent Ownership Pacific New Investment Limited $ 9.5 23.8 % $ 9.6 23.8 % Other 0.4 0.7 Total $ 9.9 $ 10.3 Pacific New Investment Limited and Shandong Hi-Speed Hainan Development Co., Ltd. On August 5, 2015, the Company and The 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 September 30, 2017 and 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 6.0% in Hi-Speed. PACNIL wishes to exit its investment in Hi-Speed. The Company and PACNIL believe they will fully recover their investment in the Hi-Speed joint venture. The Company accounts for its ownership in PACNIL under the equity method of accounting. As of September 30, 2017 and December 31, 2016 , the Company had an investment of $9.5 million and $9.6 million , respectively, in PACNIL, primarily related to the purchase of equity in the Hi-Speed joint venture. 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 from the sale of the unconsolidated affiliate of $113.9 million during the nine months ended September 30, 2016.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various 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 federal Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company. Environmental The Company conducts crude oil and specialty hydrocarbon refining, blending and terminal operations in addition to providing oilfield services and products, 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 September 30, 2017 , of which $14.6 million was capitalized into the cost of the Company’s recently completed refinery expansion project and $4.1 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. Arbitration is scheduled for early 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. Superior Refinery In connection with the acquisition of the Superior refinery, the Company became a party to an existing Refinery Initiative Consent Decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to its Superior refinery. Under the Superior Consent Decree, the Company must complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the refinery to the EPA and the WDNR. Failure to perform these required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be material. The Company is currently assessing certain past actions at the refinery for compliance with the terms of the Superior Consent Decree, which actions may be subject to stipulated penalties under the Superior Consent Decree but, in any event, the Company does not currently believe that the imposition of such penalties for those actions, should they be imposed, would be material. In addition, the Company is pursuing certain additional environmental and safety-related projects at the Superior refinery. Completion of these additional projects will result in the Company incurring additional costs, which could be substantial. For the three and nine months ended September 30, 2017 , the Company incurred costs of $0.2 million and $0.3 million , respectively related to installing process equipment at the Superior refinery pursuant to EPA fuel content regulations as compared to less than $0.1 million in the respective 2016 comparable periods. In June 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery, which included a proposed penalty amount of $0.1 million . This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and is in settlement discussions with the EPA to resolve this issue. The Company has not yet received formal action from the EPA. The Company does not believe that the resolution of these allegations will have a material adverse effect on its financial position or results of operations. The Company is contractually indemnified by Murphy Oil Corporation (“Murphy Oil”) under an asset purchase agreement between the Company and Murphy Oil for specified environmental liabilities arising from the operation of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the acquisition of Superior and (iii) certain liabilities for certain third-party actions, suits or proceedings alleging exposure, prior to the acquisition of Superior, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or otherwise discharged by Murphy Oil. The Company believes contractual indemnity by Murphy Oil for such specified environmental liabilities is unlimited in duration and not subject to any monetary deductibles or maximums. The amount of any damages payable by Murphy Oil pursuant to the contractual indemnities under the asset purchase agreement are net of any amount recoverable under an environmental insurance policy that the Company obtained in connection with the acquisition of the Superior refinery, which named the Company and Murphy Oil as insureds and covers environmental conditions existing at the Superior refinery prior to the Company’s acquisition of the Superior refinery. For further information related to the Superior Refinery, refer to Note 4 - “ Superior Divestiture ”. Shreveport, Cotton Valley and Princeton Refineries On December 23, 2010 , the Company entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012 . The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act, 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, Princeton and Cotton Valley refineries on an agreed-upon schedule. The Company incurred approximately $0.1 million of such capital expenditures during the three months ended September 30, 2017 compared to $0.4 million incurred during the three months ended September 30, 2016 . During the nine months ended September 30, 2017 and 2016 , the Company incurred approximately $0.6 million and $0.8 million , respectively, of such capital expenditures. 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 condensed consolidated balance sheets. Bel-Ray Facility Bel-Ray executed an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection, effective January 4, 1994, which required investigation and remediation of contamination at or emanating from the Bel-Ray facility. In 2000, Bel-Ray entered into a fixed price remediation contract with Weston Solutions (“Weston”), a large remediation contractor, whereby Weston agreed to be fully liable for the remediation of the soil and groundwater issues at the facility, including an offsite groundwater plume pursuant to the ACO (“Weston Agreement”). The Weston Agreement set up a trust fund to reimburse Weston, administered by Bel-Ray’s environmental counsel. As of September 30, 2017 , the trust fund contained approximately $0.6 million . In addition, Weston has remediation cost containment insurance, should Weston be unable to complete the work required under the Weston Agreement. In connection with the acquisition of Bel-Ray, the Company became a party to the Weston Agreement. Weston has been addressing the environmental issues at the Bel-Ray facility over time and the next phase will address the groundwater issues, which extend offsite. Renewable Identification Numbers Obligation On February 10, 2017 and on May 4, 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. As of September 30, 2017 and December 31, 2016 , the Company had a RINs Obligation of $41.0 million and $79.3 million , respectively. RINs expense for the three months ended September 30, 2017 was $12.3 million and the RINs gain for the nine months ended September 30, 2017 was $51.8 million , compared to a RINs expense for the respective periods in 2016 of $10.1 million and $35.1 million . Occupational Health and Safety The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to 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. 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 unaudited condensed 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. Labor Matters The Company has employees covered by various collective bargaining agreements. The Company’s Princeton facility collective bargaining agreement was ratified on October 30, 2017 and will expire on October 31, 2020. 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 September 30, 2017 and December 31, 2016 , the Company had outstanding standby letters of credit of $100.3 million and $82.1 million , respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 8 for additional information regarding the Company’s revolving credit facility. At September 30, 2017 and December 31, 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 September 30, 2017 and December 31, 2016 ) with the consent of the Agent (as defined in the revolving credit facility agreement).

Inventory Financing Agreement

Inventory Financing Agreement	9 Months Ended
	Sep. 30, 2017
Other Commitments [Abstract]
Inventory Financing Agreement	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 30, 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, as of September 30, 2017 , 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 condensed 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 condensed 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 condensed consolidated balance sheets. The Company has determined that the redemption feature on the initially recognized liabilities related to the Supply and Offtake Agreements and the contingent interest feature are embedded derivatives 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 unaudited condensed consolidated statements of operations. For more information on the valuation of the associated derivatives, see Note 9 - “ Derivatives ” and Note 10 - “ Fair Value Measurements .” The embedded derivatives will be recorded in obligations under inventory financing agreements on the condensed 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 unaudited condensed consolidated statements of cash flows. For the three and nine months ended September 30, 2017 , the Company incurred $3.6 million and $4.0 million , respectively of financing costs related to the Supply and Offtake Agreements, which is included in interest expense in the Company’s unaudited condensed consolidated statements of operations. The Company has provided collateral of $5.0 million related to the initial purchase of 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 ( 90.0% of the collateral inventory) with the amount due always paid prior to the 20 th of the month. The deferred amounts under the deferred payment arrangement will bear interest at a rate equal to LIBOR plus 3.25% or 2.65% per annum for Shreveport and Great Falls, respectively. Amounts outstanding under the Deferred Payment Arrangement are included in obligations under inventory financing agreements in the Company’s condensed consolidated balance sheets. Changes in the amount outstanding under the Deferred Payment Arrangement are included within cash flows from financing activities on the unaudited condensed consolidated statements of cash flows. As of September 30, 2017 , the capacity of the Deferred Payment Arrangement was $7.5 million and the Company had $7.3 million deferred payments outstanding.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consisted of the following (in millions): September 30, 2017 December 31, 2016 Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rate of 7.4% and 4.8% for the nine months ended September 30, 2017 and year ended December 31, 2016, respectively. $ 0.1 $ 10.2 Borrowings under 2021 Secured Notes, interest at a fixed rate of 11.5%, interest payments semiannually, borrowings due January 2021, effective interest rate of 12.3% and 12.2% for the nine months ended September 30, 2017 and year ended December 31, 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 the nine months ended September 30, 2017 and year ended December 31, 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 the nine months ended September 30, 2017 and year ended December 31, 2016. (1) 352.2 352.5 Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the nine months ended September 30, 2017 and year ended December 31, 2016. 325.0 325.0 Other 6.9 8.0 Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034. 44.7 46.5 Less unamortized debt issuance costs (2) (27.7 ) (33.2 ) Less unamortized discounts (10.3 ) (11.8 ) Total long-term debt $ 1,990.9 $ 1,997.2 Less current portion of long-term debt 4.3 3.5 $ 1,986.6 $ 1,993.7 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.2 million and $2.5 million as of September 30, 2017 and December 31, 2016 , respectively (refer to Note 9 for additional information on the interest rate swap designated as a fair value hedge). (2) Deferred debt issuance costs are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $19.8 million and $14.5 million at September 30, 2017 and December 31, 2016 , respectively. 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. 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. 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 acquisition of Bel-Ray 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. 2021 Secured Notes, 2021 Notes, 2022 Notes and 2023 Notes In accordance with SEC Rule 3-10 of Regulation S-X, unaudited 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 September 30, 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 to 1.0. As of September 30, 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. The revolving credit facility is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in July 2019 and currently bears interest at a rate equal to 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 September 30, 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. 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 facility 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 7 . 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 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 . As of September 30, 2017 , the Company was in compliance with all covenants under the revolving credit facility, subject to the statements Note 15 - “Subsequent Events”. Maturities of Long-Term Debt As of September 30, 2017 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2017 $ 0.8 2018 4.2 2019 2.9 2020 2.4 2021 1,303.3 Thereafter 713.1 Total $ 2,026.7

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 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. 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 maintain 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 and the contingent interest feature are embedded derivatives 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 unaudited condensed consolidated statements of operations. The Company recognizes all derivative instruments at their fair values (see Note 10 ) as either current assets or current liabilities in the condensed consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Balance Sheet Location Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps Derivative assets $ — $ (0.3 ) $ (0.3 ) $ 0.1 $ (0.1 ) $ — Fuel products segment: Crude oil swaps Derivative assets 1.9 (1.4 ) 0.5 10.3 (7.4 ) 2.9 Crude oil basis swaps Derivative assets 1.0 (0.5 ) 0.5 — (2.1 ) (2.1 ) Crude oil percentage basis swaps Derivative assets 0.7 — 0.7 0.1 (0.1 ) — Gasoline crack spread swaps Derivative assets 0.2 (0.5 ) (0.3 ) — — — Diesel crack spread swap Derivative assets — (0.8 ) (0.8 ) — — — Total derivative instruments $ 3.8 $ (3.5 ) $ 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 condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Balance Sheet Location Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps Derivative liabilities $ (0.7 ) $ 0.3 $ (0.4 ) $ (1.2 ) $ 0.1 $ (1.1 ) Fuel products segment: Inventory financing obligation Obligations under inventory financing agreements (3.8 ) — (3.8 ) — — — Crude oil swaps Derivative liabilities (2.0 ) 1.4 (0.6 ) (8.2 ) 7.4 (0.8 ) Crude oil basis swaps Derivative liabilities — 0.5 0.5 (7.1 ) 2.1 (5.0 ) Crude oil percentage basis swaps Derivative liabilities — — — (0.6 ) 0.1 (0.5 ) Gasoline swaps Derivative liabilities (0.3 ) — (0.3 ) — — — Gasoline crack spread swaps Derivative liabilities (2.6 ) 0.5 (2.1 ) (3.5 ) — (3.5 ) Diesel swaps Derivative liabilities (0.4 ) — (0.4 ) — — — Diesel crack spread swaps Derivative liabilities (5.8 ) 0.8 (5.0 ) (1.4 ) — (1.4 ) 2/1/1 crack spread swaps Derivative liabilities — — — (2.5 ) — (2.5 ) Total derivative instruments $ (15.6 ) $ 3.5 $ (12.1 ) $ (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 September 30, 2017 , the Company had two counterparties in which the derivatives held were net assets, totaling $0.3 million . As of December 31, 2016 , the Company had one counterparty in which the derivatives held were net assets, totaling $0.8 million . To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa1 and BBB+ by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark-to-market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed-upon thresholds in its master derivative contracts with these counterparties. No such collateral was held by the Company as of September 30, 2017 or December 31, 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 condensed 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 September 30, 2017 and December 31, 2016 , the Company had provided no collateral to its counterparties. 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 commodity derivative activities is classified primarily as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows. The cash flow impact of the Company’s embedded derivatives included in the Supply and Offtake Agreements is classified as a change in derivative activity in the investing activities section in the unaudited condensed 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 diesel swaps as cash flow hedges. As of September 30, 2017 , the Company has no derivative instruments designated as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases are recorded to sales and cost of sales, respectively, in the unaudited condensed consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. The Company assesses, both at inception of the cash flow hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Periodically, the Company may enter into crude oil and fuel product basis swaps to more effectively hedge its crude oil purchases, crude oil sales and fuel products sales. These derivatives can be combined with a swap contract in order to create a more effective cash flow hedge. To the extent a derivative instrument designated as a cash flow hedge is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations. Ineffectiveness is inherent in the hedging of crude oil and fuel products. Due to the volatility in the markets for crude oil and fuel products, the Company is unable to predict the amount of ineffectiveness each period, determined on a derivative by derivative basis or in the aggregate for a specific commodity and has the potential for the future loss of cash flow hedge accounting. Ineffectiveness has resulted, and the loss of cash flow hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize cash flows. Cash flow hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When cash flow hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously deferred in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive loss and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended September 30, 2017 and 2016 , related to its derivative instruments that were designated as cash flow hedges (in millions): Type of Derivative Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion) Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion) Three Months Ended Location of Gain (Loss) Three Months Ended Location of Gain (Loss) Three Months Ended September 30, September 30, September 30, 2017 2016 2017 2016 2017 2016 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ — $ 2.6 Gain (loss) on derivative instruments $ — $ — Fuel products segment: Crude oil swaps — (2.3 ) Cost of sales — (12.3 ) Gain (loss) on derivative instruments — — Diesel swaps — 2.3 Sales — 14.5 Gain (loss) on derivative instruments — — Total $ — $ — $ — $ 4.8 $ — $ — The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive loss and unaudited condensed consolidated statements of partners’ capital as of and for the nine months ended September 30, 2017 and 2016 , related to its derivative instruments that were designated as cash flow hedges (in millions): Type of Derivative Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion) Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion) Nine Months Ended Location of Gain (Loss) Nine Months Ended Location of Gain (Loss) Nine Months Ended September 30, September 30, September 30, 2017 2016 2017 2016 2017 2016 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ — $ 1.4 Gain (loss) on derivative instruments $ — $ — Fuel products segment: Crude oil swaps — (8.1 ) Cost of sales — (37.8 ) Gain (loss) on derivative instruments — — Diesel swaps — 8.1 Sales — 45.6 Gain (loss) on derivative instruments — — Total $ — $ — $ — $ 9.2 $ — $ — As of September 30, 2017 and December 31, 2016 , there was no effective portion of cash flow hedges classified in accumulated other comprehensive loss. Derivative Instruments Designated as Fair Value Hedges For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the unaudited condensed consolidated statements of operations. No hedge ineffectiveness is recognized if the interest rate swap qualifies for the “shortcut” method and, as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items. Fair value hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective fair value hedge, the derivative instrument is still subject to mark-to-market method of accounting, however the Company will cease to adjust the hedged asset or liability for changes in fair value. In 2014, the Company entered into an interest rate swap agreement which converted a portion of the Company’s fixed rate debt to a floating rate. This agreement involved the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount. Also, in connection with the interest rate swap agreement, the Company entered into an option that permits the counterparty to cancel the interest rate swap for a specified premium. The Company designated this interest rate swap and option as a fair value hedge. On January 13, 2015, the Company terminated its interest rate swap, which was designated as a fair value hedge, related to a notional amount of $200.0 million of 2022 Notes. In settlement of this swap, the Company recognized a net gain of approximately $3.3 million . The Company recorded the following losses in its unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 , related to its derivative instrument designated as a fair value hedge (in millions): Location of Loss of Derivative Amount of Loss Recognized Hedged Item Location of Gain on Hedged Item Amount of Gain Recognized Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 Swaps not allocated to a specific segment: Interest rate swap Interest expense $ 0.1 $ 0.1 $ 0.3 $ 0.3 2022 Notes Interest income $ — $ — $ — $ — Total $ 0.1 $ 0.1 $ 0.3 $ 0.3 $ — $ — $ — $ — 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 gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is realized in the unaudited condensed consolidated statements of operations in gain (loss) on derivative instruments. Additionally, the Company has entered into natural gas swaps, crude oil swaps, crack spread swaps, diesel swaps and gasoline swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and natural gas purchases and gasoline and diesel sales at the Company’s refineries. The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended September 30, 2017 and 2016 , related to its derivative instruments not designated as hedges (in millions): Type of Derivative Amount of Realized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 Specialty products segment: Natural gas swaps $ (1.2 ) $ (1.8 ) $ 1.1 $ 0.9 Natural gas collars — (0.3 ) — 0.3 Fuel products segment: Inventory financing obligation — — (2.9 ) — Crude oil swaps (1.0 ) 2.1 2.6 (5.4 ) Crude oil basis swaps 2.0 (1.7 ) (1.5 ) (0.1 ) Crude oil percentage basis swaps 0.9 0.1 (0.1 ) — Crude oil options — — — (0.7 ) Gasoline swaps (0.2 ) — (0.3 ) — Gasoline crack spread swaps (1.2 ) — (2.4 ) — Diesel swaps (0.2 ) — (0.4 ) — Diesel crack spread swaps (1.4 ) — (5.8 ) — Natural gas swaps — (0.2 ) — 0.1 Total $ (2.3 ) $ (1.8 ) $ (9.7 ) $ (4.9 ) The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the nine months ended September 30, 2017 and 2016 , related to its derivative instruments not designated as hedges (in millions): Type of Derivative Amount of Realized Gain (loss) Recognized in Gain (Loss) on Derivative Instruments Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Specialty products segment: Natural gas swaps $ (2.9 ) $ (8.4 ) $ 0.5 $ 9.4 Natural gas collars — (1.0 ) — 0.9 Fuel products segment: Inventory financing obligation — — (3.8 ) — Crude oil swaps (2.5 ) 1.3 (2.2 ) 7.6 Crude oil basis swaps 2.6 (1.6 ) 7.9 (5.0 ) Crude oil percentage basis swaps 1.5 (4.3 ) 1.2 5.4 Crude oil options — (1.5 ) — (0.5 ) Crude oil futures — (2.0 ) — — Gasoline swaps (0.2 ) — (0.3 ) — Gasoline crack spread swaps (2.8 ) (1.2 ) 2.4 4.3 Diesel swaps (0.2 ) — (0.4 ) — Diesel crack spread swaps (1.7 ) — (3.1 ) — 2/1/1 crack spread swaps (1.0 ) — — — Natural gas swaps — (1.4 ) — 1.4 Total $ (7.2 ) $ (20.1 ) $ 2.2 $ 23.5 Derivative Positions — Specialty Products Segment Natural Gas Swap Contracts At September 30, 2017 , 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 Fourth Quarter 2017 960,000 $ 3.72 Total 960,000 Average price $ 3.72 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 September 30, 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 Fourth Quarter 2017 419,161 4,556 $ 49.05 Calendar Year 2018 28,000 77 $ 48.25 Total 447,161 Average price $ 49.00 At September 30, 2017 , 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 Fourth Quarter 2017 133,216 1,448 $ 41.56 Total 133,216 Average price $ 41.56 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 Purchased 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 has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At September 30, 2017 , 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 Fourth Quarter 2017 644,000 7,000 $ (13.22 ) Total 644,000 Average differential $ (13.22 ) 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 has entered into derivative instruments to secure a percentage differential of WCS crude oil to NYMEX WTI. At September 30, 2017 , 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 Fourth Quarter 2017 276,000 3,000 72.3 % Total 276,000 Average percentage 72.3 % 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 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 September 30, 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 Fourth Quarter 2017 1,149,000 12,489 $ 12.98 Calendar Year 2018 826,000 2,263 $ 12.24 Total 1,975,000 Average price $ 12.67 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 September 30, 2017 , the Company had the following derivatives related to gasoline swap sales in its fuel products segment, none of which are designated as hedges: Gasoline Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap Fourth Quarter 2017 46,000 500 $ 62.75 Calendar Year 2018 14,000 38 $ 61.35 Total 60,000 Average price $ 62.42 At December 31, 2016 , the Company did not have any derivatives related to gasoline swap sales in its fuel products segment. Diesel Crack Spread Swap Contracts At September 30, 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 Fourth Quarter 2017 1,149,000 12,489 $ 18.17 Calendar Year 2018 826,000 2,263 $ 17.58 Total 1,975,000 Average price $ 17.92 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 September 30, 2017 , the Company had the following derivatives related to diesel swap sales in its fuel products segment, none of which are designated as hedges: Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap Fourth Quarter 2017 46,000 500 $ 67.58 Calendar Year 2018 14,000 38 $ 66.35 Total 60,000 Average price $ 67.29 At December 31, 2016 , the Company did not have any derivatives related to diesel swap sales in its fuel products segment. 2/1/1 Crack Spread Swap Contracts At September 30, 2017 , the Company did not have any derivatives related to 2/1/1 crack spread sales in its fuel products segment. 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	9 Months Ended
	Sep. 30, 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 unaudited condensed consolidated financial statements at fair value. The Company’s commodity derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s commodity derivative instruments are with counterparties that have long-term credit ratings of at least Baa1 and BBB+ by Moody’s and S&P, respectively. To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument prior to settlement, the Company used discounted cash flows, which use observable inputs such as maturity and market interest rates. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the 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 September 30, 2017 , the Company’s net assets were increased by less than $0.1 million and net liabilities were reduced by approximately $0.1 million . 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 nonperformance 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 9 for further information on derivative instruments. Inventory Financing Agreements 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 and the contingent interest feature are embedded derivatives 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 unaudited condensed consolidated statements of operations. The valuation of the repurchase obligation derivative requires the Company to make estimates of the prices and differentials assuming settlement at the end of the reporting period; therefore it is classified as Level 3. Pension Assets Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At September 30, 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 (approximately 10 business days), if requested. See Note 11 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 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 6 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 at September 30, 2017 and December 31, 2016 , were as follows (in millions): September 30, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Natural gas swaps $ — $ — $ (0.3 ) $ (0.3 ) $ — $ — $ — $ — Gasoline crack spread swaps — — (0.3 ) $ (0.3 ) — — — — Diesel crack spread swaps — — (0.8 ) $ (0.8 ) — — — — Crude oil swaps — — 0.5 0.5 — — 2.9 2.9 Crude oil percentage basis swaps — — 0.7 0.7 — — — — Crude oil basis swaps — — 0.5 0.5 — — (2.1 ) (2.1 ) Total derivative assets — — 0.3 0.3 — — 0.8 0.8 Pension plan investments — — — — 0.3 — — 0.3 Total recurring assets at fair value $ — $ — $ 0.3 $ 0.3 $ 0.3 $ — $ 0.8 $ 1.1 Liabilities: Derivative liabilities: Inventory financing obligation $ — $ — $ (3.8 ) $ (3.8 ) $ — $ — $ — $ — Crude oil swaps — — (0.6 ) (0.6 ) — — (0.8 ) (0.8 ) Crude oil basis swaps — — 0.5 0.5 — — (5.0 ) (5.0 ) Crude oil percentage basis swaps — — — — — — (0.5 ) (0.5 ) Gasoline swaps — — (0.3 ) (0.3 ) — — — — Gasoline crack spread swaps — — (2.1 ) (2.1 ) — — (3.5 ) (3.5 ) Diesel swaps — — (0.4 ) (0.4 ) — — — — Diesel crack spread swaps — — (5.0 ) (5.0 ) — — (1.4 ) (1.4 ) 2/1/1 crack spread swaps — — — — — — (2.5 ) (2.5 ) Natural gas swaps — — (0.4 ) (0.4 ) — — (1.1 ) (1.1 ) Total derivative liabilities — — (12.1 ) (12.1 ) — — (14.8 ) (14.8 ) RINs Obligation — (41.0 ) — (41.0 ) — (79.3 ) — (79.3 ) Liability Awards (4.1 ) — — (4.1 ) — — — — Total recurring liabilities at fair value $ (4.1 ) $ (41.0 ) $ (12.1 ) $ (57.2 ) $ — $ (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 for the nine months ended September 30, 2017 and 2016 (in millions): Nine Months Ended September 30, 2017 2016 Fair value at January 1, $ (14.0 ) $ (33.9 ) Realized loss on derivative instruments 7.2 20.1 Unrealized gain on derivative instruments 2.2 23.5 Settlements (7.2 ) (20.0 ) Fair value at September 30, $ (11.8 ) $ (10.3 ) Total gain included in net loss attributable to changes in unrealized gain relating to financial assets and liabilities held as of September 30, $ 2.2 $ 23.5 All settlements from derivative instruments designated as cash flow hedges and deemed “effective” are included in sales for gasoline, diesel and jet fuel derivatives, and cost of sales for crude oil derivatives in the unaudited condensed consolidated statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these settlements from derivative instruments designated as cash flow hedges are recorded in earnings in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments designated as fair value hedges are accrued and recorded as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments not designated as hedges are recorded in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 9 for further information on derivative instruments. Nonrecurring Fair Value Measurements Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements. The Company periodically evaluates the carrying value of long-lived assets to be held and used, including indefinite-lived intangible assets and property, plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements. Estimated Fair Value of Financial Instruments Cash and Cash Equivalents The carrying value of cash and cash equivalents is considered to be representative of its fair value. Debt The estimated fair value of long-term debt at September 30, 2017 and December 31, 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 and other obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 8 for further information on long-term debt. The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at September 30, 2017 and December 31, 2016 , were as follows (in millions): September 30, 2017 December 31, 2016 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,543.9 $ 1,555.4 $ 1,334.1 $ 1,552.2 Senior secured notes 2 $ 464.1 $ 386.8 $ 458.8 $ 384.5 Revolving credit facility 3 $ 0.1 $ 0.1 $ 6.0 $ 6.0 Capital lease and other obligations 3 $ 51.6 $ 51.6 $ 54.5 $ 54.5

Employee Benefit Plans

Employee Benefit Plans	9 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans The components of net periodic benefit income for the three and nine months ended September 30, 2017 and 2016 , were as follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Interest cost $ 0.6 $ 0.6 $ 1.8 $ 1.9 Expected return on assets (0.7 ) (0.8 ) (2.3 ) (2.4 ) Amortization of net loss 0.1 — 0.1 0.1 Net periodic benefit income $ — $ (0.2 ) $ (0.4 ) $ (0.4 ) At September 30, 2017 and December 31, 2016 , 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 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 of 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 10 for the definition of Level 1. The Company’s pension plan assets measured at fair value at September 30, 2017 and December 31, 2016 , were as follows (in millions): September 30, 2017 December 31, 2016 Level 1 Total Level 1 Total Plan assets subject to leveling: Cash and cash equivalents $ — $ — $ 0.3 $ 0.3 Total plan assets subject to leveling $ — — $ 0.3 0.3 Plan assets measured at net asset value: Domestic equities 6.1 8.6 Foreign equities 6.2 8.7 Fixed income 22.1 32.2 Total plan assets measured at net asset value 34.4 49.5 Total plan assets $ 34.4 $ 49.8 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.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	9 Months Ended
	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Loss The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive loss in the Company’s unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 (in millions): Components of Accumulated Other Comprehensive Loss Amount Reclassified From Accumulated Other Comprehensive Loss Location of Gain (Loss) Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Derivative gains (losses) reflected in gross profit: $ — $ 14.5 $ — $ 45.6 Sales — (9.7 ) — (36.4 ) Cost of sales $ — $ 4.8 $ — $ 9.2 Total Amortization of defined benefit pension plans: Amortization of net loss $ (0.1 ) $ — $ (0.1 ) $ (0.1 ) (1) $ (0.1 ) $ — $ (0.1 ) $ (0.1 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic benefit income. See Note 11 for additional details.

Earnings Per Unit

Earnings Per Unit	9 Months Ended
	Sep. 30, 2017
Earnings Per Unit [Abstract]
Earnings Per Unit	Earnings Per Unit The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2017 and 2016 (in millions, except unit and per unit data): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Numerator for basic and diluted earnings per limited partner unit: Net loss $ (23.6 ) $ (33.4 ) $ (20.2 ) $ (249.0 ) General partner’s interest in net loss (0.5 ) (0.7 ) (0.4 ) (5.0 ) Net loss available to limited partners $ (23.1 ) $ (32.7 ) $ (19.8 ) $ (244.0 ) Denominator for basic and diluted earnings per limited partner unit: Basic and diluted weighted average limited partner units outstanding (1) 77,632,784 77,331,347 77,537,531 76,767,975 Limited partners’ interest basic and diluted net loss per unit $ (0.30 ) $ (0.42 ) $ (0.25 ) $ (3.18 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.3 million for the three and nine months ended September 30, 2017 as compared to the 0.1 million and 0.2 million , respectively, of dilutive phantom units for the three and nine months ended September 30, 2016 .

Segments and Related Informatio

Segments and Related Information	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Segments and Related Information	Segments and Related Information a. Segment Reporting The Company manages its business in multiple operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments: • Specialty Products. The specialty products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants and other products which are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. Specialty products also include synthetic lubricants used primarily in manufacturing, mining and automotive applications. • Fuel Products . The fuel products segment produces primarily gasoline, diesel, jet fuel and asphalt which are primarily sold to customers located in the PADD 2, PADD 3 and PADD 4 areas within the U.S. • Oilfield Services. The oilfield services segment markets its products and oilfield services including drilling fluids, completion fluids and solids control services to the oil and gas industry. 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 — “Summary of Significant Accounting Policies” in Part II, Item 8 “Financial Statements and Supplementary Data” of the Company’s 2016 Annual Report, 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; (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 (loss) 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 for the three months ended September 30, 2017 and 2016 , is as follows (in millions): Three Months Ended September 30, 2017 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 305.8 $ 720.7 $ 70.9 $ 1,097.4 $ — $ 1,097.4 Intersegment sales — 14.9 — 14.9 (14.9 ) — Total sales $ 305.8 $ 735.6 $ 70.9 $ 1,112.3 $ (14.9 ) $ 1,097.4 Loss from unconsolidated affiliates $ (0.1 ) $ — $ (0.1 ) $ (0.2 ) $ — $ (0.2 ) Adjusted EBITDA $ 43.0 $ 46.3 $ 6.4 $ 95.7 $ — $ 95.7 Reconciling items to net loss: Depreciation and amortization 20.6 30.6 3.8 55.0 — 55.0 Unrealized loss on derivatives 9.7 Interest expense 47.4 Non-cash equity based compensation and other non-cash items 7.3 Income tax benefit (0.1 ) Net loss $ (23.6 ) Three Months Ended September 30, 2016 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 315.7 $ 616.6 $ 34.3 $ 966.6 $ — $ 966.6 Intersegment sales 0.1 12.7 — 12.8 (12.8 ) — Total sales $ 315.8 $ 629.3 $ 34.3 $ 979.4 $ (12.8 ) $ 966.6 Loss from unconsolidated affiliates $ (0.2 ) $ — $ (0.1 ) $ (0.3 ) $ — $ (0.3 ) Adjusted EBITDA $ 43.4 $ 13.8 $ (3.3 ) $ 53.9 $ — $ 53.9 Reconciling items to net loss: Depreciation and amortization 18.8 28.8 4.8 52.4 — 52.4 Realized loss on derivatives, not reflected in net loss or settled in a prior period (2.6 ) (2.2 ) — (4.8 ) — (4.8 ) Unrealized loss on derivatives 4.9 Interest expense 44.6 Non-cash equity based compensation and other non-cash items (2.2 ) Income tax benefit (7.6 ) Net loss $ (33.4 ) Reportable segment information for the nine months ended September 30, 2017 and 2016 , is as follows (in millions): Nine Months Ended September 30, 2017 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 986.1 $ 1,893.9 $ 185.7 $ 3,065.7 $ — $ 3,065.7 Intersegment sales 0.2 47.5 — 47.7 (47.7 ) — Total sales $ 986.3 $ 1,941.4 $ 185.7 $ 3,113.4 $ (47.7 ) $ 3,065.7 Loss from unconsolidated affiliates $ (0.1 ) $ — $ (0.3 ) $ (0.4 ) $ — $ (0.4 ) Adjusted EBITDA $ 155.7 $ 117.1 $ 3.2 $ 276.0 $ — $ 276.0 Reconciling items to net loss: Depreciation and amortization 53.5 85.9 11.6 151.0 — 151.0 Asset Impairment 0.4 — — 0.4 — 0.4 Unrealized gain on derivatives (2.2 ) Interest expense 135.8 Non-cash equity based compensation and other non-cash items 12.3 Income tax benefit (1.1 ) Net loss $ (20.2 ) Nine Months Ended September 30, 2016 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 948.8 $ 1,615.7 $ 88.0 $ 2,652.5 $ — $ 2,652.5 Intersegment sales 0.5 26.4 — 26.9 (26.9 ) — Total sales $ 949.3 $ 1,642.1 $ 88.0 $ 2,679.4 $ (26.9 ) $ 2,652.5 Loss from unconsolidated affiliates $ (0.2 ) $ (18.0 ) $ (0.3 ) $ (18.5 ) $ — $ (18.5 ) Adjusted EBITDA $ 160.9 $ (13.3 ) $ (17.1 ) $ 130.5 $ — $ 130.5 Reconciling items to net loss: Depreciation and amortization 56.0 82.0 14.4 152.4 — 152.4 Realized loss on derivatives, not reflected in net loss or settled in a prior period (1.4 ) (7.8 ) — (9.2 ) — (9.2 ) Asset Impairment — 33.4 — 33.4 — 33.4 Loss from sale of unconsolidated affiliate — 113.9 — 113.9 — 113.9 Unrealized gain on derivatives (23.5 ) Interest expense 117.7 Non-cash equity based compensation and other non-cash items 1.9 Income tax benefit (7.1 ) Net loss $ (249.0 ) b. Geographic Information International sales accounted for less than 10% of consolidated sales in each of the three and nine months ended September 30, 2017 and 2016 . Substantially all of the Company’s long-lived assets are domestically located. c. Product Information The Company offers specialty products primarily in categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products and other. Fuel products categories primarily consist of gasoline, diesel, jet fuel, asphalt, heavy fuel oils and other. All oilfield services products are consolidated in a standalone category. The following table sets forth the major product category sales for the three months ended September 30, 2017 and 2016 (dollars in millions): Three Months Ended September 30, 2017 2016 Specialty products: Lubricating oils $ 148.8 13.6 % $ 133.0 13.8 % Solvents 62.6 5.7 % 60.6 6.3 % Waxes 27.4 2.5 % 33.2 3.4 % Packaged and synthetic specialty products 62.8 5.7 % 79.6 8.2 % Other 4.2 0.4 % 9.3 1.0 % Total $ 305.8 27.9 % $ 315.7 32.7 % Fuel products: Gasoline $ 260.5 23.7 % $ 209.4 21.7 % Diesel 241.9 22.0 % 216.7 22.4 % Jet fuel 36.0 3.3 % 32.3 3.3 % Asphalt, heavy fuel oils and other 182.3 16.6 % 158.2 16.4 % Total $ 720.7 65.6 % $ 616.6 63.8 % Oilfield services: Total $ 70.9 6.5 % $ 34.3 3.5 % Consolidated sales $ 1,097.4 100.0 % $ 966.6 100.0 % The following table sets forth the major product category sales for the nine months ended September 30, 2017 and 2016 (dollars in millions): Nine Months Ended September 30, 2017 2016 Specialty products: Lubricating oils $ 453.2 14.8 % $ 408.5 15.4 % Solvents 198.7 6.5 % 177.6 6.7 % Waxes 87.4 2.9 % 96.7 3.6 % Packaged and synthetic specialty products 224.3 7.3 % 237.1 8.9 % Other 22.5 0.7 % 28.9 1.2 % Total $ 986.1 32.2 % $ 948.8 35.8 % Fuel products: Gasoline $ 736.1 24.0 % $ 599.6 22.6 % Diesel 658.9 21.5 % 594.2 22.4 % Jet fuel 106.4 3.5 % 81.5 3.1 % Asphalt, heavy fuel oils and other 392.5 12.8 % 340.4 12.8 % Total $ 1,893.9 61.8 % $ 1,615.7 60.9 % Oilfield services: Total $ 185.7 6.0 % $ 88.0 3.3 % Consolidated sales $ 3,065.7 100.0 % $ 2,652.5 100.0 % d. Major Customers During the three and nine months ended September 30, 2017 and 2016 , the Company had no customer that represented 10% or greater of consolidated sales. e. Major Suppliers During the three months ended September 30, 2017 and 2016 , the Company had two suppliers that supplied approximately 64.8% and 72.9% , respectively, of its crude oil supply. During the nine months ended September 30, 2017 and 2016 , the Company had two suppliers that supplied approximately 65.9% and 62.6% , respectively, of its crude oil supply.

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events	9 Months Ended
	Sep. 30, 2017
Subsequent Events [Abstract]
Subsequent Events	15. Subsequent Events On November 8, 2017, Calumet Lubricants Co., Limited Partnership, an Indiana limited partnership (“Calumet Lubricants”) and a wholly-owned subsidiary of the Company, completed its previously announced sale to Husky of the Superior Refinery including its wholesale marketing business and related assets, including certain owned or leased product terminals, and certain crude gathering assets and line space in North Dakota for net proceeds of approximately $ 492.1 million in cash, which includes payment for net working capital and reimbursement of certain capital spending. The cash consideration is subject to certain purchase price adjustments relating to, among other things, final net working capital adjustments. The gain on sale cannot be estimated at this time. On November 21, 2017, Calumet Operating, LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Company, completed the sale (the “Anchor Transaction”) 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 $84.0 million including $50 million in cash, $15 million to be paid at various times over the next two years for net working capital and other items, and 10% equity ownership in Fluid Holding Corp, the parent company of Q’Max. The cash consideration is subject to certain purchase price adjustments relating to, among other things, final net working capital adjustments. The Company evaluated the criteria for recording a disposal group as held for sale and discontinued operations. This criteria was not met as September 30, 2017; therefore, the Company did not present this disposal group as discontinued operations in the unaudited condensed consolidated balance sheet and unaudited condensed consolidated statements of operations. Beginning in the fourth quarter of 2017, the historical results attributable to Anchor for periods prior to the transaction will be reflected in the Company’s unaudited condensed consolidated financial statements as discontinued operations. The loss on sale cannot be estimated at this time. On November 13, 2017, 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 by November 9, 2017, the due date for such filing, without unreasonable effort or expense. Also on November 13, 2017, the Company received notice from the Listing Qualifications Department of Nasdaq stating that the Company was not in compliance with Nasdaq Listing Rule 5250(c)(1) for continued listing because the Company did not timely file this Quarterly Report on Form 10-Q for the quarter ended September 30, 2017. The Nasdaq notice was issued in accordance with standard Nasdaq procedures and had no immediate effect on the continued listing of the Company’s common units on Nasdaq. In the Nasdaq notice, Nasdaq indicated that the Company had 60 calendar days to submit a plan to regain compliance. This Form 10-Q is being filed within that 60 calendar-day period. As described herein, the Company is party to the Second Amended and Restated Credit Agreement, dated as of July 14, 2014, as amended, among the Company, certain of its Subsidiaries, certain lenders, and Bank of America, N.A., as agent for those lenders. Pursuant to this revolving credit agreement, the Company was required to deliver unaudited consolidated financial statements for the quarter ended September 30, 2017 on or before November 14, 2017. However, the Company was unable to deliver the unaudited consolidated financial statements for the quarter ended September 30, 2017 when required due to financial reporting difficulties caused by the implementation of an enterprise resource planning system. Failure to deliver the unaudited consolidated financial statements for the quarter ended September 30, 2017 by such time would have been an “Event of Default” as that term is defined in the revolving credit agreement. If an Event of Default exists under the revolving credit agreement, then the lenders may accelerate the Company’s borrowings under the credit agreement, require cash collateralization of outstanding letters of credit, and exercise other rights and remedies thereunder. On November 13, 2017, the lenders of the revolving credit facility consented to permit the Company to deliver its unaudited consolidated financial statements for the quarter ended September 30, 2017 on or before December 5, 2017, and effective November 30, 2017, the lenders consented in writing to postpone the due date for delivery of the unaudited consolidated financial statements for the quarter ended September 30, 2017 until December 31, 2017. As described herein, the Company is party to the Supply and Offtake Agreements and pursuant to the Supply and Offtake Agreements, the Company was required to deliver unaudited consolidated financial statements for the quarter ended September 30, 2017 on or before November 14, 2017. However, for the reasons described above, the Company was unable to deliver the unaudited consolidated financial statements for the quarter ended September 30, 2017. On November 14, 2017, Macquarie agreed to grant the Company a temporary waiver of its obligation to deliver the unaudited consolidated financial statements for the quarter ended September 30, 2017 until December 15, 2017, and effective December 12, 2017, Macquarie consented in writing to postpone the due date for delivery of the unaudited consolidated financial statements for the quarter ended September 30, 2017 until December 31, 2017.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Basis of Accounting	The unaudited condensed consolidated financial statements of the Company as of September 30, 2017 and for the three and nine months ended September 30, 2017 and 2016 , included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires 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 unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2016 Annual Report.
RINS Obligation	The Company’s 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 unaudited condensed consolidated statements of cash flows. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN 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 condensed 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 unaudited condensed consolidated statements of operations. The assets and liabilities associated with our RINs Obligation are considered recurring fair value measurements.
New Accounting Pronouncements	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 unaudited condensed consolidated financial statements. In May 2017, the FASB issued 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 is not expected to have an impact on the Company’s unaudited condensed consolidated financial statements. In March 2017, the FASB issued ASU No. 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 is not expected to have an impact on the Company’s unaudited condensed 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. The amendments in this standard 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 this standard on its unaudited condensed 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 unaudited condensed consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in Accounting Standard Codification Topic 605, Revenue Recognition . ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires enhanced disclosures. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the original effective date by one year to annual and interim periods beginning after December 15, 2017, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. In March, April, May and December 2016, the FASB clarified the implementation guidance on principal versus agent considerations, identifying performance obligations, licensing, collectability, presentation of sales taxes, non-cash consideration, transition, the scope of Topic 606, impairment testing, policy elections over determining the provision for losses on certain types of contracts, the accrual of advertising costs and disclosure requirements. All amendments are effective with the same date as ASU 2014-09. The Company is currently evaluating the impact of these standards on its unaudited condensed consolidated financial statements. The Company is required to adopt ASU 2014-09 as of January 1, 2018, and expects to use the modified retrospective approach. The Company has an implementation work team evaluating contracts from the various revenue streams across all of its business segments to evaluate and implement changes to business processes, systems and controls. Based on the evaluation performed to date, 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. The Company does not believe that these elements would result in a material change to how revenue would be recognized for these agreements upon the adoption of ASU 2014-09 or have a material effect on the Company’s unaudited condensed consolidated financial statements. As a result of adopting the new standard, there will be changes to our 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. The Company continues to analyze the full impact on its operating segments of the adoption of ASU 2014-09, which may result in differences between current revenue recognition practices and those required by ASU 2014-09 that may be material. As part of the Company’s evaluation, it has segregated its revenue streams into categories which will serve as the basis for the continuing accounting analysis on, and documentation of revenues, as it relates to the impact of ASU 2014-09. In addition, the Company continues to actively monitor outstanding issues currently being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the FASB’s Transition Resource Group, since conclusions reached by these groups may impact its application of ASU 2014-09.
Accounting Changes and Error Corrections	Correction of Immaterial Errors During the quarter ended September 30, 2016, the Company identified and corrected errors in the accounting for the lower of cost or market of inventory and income taxes that related to the year ended December 31, 2015. These errors primarily related to lower of cost or market (“LCM”) adjustments at its Branded and Packaging operating segment and an adjustment for a tax benefit associated with its decision to liquidate a wholly-owned C corporation as of December 31, 2015, and convert it to an entity which will not be subject to tax. The impact of correcting these items in the third quarter of 2016 increased cost of sales by $6.5 million , increased income tax benefit by $7.8 million and decreased net loss by $1.3 million . The Company concluded that the corrections to the financial statements were immaterial to its financial results for the year ended December 31, 2016 and 2015. 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 by 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. In light of declines in certain markets the Company serves, an evaluation of existing and future capacity, and as part of its annual planning and budgeting process which is currently in progress, the Company will perform an assessment of its major long-lived assets which may result in long-lived asset impairment. The Company will complete its asset recoverability assessment and analyze the conclusions of that assessment in connection with the annual planning and budgeting process. Until these activities are complete, it is not practicable to reasonably estimate the existence or range of potential future impairments related to the Company’s long-lived assets.
Inventories	The cost of inventory is recorded using the last-in, first-out (“LIFO”) method. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. 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. The Company records the inventory owned by Macquarie as inventory with a corresponding obligation on the Company’s condensed consolidated balance sheets because Macquarie maintains the risk of loss until the refined products are sold to third parties and the Company is obligated to repurchase the inventory in certain scenarios. The agreements are accounted for similar to a product financing arrangement.
Impairment of Long-Lived Assets	Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell.
Investment in Unconsolidated Affiliates	The Company accounts for its ownership in PACNIL under the equity method of accounting.
Derivatives	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 gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is realized in the unaudited condensed consolidated statements of operations in gain (loss) on derivative instruments. Additionally, the Company has entered into natural gas swaps, crude oil swaps, crack spread swaps, diesel swaps and gasoline swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and natural gas purchases and gasoline and diesel sales at the Company’s refineries. Derivative Instruments Designated as Fair Value Hedges For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the unaudited condensed consolidated statements of operations. No hedge ineffectiveness is recognized if the interest rate swap qualifies for the “shortcut” method and, as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items. Fair value hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective fair value hedge, the derivative instrument is still subject to mark-to-market method of accounting, however the Company will cease to adjust the hedged asset or liability for changes in fair value. 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. 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 maintain 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 and the contingent interest feature are embedded derivatives 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 unaudited condensed consolidated statements of operations. The Company recognizes all derivative instruments at their fair values (see Note 10 ) as either current assets or current liabilities in the condensed consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. Derivative Instruments Designated as Cash Flow Hedges Prior to 2017, the Company accounted for certain derivatives hedging purchases of crude oil and sales of diesel swaps as cash flow hedges. As of September 30, 2017 , the Company has no derivative instruments designated as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases are recorded to sales and cost of sales, respectively, in the unaudited condensed consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. The Company assesses, both at inception of the cash flow hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Periodically, the Company may enter into crude oil and fuel product basis swaps to more effectively hedge its crude oil purchases, crude oil sales and fuel products sales. These derivatives can be combined with a swap contract in order to create a more effective cash flow hedge. To the extent a derivative instrument designated as a cash flow hedge is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations. Ineffectiveness is inherent in the hedging of crude oil and fuel products. Due to the volatility in the markets for crude oil and fuel products, the Company is unable to predict the amount of ineffectiveness each period, determined on a derivative by derivative basis or in the aggregate for a specific commodity and has the potential for the future loss of cash flow hedge accounting. Ineffectiveness has resulted, and the loss of cash flow hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize cash flows. Cash flow hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When cash flow hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously deferred in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations.
Fair Value Measurement	Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The Company’s commodity derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument prior to settlement, the Company used discounted cash flows, which use observable inputs such as maturity and market interest rates. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the 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 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 and other obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. 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 and the contingent interest feature are embedded derivatives 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 unaudited condensed consolidated statements of operations. The valuation of the repurchase obligation derivative requires the Company to make estimates of the prices and differentials assuming settlement at the end of the reporting period; therefore it is 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 nonperformance 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. All settlements from derivative instruments designated as cash flow hedges and deemed “effective” are included in sales for gasoline, diesel and jet fuel derivatives, and cost of sales for crude oil derivatives in the unaudited condensed consolidated statements of operations in the period that the hedged cash flow occurs. Any “ineffectiveness” associated with these settlements from derivative instruments designated as cash flow hedges are recorded in earnings in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments designated as fair value hedges are accrued and recorded as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. All settlements from derivative instruments not designated as hedges are recorded in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. 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. The carrying value of cash and cash equivalents is considered to be representative of its fair value. Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements. The Company periodically evaluates the carrying value of long-lived assets to be held and used, including indefinite-lived intangible assets and property, plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements. The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service. Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At September 30, 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 (approximately 10 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.
Segment Reporting	The Company manages its business in multiple operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments: • Specialty Products. The specialty products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants and other products which are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. Specialty products also include synthetic lubricants used primarily in manufacturing, mining and automotive applications. • Fuel Products . The fuel products segment produces primarily gasoline, diesel, jet fuel and asphalt which are primarily sold to customers located in the PADD 2, PADD 3 and PADD 4 areas within the U.S. • Oilfield Services. The oilfield services segment markets its products and oilfield services including drilling fluids, completion fluids and solids control services to the oil and gas industry. 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 — “Summary of Significant Accounting Policies” in Part II, Item 8 “Financial Statements and Supplementary Data” of the Company’s 2016 Annual Report, 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; (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 (loss) 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. The Company offers specialty products primarily in categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products and other. Fuel products categories primarily consist of gasoline, diesel, jet fuel, asphalt, heavy fuel oils and other. All oilfield services products are consolidated in a standalone category.

Summary of Significant Accoun24

Summary of Significant Accounting Policies Summary of SIgnificant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Other Current Liabilities [Table Text Block]	Other current liabilities consisted of the following as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 RINs Obligation $ 41.0 $ 79.3 Other 18.7 20.3 Total $ 59.7 $ 99.6

Inventories (Tables)

Inventories (Tables)	9 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
Summary of Inventories	Inventories consist of the following (in millions): September 30, 2017 December 31, 2016 Titled Inventory Supply and Offtake Agreements (1) Total Titled Inventory Supply and Offtake Agreements (1) Total Raw materials $ 31.1 $ 14.4 $ 45.5 $ 57.4 $ — $ 57.4 Work in process 35.1 24.5 59.6 74.2 — 74.2 Finished goods 174.9 44.4 219.3 254.6 — 254.6 $ 241.1 $ 83.3 $ 324.4 $ 386.2 $ — $ 386.2 (1) Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Refer to Note 7 for further information.

Divestiture Divestiture (Tables

Divestiture Divestiture (Tables)	9 Months Ended
	Sep. 30, 2017
Superior Divestiture [Abstract]
Income from Individually Significant Component Disposed of or Held-for-sale, Excluding Discontinued Operations, before Income Tax	The following table details the major classes of assets and liabilities of Superior (in millions): September 30, 2017 ASSETS HELD FOR SALE Current assets: Accounts receivable $ 52.1 Inventories 72.9 Total current assets held for sale 125.0 Property, plant and equipment, net 198.2 Goodwill 5.2 Other noncurrent assets, net 11.7 Total noncurrent assets held for sale 215.1 Total assets held for sale $ 340.1 LIABILITIES HELD FOR SALE Current liabilities: Accounts payable $ 66.9 Accrued salaries, wages and benefits 1.9 Other taxes payable 3.8 Other current liabilities 1.9 Total current liabilities held for sale 74.5 Pension and postretirement benefit obligations 7.1 Total noncurrent liabilities held for sale 7.1 Total liabilities held for sale $ 81.6 The following table presents the net income before income taxes of the asset held for sale for the periods presented (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Net income before income taxes $ 17.0 $ 19.5 $ 82.5 $ 54.5

Investment in Unconsolidated 27

Investment in Unconsolidated Affiliates Investment in Unconsolidated Affiliates (Tables)	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments [Table Text Block]	The following table summarizes the Company’s investments in unconsolidated affiliates as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Investment Percent Ownership Investment Percent Ownership Pacific New Investment Limited $ 9.5 23.8 % $ 9.6 23.8 % Other 0.4 0.7 Total $ 9.9 $ 10.3

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Instrument [Line Items]
Summary of Long-Term Debt	Long-term debt consisted of the following (in millions): September 30, 2017 December 31, 2016 Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rate of 7.4% and 4.8% for the nine months ended September 30, 2017 and year ended December 31, 2016, respectively. $ 0.1 $ 10.2 Borrowings under 2021 Secured Notes, interest at a fixed rate of 11.5%, interest payments semiannually, borrowings due January 2021, effective interest rate of 12.3% and 12.2% for the nine months ended September 30, 2017 and year ended December 31, 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 the nine months ended September 30, 2017 and year ended December 31, 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 the nine months ended September 30, 2017 and year ended December 31, 2016. (1) 352.2 352.5 Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the nine months ended September 30, 2017 and year ended December 31, 2016. 325.0 325.0 Other 6.9 8.0 Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034. 44.7 46.5 Less unamortized debt issuance costs (2) (27.7 ) (33.2 ) Less unamortized discounts (10.3 ) (11.8 ) Total long-term debt $ 1,990.9 $ 1,997.2 Less current portion of long-term debt 4.3 3.5 $ 1,986.6 $ 1,993.7 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.2 million and $2.5 million as of September 30, 2017 and December 31, 2016 , respectively (refer to Note 9 for additional information on the interest rate swap designated as a fair value hedge). (2) Deferred debt issuance costs are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $19.8 million and $14.5 million at September 30, 2017 and December 31, 2016 , respectively.
Summary of Principal Payments on Debt Obligations and Future Minimum Rentals on Capital Lease Obligations	As of September 30, 2017 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2017 $ 0.8 2018 4.2 2019 2.9 2020 2.4 2021 1,303.3 Thereafter 713.1 Total $ 2,026.7

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative [Line Items]
Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative 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 condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Balance Sheet Location Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps Derivative assets $ — $ (0.3 ) $ (0.3 ) $ 0.1 $ (0.1 ) $ — Fuel products segment: Crude oil swaps Derivative assets 1.9 (1.4 ) 0.5 10.3 (7.4 ) 2.9 Crude oil basis swaps Derivative assets 1.0 (0.5 ) 0.5 — (2.1 ) (2.1 ) Crude oil percentage basis swaps Derivative assets 0.7 — 0.7 0.1 (0.1 ) — Gasoline crack spread swaps Derivative assets 0.2 (0.5 ) (0.3 ) — — — Diesel crack spread swap Derivative assets — (0.8 ) (0.8 ) — — — Total derivative instruments $ 3.8 $ (3.5 ) $ 0.3 $ 10.5 $ (9.7 ) $ 0.8
Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative 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 condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Balance Sheet Location Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets Derivative instruments not designated as hedges: Specialty products segment: Natural gas swaps Derivative liabilities $ (0.7 ) $ 0.3 $ (0.4 ) $ (1.2 ) $ 0.1 $ (1.1 ) Fuel products segment: Inventory financing obligation Obligations under inventory financing agreements (3.8 ) — (3.8 ) — — — Crude oil swaps Derivative liabilities (2.0 ) 1.4 (0.6 ) (8.2 ) 7.4 (0.8 ) Crude oil basis swaps Derivative liabilities — 0.5 0.5 (7.1 ) 2.1 (5.0 ) Crude oil percentage basis swaps Derivative liabilities — — — (0.6 ) 0.1 (0.5 ) Gasoline swaps Derivative liabilities (0.3 ) — (0.3 ) — — — Gasoline crack spread swaps Derivative liabilities (2.6 ) 0.5 (2.1 ) (3.5 ) — (3.5 ) Diesel swaps Derivative liabilities (0.4 ) — (0.4 ) — — — Diesel crack spread swaps Derivative liabilities (5.8 ) 0.8 (5.0 ) (1.4 ) — (1.4 ) 2/1/1 crack spread swaps Derivative liabilities — — — (2.5 ) — (2.5 ) Total derivative instruments $ (15.6 ) $ 3.5 $ (12.1 ) $ (24.5 ) $ 9.7 $ (14.8 )
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The Company recorded the following losses in its unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 , related to its derivative instrument designated as a fair value hedge (in millions): Location of Loss of Derivative Amount of Loss Recognized Hedged Item Location of Gain on Hedged Item Amount of Gain Recognized Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 Swaps not allocated to a specific segment: Interest rate swap Interest expense $ 0.1 $ 0.1 $ 0.3 $ 0.3 2022 Notes Interest income $ — $ — $ — $ — Total $ 0.1 $ 0.1 $ 0.3 $ 0.3 $ — $ — $ — $ —
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive loss and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended September 30, 2017 and 2016 , related to its derivative instruments that were designated as cash flow hedges (in millions): Type of Derivative Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion) Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion) Three Months Ended Location of Gain (Loss) Three Months Ended Location of Gain (Loss) Three Months Ended September 30, September 30, September 30, 2017 2016 2017 2016 2017 2016 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ — $ 2.6 Gain (loss) on derivative instruments $ — $ — Fuel products segment: Crude oil swaps — (2.3 ) Cost of sales — (12.3 ) Gain (loss) on derivative instruments — — Diesel swaps — 2.3 Sales — 14.5 Gain (loss) on derivative instruments — — Total $ — $ — $ — $ 4.8 $ — $ — The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive loss and unaudited condensed consolidated statements of partners’ capital as of and for the nine months ended September 30, 2017 and 2016 , related to its derivative instruments that were designated as cash flow hedges (in millions): Type of Derivative Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion) Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion) Nine Months Ended Location of Gain (Loss) Nine Months Ended Location of Gain (Loss) Nine Months Ended September 30, September 30, September 30, 2017 2016 2017 2016 2017 2016 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ — $ 1.4 Gain (loss) on derivative instruments $ — $ — Fuel products segment: Crude oil swaps — (8.1 ) Cost of sales — (37.8 ) Gain (loss) on derivative instruments — — Diesel swaps — 8.1 Sales — 45.6 Gain (loss) on derivative instruments — — Total $ — $ — $ — $ 9.2 $ — $ —
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended September 30, 2017 and 2016 , related to its derivative instruments not designated as hedges (in millions): Type of Derivative Amount of Realized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 Specialty products segment: Natural gas swaps $ (1.2 ) $ (1.8 ) $ 1.1 $ 0.9 Natural gas collars — (0.3 ) — 0.3 Fuel products segment: Inventory financing obligation — — (2.9 ) — Crude oil swaps (1.0 ) 2.1 2.6 (5.4 ) Crude oil basis swaps 2.0 (1.7 ) (1.5 ) (0.1 ) Crude oil percentage basis swaps 0.9 0.1 (0.1 ) — Crude oil options — — — (0.7 ) Gasoline swaps (0.2 ) — (0.3 ) — Gasoline crack spread swaps (1.2 ) — (2.4 ) — Diesel swaps (0.2 ) — (0.4 ) — Diesel crack spread swaps (1.4 ) — (5.8 ) — Natural gas swaps — (0.2 ) — 0.1 Total $ (2.3 ) $ (1.8 ) $ (9.7 ) $ (4.9 ) The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the nine months ended September 30, 2017 and 2016 , related to its derivative instruments not designated as hedges (in millions): Type of Derivative Amount of Realized Gain (loss) Recognized in Gain (Loss) on Derivative Instruments Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Specialty products segment: Natural gas swaps $ (2.9 ) $ (8.4 ) $ 0.5 $ 9.4 Natural gas collars — (1.0 ) — 0.9 Fuel products segment: Inventory financing obligation — — (3.8 ) — Crude oil swaps (2.5 ) 1.3 (2.2 ) 7.6 Crude oil basis swaps 2.6 (1.6 ) 7.9 (5.0 ) Crude oil percentage basis swaps 1.5 (4.3 ) 1.2 5.4 Crude oil options — (1.5 ) — (0.5 ) Crude oil futures — (2.0 ) — — Gasoline swaps (0.2 ) — (0.3 ) — Gasoline crack spread swaps (2.8 ) (1.2 ) 2.4 4.3 Diesel swaps (0.2 ) — (0.4 ) — Diesel crack spread swaps (1.7 ) — (3.1 ) — 2/1/1 crack spread swaps (1.0 ) — — — Natural gas swaps — (1.4 ) — 1.4 Total $ (7.2 ) $ (20.1 ) $ 2.2 $ 23.5
Natural Gas Swap Contracts [Member] | Specialty Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At September 30, 2017 , 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 Fourth Quarter 2017 960,000 $ 3.72 Total 960,000 Average price $ 3.72 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 [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At September 30, 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 Fourth Quarter 2017 419,161 4,556 $ 49.05 Calendar Year 2018 28,000 77 $ 48.25 Total 447,161 Average price $ 49.00 At September 30, 2017 , 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 Fourth Quarter 2017 133,216 1,448 $ 41.56 Total 133,216 Average price $ 41.56 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 Purchased 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 [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At September 30, 2017 , 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 Fourth Quarter 2017 644,000 7,000 $ (13.22 ) Total 644,000 Average differential $ (13.22 ) 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 [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	The Company has entered into derivative instruments to secure a percentage differential of WCS crude oil to NYMEX WTI. At September 30, 2017 , 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 Fourth Quarter 2017 276,000 3,000 72.3 % Total 276,000 Average percentage 72.3 % 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 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 [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At September 30, 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 Fourth Quarter 2017 1,149,000 12,489 $ 12.98 Calendar Year 2018 826,000 2,263 $ 12.24 Total 1,975,000 Average price $ 12.67 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 [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At September 30, 2017 , the Company had the following derivatives related to gasoline swap sales in its fuel products segment, none of which are designated as hedges: Gasoline Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap Fourth Quarter 2017 46,000 500 $ 62.75 Calendar Year 2018 14,000 38 $ 61.35 Total 60,000 Average price $ 62.42 At December 31, 2016 , the Company did not have any derivatives related to gasoline swap sales in its fuel products segment.
Diesel Crack Spread Swaps [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At September 30, 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 Fourth Quarter 2017 1,149,000 12,489 $ 18.17 Calendar Year 2018 826,000 2,263 $ 17.58 Total 1,975,000 Average price $ 17.92 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 [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At September 30, 2017 , the Company had the following derivatives related to diesel swap sales in its fuel products segment, none of which are designated as hedges: Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap Fourth Quarter 2017 46,000 500 $ 67.58 Calendar Year 2018 14,000 38 $ 66.35 Total 60,000 Average price $ 67.29 At December 31, 2016 , the Company did not have any derivatives related to diesel swap sales in its fuel products segment.
2-1-1- Crack Spread Swap [Member] | Fuel Product [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At September 30, 2017 , the Company did not have any derivatives related to 2/1/1 crack spread sales in its fuel products segment. 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)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Summary of Recurring Assets and Liabilities Measured at Fair Value	The Company’s recurring assets and liabilities measured at fair value at September 30, 2017 and December 31, 2016 , were as follows (in millions): September 30, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Natural gas swaps $ — $ — $ (0.3 ) $ (0.3 ) $ — $ — $ — $ — Gasoline crack spread swaps — — (0.3 ) $ (0.3 ) — — — — Diesel crack spread swaps — — (0.8 ) $ (0.8 ) — — — — Crude oil swaps — — 0.5 0.5 — — 2.9 2.9 Crude oil percentage basis swaps — — 0.7 0.7 — — — — Crude oil basis swaps — — 0.5 0.5 — — (2.1 ) (2.1 ) Total derivative assets — — 0.3 0.3 — — 0.8 0.8 Pension plan investments — — — — 0.3 — — 0.3 Total recurring assets at fair value $ — $ — $ 0.3 $ 0.3 $ 0.3 $ — $ 0.8 $ 1.1 Liabilities: Derivative liabilities: Inventory financing obligation $ — $ — $ (3.8 ) $ (3.8 ) $ — $ — $ — $ — Crude oil swaps — — (0.6 ) (0.6 ) — — (0.8 ) (0.8 ) Crude oil basis swaps — — 0.5 0.5 — — (5.0 ) (5.0 ) Crude oil percentage basis swaps — — — — — — (0.5 ) (0.5 ) Gasoline swaps — — (0.3 ) (0.3 ) — — — — Gasoline crack spread swaps — — (2.1 ) (2.1 ) — — (3.5 ) (3.5 ) Diesel swaps — — (0.4 ) (0.4 ) — — — — Diesel crack spread swaps — — (5.0 ) (5.0 ) — — (1.4 ) (1.4 ) 2/1/1 crack spread swaps — — — — — — (2.5 ) (2.5 ) Natural gas swaps — — (0.4 ) (0.4 ) — — (1.1 ) (1.1 ) Total derivative liabilities — — (12.1 ) (12.1 ) — — (14.8 ) (14.8 ) RINs Obligation — (41.0 ) — (41.0 ) — (79.3 ) — (79.3 ) Liability Awards (4.1 ) — — (4.1 ) — — — — Total recurring liabilities at fair value $ (4.1 ) $ (41.0 ) $ (12.1 ) $ (57.2 ) $ — $ (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 for the nine months ended September 30, 2017 and 2016 (in millions): Nine Months Ended September 30, 2017 2016 Fair value at January 1, $ (14.0 ) $ (33.9 ) Realized loss on derivative instruments 7.2 20.1 Unrealized gain on derivative instruments 2.2 23.5 Settlements (7.2 ) (20.0 ) Fair value at September 30, $ (11.8 ) $ (10.3 ) Total gain included in net loss attributable to changes in unrealized gain relating to financial assets and liabilities held as of September 30, $ 2.2 $ 23.5
Summary of the Company's Carrying and Estimated Fair Value of the Company's Financial Instruments, Carried at Adjusted Historical Cost	The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at September 30, 2017 and December 31, 2016 , were as follows (in millions): September 30, 2017 December 31, 2016 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,543.9 $ 1,555.4 $ 1,334.1 $ 1,552.2 Senior secured notes 2 $ 464.1 $ 386.8 $ 458.8 $ 384.5 Revolving credit facility 3 $ 0.1 $ 0.1 $ 6.0 $ 6.0 Capital lease and other obligations 3 $ 51.6 $ 51.6 $ 54.5 $ 54.5

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
Summary of Components of Net Periodic Pension Cost	The components of net periodic benefit income for the three and nine months ended September 30, 2017 and 2016 , were as follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Interest cost $ 0.6 $ 0.6 $ 1.8 $ 1.9 Expected return on assets (0.7 ) (0.8 ) (2.3 ) (2.4 ) Amortization of net loss 0.1 — 0.1 0.1 Net periodic benefit income $ — $ (0.2 ) $ (0.4 ) $ (0.4 )
Schedule of Pension Plan Assets Measured at Fair Value	The Company’s pension plan assets measured at fair value at September 30, 2017 and December 31, 2016 , were as follows (in millions): September 30, 2017 December 31, 2016 Level 1 Total Level 1 Total Plan assets subject to leveling: Cash and cash equivalents $ — $ — $ 0.3 $ 0.3 Total plan assets subject to leveling $ — — $ 0.3 0.3 Plan assets measured at net asset value: Domestic equities 6.1 8.6 Foreign equities 6.2 8.7 Fixed income 22.1 32.2 Total plan assets measured at net asset value 34.4 49.5 Total plan assets $ 34.4 $ 49.8

Accumulated Other Comprehensi32

Accumulated Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Summary of Reclassification Adjustments out of Accumulated Other Comprehensive Income (Loss)	The table below sets forth a summary of reclassification adjustments out of accumulated other comprehensive loss in the Company’s unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 (in millions): Components of Accumulated Other Comprehensive Loss Amount Reclassified From Accumulated Other Comprehensive Loss Location of Gain (Loss) Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Derivative gains (losses) reflected in gross profit: $ — $ 14.5 $ — $ 45.6 Sales — (9.7 ) — (36.4 ) Cost of sales $ — $ 4.8 $ — $ 9.2 Total Amortization of defined benefit pension plans: Amortization of net loss $ (0.1 ) $ — $ (0.1 ) $ (0.1 ) (1) $ (0.1 ) $ — $ (0.1 ) $ (0.1 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic benefit income. See Note 11 for additional details.

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	9 Months Ended
	Sep. 30, 2017
Earnings Per Unit [Abstract]
Summary of Computation of Basic and Diluted Earnings Per Limited Partner Unit	The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2017 and 2016 (in millions, except unit and per unit data): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Numerator for basic and diluted earnings per limited partner unit: Net loss $ (23.6 ) $ (33.4 ) $ (20.2 ) $ (249.0 ) General partner’s interest in net loss (0.5 ) (0.7 ) (0.4 ) (5.0 ) Net loss available to limited partners $ (23.1 ) $ (32.7 ) $ (19.8 ) $ (244.0 ) Denominator for basic and diluted earnings per limited partner unit: Basic and diluted weighted average limited partner units outstanding (1) 77,632,784 77,331,347 77,537,531 76,767,975 Limited partners’ interest basic and diluted net loss per unit $ (0.30 ) $ (0.42 ) $ (0.25 ) $ (3.18 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.3 million for the three and nine months ended September 30, 2017 as compared to the 0.1 million and 0.2 million , respectively, of dilutive phantom units for the three and nine months ended September 30, 2016 .

Segments and Related Informat34

Segments and Related Information (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Schedule of Reportable Segment Information	Reportable segment information for the three months ended September 30, 2017 and 2016 , is as follows (in millions): Three Months Ended September 30, 2017 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 305.8 $ 720.7 $ 70.9 $ 1,097.4 $ — $ 1,097.4 Intersegment sales — 14.9 — 14.9 (14.9 ) — Total sales $ 305.8 $ 735.6 $ 70.9 $ 1,112.3 $ (14.9 ) $ 1,097.4 Loss from unconsolidated affiliates $ (0.1 ) $ — $ (0.1 ) $ (0.2 ) $ — $ (0.2 ) Adjusted EBITDA $ 43.0 $ 46.3 $ 6.4 $ 95.7 $ — $ 95.7 Reconciling items to net loss: Depreciation and amortization 20.6 30.6 3.8 55.0 — 55.0 Unrealized loss on derivatives 9.7 Interest expense 47.4 Non-cash equity based compensation and other non-cash items 7.3 Income tax benefit (0.1 ) Net loss $ (23.6 ) Three Months Ended September 30, 2016 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 315.7 $ 616.6 $ 34.3 $ 966.6 $ — $ 966.6 Intersegment sales 0.1 12.7 — 12.8 (12.8 ) — Total sales $ 315.8 $ 629.3 $ 34.3 $ 979.4 $ (12.8 ) $ 966.6 Loss from unconsolidated affiliates $ (0.2 ) $ — $ (0.1 ) $ (0.3 ) $ — $ (0.3 ) Adjusted EBITDA $ 43.4 $ 13.8 $ (3.3 ) $ 53.9 $ — $ 53.9 Reconciling items to net loss: Depreciation and amortization 18.8 28.8 4.8 52.4 — 52.4 Realized loss on derivatives, not reflected in net loss or settled in a prior period (2.6 ) (2.2 ) — (4.8 ) — (4.8 ) Unrealized loss on derivatives 4.9 Interest expense 44.6 Non-cash equity based compensation and other non-cash items (2.2 ) Income tax benefit (7.6 ) Net loss $ (33.4 ) Reportable segment information for the nine months ended September 30, 2017 and 2016 , is as follows (in millions): Nine Months Ended September 30, 2017 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 986.1 $ 1,893.9 $ 185.7 $ 3,065.7 $ — $ 3,065.7 Intersegment sales 0.2 47.5 — 47.7 (47.7 ) — Total sales $ 986.3 $ 1,941.4 $ 185.7 $ 3,113.4 $ (47.7 ) $ 3,065.7 Loss from unconsolidated affiliates $ (0.1 ) $ — $ (0.3 ) $ (0.4 ) $ — $ (0.4 ) Adjusted EBITDA $ 155.7 $ 117.1 $ 3.2 $ 276.0 $ — $ 276.0 Reconciling items to net loss: Depreciation and amortization 53.5 85.9 11.6 151.0 — 151.0 Asset Impairment 0.4 — — 0.4 — 0.4 Unrealized gain on derivatives (2.2 ) Interest expense 135.8 Non-cash equity based compensation and other non-cash items 12.3 Income tax benefit (1.1 ) Net loss $ (20.2 ) Nine Months Ended September 30, 2016 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 948.8 $ 1,615.7 $ 88.0 $ 2,652.5 $ — $ 2,652.5 Intersegment sales 0.5 26.4 — 26.9 (26.9 ) — Total sales $ 949.3 $ 1,642.1 $ 88.0 $ 2,679.4 $ (26.9 ) $ 2,652.5 Loss from unconsolidated affiliates $ (0.2 ) $ (18.0 ) $ (0.3 ) $ (18.5 ) $ — $ (18.5 ) Adjusted EBITDA $ 160.9 $ (13.3 ) $ (17.1 ) $ 130.5 $ — $ 130.5 Reconciling items to net loss: Depreciation and amortization 56.0 82.0 14.4 152.4 — 152.4 Realized loss on derivatives, not reflected in net loss or settled in a prior period (1.4 ) (7.8 ) — (9.2 ) — (9.2 ) Asset Impairment — 33.4 — 33.4 — 33.4 Loss from sale of unconsolidated affiliate — 113.9 — 113.9 — 113.9 Unrealized gain on derivatives (23.5 ) Interest expense 117.7 Non-cash equity based compensation and other non-cash items 1.9 Income tax benefit (7.1 ) Net loss $ (249.0 )
Schedule of Major Product Category Sales	The following table sets forth the major product category sales for the nine months ended September 30, 2017 and 2016 (dollars in millions): Nine Months Ended September 30, 2017 2016 Specialty products: Lubricating oils $ 453.2 14.8 % $ 408.5 15.4 % Solvents 198.7 6.5 % 177.6 6.7 % Waxes 87.4 2.9 % 96.7 3.6 % Packaged and synthetic specialty products 224.3 7.3 % 237.1 8.9 % Other 22.5 0.7 % 28.9 1.2 % Total $ 986.1 32.2 % $ 948.8 35.8 % Fuel products: Gasoline $ 736.1 24.0 % $ 599.6 22.6 % Diesel 658.9 21.5 % 594.2 22.4 % Jet fuel 106.4 3.5 % 81.5 3.1 % Asphalt, heavy fuel oils and other 392.5 12.8 % 340.4 12.8 % Total $ 1,893.9 61.8 % $ 1,615.7 60.9 % Oilfield services: Total $ 185.7 6.0 % $ 88.0 3.3 % Consolidated sales $ 3,065.7 100.0 % $ 2,652.5 100.0 % The following table sets forth the major product category sales for the three months ended September 30, 2017 and 2016 (dollars in millions): Three Months Ended September 30, 2017 2016 Specialty products: Lubricating oils $ 148.8 13.6 % $ 133.0 13.8 % Solvents 62.6 5.7 % 60.6 6.3 % Waxes 27.4 2.5 % 33.2 3.4 % Packaged and synthetic specialty products 62.8 5.7 % 79.6 8.2 % Other 4.2 0.4 % 9.3 1.0 % Total $ 305.8 27.9 % $ 315.7 32.7 % Fuel products: Gasoline $ 260.5 23.7 % $ 209.4 21.7 % Diesel 241.9 22.0 % 216.7 22.4 % Jet fuel 36.0 3.3 % 32.3 3.3 % Asphalt, heavy fuel oils and other 182.3 16.6 % 158.2 16.4 % Total $ 720.7 65.6 % $ 616.6 63.8 % Oilfield services: Total $ 70.9 6.5 % $ 34.3 3.5 % Consolidated sales $ 1,097.4 100.0 % $ 966.6 100.0 %

Description of the Business - N

Description of the Business - Narrative (Details) - shares	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Limited Partner [Member]
Schedule of Capitalization, Equity [Line Items]
Limited partners’ interest units outstanding (in shares)	76,729,706	76,392,258
Ownership percentage	98.00%
General Partner [Member]
Schedule of Capitalization, Equity [Line Items]
General partner equivalent units outstanding (in shares)	1,565,912
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	2.00%

Summary of Significant Accoun36

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Increase in Cost of Sales	$ 945.9	$ 856.3	$ 2,614.3	$ 2,324.7
Increase in Income tax benefit (expense)	0.1	7.6	1.1	7.1
(Increase) Decrease in Net loss	(23.6)	$ (33.4)	(20.2)	$ (249)
RINs Obligation	41		41		$ 79.3
Other	18.7		18.7		20.3
Total	$ 59.7		59.7		$ 99.6
Accounting For Lower Of Cost Or Market Of Inventory And Income Taxes [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Increase in Cost of Sales			6.5
Increase in Income tax benefit (expense)			7.8
(Increase) Decrease in Net loss			$ 1.3

Inventories - Narrative (Detail

Inventories - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventory method			last-in, first-out (“LIFO”)
Replacement cost of inventories, based on current market values	$ (20.1)		$ (20.1)		$ (14.4)
Lower of cost or market inventory adjustment	$ 11.1	$ (11.1)	$ 19.1	$ 33.3

Inventories - Summary of Invent

Inventories - Summary of Inventories (Details) - USD ($) $ in Millions		Sep. 30, 2017	Dec. 31, 2016
Inventories
Raw materials		$ 45.5	$ 57.4
Work in process		59.6	74.2
Finished goods		219.3	254.6
Inventories total		324.4	386.2
TitledInventory [Member]
Inventories
Raw materials		31.1	57.4
Work in process		35.1	74.2
Finished goods		174.9	254.6
Inventories total		241.1	386.2
Supply&OfftakeAgreements [Member]
Inventories
Raw materials	[1]	14.4	0
Work in process	[1]	24.5	0
Finished goods	[1]	44.4	0
Inventories total	[1]	$ 83.3	$ 0
[1]	Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Refer to Note 7 for further information.

Divestiture Divestiture (Detail

Divestiture Divestiture (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Aug. 11, 2017	Dec. 31, 2016
Superior Divestiture [Abstract]
Superior Refinery, Consideration					$ 435
Net income before income tax	$ 17	$ 19.5	$ 82.5	$ 54.5
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets held for sale	125		125			$ 0
Total noncurrent assets held for sale	215.1		215.1			0
Total current liabilities held for sale	74.5		74.5			0
Total noncurrent liabilities held for sale	7.1		7.1			$ 0
Superior Refinery [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts Receivable	52.1		52.1
Inventories	72.9		72.9
Total current assets held for sale	125		125
Property, Plant and Equipment, net	198.2		198.2
Goodwill	5.2		5.2
Other noncurrent assets, net	11.7		11.7
Total noncurrent assets held for sale	215.1		215.1
Total assets held for sale	340.1		340.1
Accounts payable	66.9		66.9
Disposal Group, Including Discontinued Operation, Accrued Liabilities	1.9		1.9
Other taxes payable	3.8		3.8
Other current liabilities	1.9		1.9
Total current liabilities held for sale	74.5		74.5
Pension and postretirement benefit obligations	7.1		7.1
Total noncurrent liabilities held for sale	7.1		7.1
Total liabilities held for sale	$ 81.6		$ 81.6

Investment in Unconsolidated 40

Investment in Unconsolidated Affiliates Investment in Unconsolidated Affiliates - Schedule (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliates	$ 9.9	$ 10.3
Pacific New Investment Limited [Member]
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliates	$ 9.5	$ 9.6
Equity interest percentage	23.80%	23.80%
Other Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliates	$ 0.4	$ 0.7

Investment in Unconsolidated 41

Investment in Unconsolidated Affiliates - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Oct. 15, 2016	Jun. 30, 2016	Jun. 27, 2016
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments			$ 0	$ 41
Investment in unconsolidated affiliates	$ 9.9		9.9		$ 10.3
Proceeds from Sale of unconsolidated affiliates			0	29
Repayments of Long-term Lines of Credit			791.3	934.1
Loss from sale of unconsolidated affiliates	$ 0	$ 0	$ 0	$ (113.4)
Hi-Speed [Member]
Schedule of Equity Method Investments [Line Items]
Equity interest percentage	6.00%		6.00%		6.00%
Pacific New Investment Limited [Member]
Schedule of Equity Method Investments [Line Items]
Contribution amount funded						$ 4.8	$ 4.8
Equity interest percentage	23.80%		23.80%		23.80%
Investment in unconsolidated affiliates	$ 9.5		$ 9.5		$ 9.6
Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity interest percentage								50.00%
Proceeds from Sale of unconsolidated affiliates		28.5
Repayments of Long-term Lines of Credit		36
Outstanding standby letters of credit								$ 39.4
Loss from sale of unconsolidated affiliates		$ 113.9

Commitments and Contingencies -

Commitments and Contingencies - Narrative - Environmental (Details) - USD ($) $ in Millions	Jun. 29, 2012	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Loss Contingencies [Line Items]
RINs Expense		$ 12.3	$ 10.1	$ 51.8	$ 35.1
Great Falls [Member]
Loss Contingencies [Line Items]
Environmental remediation expense				18.7
Great Falls [Member] | Capital Expenditure [Member]
Loss Contingencies [Line Items]
Environmental remediation expense				14.6
Great Falls [Member] | Expense [Member]
Loss Contingencies [Line Items]
Environmental remediation expense				4.1
WDNR-Superior [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		0.2	0.1	0.3	0.1
EPA [Member]
Loss Contingencies [Line Items]
Proposed penalty amount	$ 0.1
LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		0.1	$ 0.4	$ 0.6	$ 0.8
Settlement agreement with the LDEQ				Dec. 23, 2010
Settlement agreement with the LDEQ, effective date				Jan. 31, 2012
Shreveport [Member]
Loss Contingencies [Line Items]
Indemnified costs for certain specified environmental liabilities				$ 5
Shreveport [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Specified environmental liabilities first required amount to contribute				1
Bel-Ray [Member]
Loss Contingencies [Line Items]
Weston Agreement trust fund amount		0.6		0.6
Fair Value, Measurements, Recurring [Member]
Loss Contingencies [Line Items]
Obligations, Fair Value Disclosure		41		41		$ 79.3
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Loss Contingencies [Line Items]
Obligations, Fair Value Disclosure		$ 41		$ 41		$ 79.3

Commitments and Contingencies43

Commitments and Contingencies - Narrative - Occupational Health and Safety (Details) - USD ($) $ in Millions	Mar. 14, 2011	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Loss Contingencies [Line Items]
RINs Gain		$ (12.3)	$ (10.1)	$ (51.8)	$ (35.1)
Occupational Safety and Health Administration [Member]
Loss Contingencies [Line Items]
Date in which OSHA issued a Citation and Notification of Penalty	Mar. 14, 2011
Proposed penalty amount	$ 0.2

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies - Narrative -Standby Letters of Credit (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Revolving Credit Facility [Member]
Loss Contingencies [Line Items]
Outstanding standby letters of credit	$ 100.3	$ 82.1
Revolver commitments	$ 900	$ 900
Revolving Credit Facility [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Letter of credit sublimit	90.00%	90.00%
Letter of Credit [Member]
Loss Contingencies [Line Items]
Revolver commitments	$ 600	$ 600

Inventory Financing Agreement I

Inventory Financing Agreement Inventory Financing Agreement - Narrative (Details) $ in Millions	Jun. 19, 2017USD ($)D / bblbbl	Mar. 31, 2017USD ($)bbl / dbbl	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proceeds from inventory financing agreements					$ (91.6)	$ 0
Financing costs			$ 47.4	$ 44.6	135.8	$ 117.7
Inventory Financing Obligations
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)	60,000	30,000
Debt Issuance Costs, Current, Net			3.1		3.1
Financing costs			3.6		$ 4
Deferred payment arrangement, maximum percentage of eligible inventory					90.00%
Deferred payment arrangement, maximum amount			7.5		$ 7.5
Deferred payment arrangement, outstanding amount			7.3		7.3
Inventory Financing Obligations | Macquarie [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Amount retained from initial inventory purchase to cover credit and liquidation risks			$ 5		$ 5

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Millions		9 Months Ended	12 Months Ended
		Sep. 30, 2017	Dec. 31, 2016
Senior Notes [Abstract]
Other Long-term Debt		$ 6.9	$ 8
Deferred Finance Costs, Noncurrent, Net	[1]	(27.7)	(33.2)
Total long-term debt		1,990.9	1,997.2
Less current portion of long-term debt		4.3	3.5
Total long-term debt, excluding current portion		1,986.6	1,993.7
Revolving Credit Facility [Member]
Summary of Long-term debt
Borrowings under senior secured revolving credit agreement		$ 0.1	$ 10.2
Senior Notes [Abstract]
Weighted average interest rate		7.40%	4.80%
Notes Due January 2021 at Fixed Rated 11.5% Interest Payments [Member]
Summary of Long-term debt
Borrowings under Notes		$ 400	$ 400
Senior Notes [Abstract]
Fixed rate		11.50%	11.50%
Effective interest rate		12.30%	12.20%
Notes Due April 2021 at Fixed Rate of 6.5% Interest Payments [Member]
Summary of Long-term debt
Borrowings under Notes		$ 900	$ 900
Senior Notes [Abstract]
Fixed rate		6.50%	6.50%
Effective interest rate		6.80%	6.80%
7.625% Notes [Member]
Summary of Long-term debt
Borrowings under Notes	[2]	$ 352.2	$ 352.5
Senior Notes [Abstract]
Fixed rate		7.625%	7.625%
Effective interest rate		8.00%	8.00%
Notes Due April 2023 at Fixed Rate of 7.75% Interest Payments [Member]
Summary of Long-term debt
Borrowings under Notes		$ 325	$ 325
Senior Notes [Abstract]
Fixed rate		7.75%	7.75%
Effective interest rate		8.00%	8.00%
Capital Lease Obligations [Member]
Summary of Long-term debt
Capital lease obligations		$ 44.7	$ 46.5
Less unamortized discounts [Member]
Summary of Long-term debt
Less unamortized discounts		(10.3)	(11.8)
Interest Expense [Member] | Fair Value Hedging [Member]
Senior Notes [Abstract]
Liabilities, fair value adjustment		$ 2.2	$ 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 $19.8 million and $14.5 million at September 30, 2017 and December 31, 2016, respectively.
[2]	The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.2 million and $2.5 million as of September 30, 2017 and December 31, 2016, respectively (refer to Note 9 for additional information on the interest rate swap designated as a fair value hedge).

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - USD ($) $ in Millions	Apr. 20, 2016	Apr. 28, 2015	Mar. 27, 2015	Mar. 31, 2014	Nov. 26, 2013	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Accumulated Amortization, Deferred Finance Costs						$ 19.8	$ 14.5
Notes Due January 2021 at Fixed Rated 11.5% Interest Payments [Member]
Long-Term Debt (Textual) [Abstract]
Date senior notes issued and sold	Apr. 20, 2016
Senior notes, aggregate principal amount issued and sold	$ 400
Maturity date	Jan. 15, 2021
Debt instrument percent discount price of par	98.273%
Net proceeds from sale of senior notes	$ 382.5
Frequency of interest payment	semiannually
Notes Due April 2023 at Fixed Rate of 7.75% Interest Payments [Member]
Long-Term Debt (Textual) [Abstract]
Date senior notes issued and sold			Mar. 27, 2015
Senior notes, aggregate principal amount issued and sold			$ 325
Maturity date			Apr. 15, 2023
Debt instrument percent discount price of par			99.257%
Net proceeds from sale of senior notes			$ 317
Frequency of interest payment			semiannually
Notes Due April 2021 at Fixed Rate of 6.5% Interest Payments [Member]
Long-Term Debt (Textual) [Abstract]
Date senior notes issued and sold				Mar. 31, 2014
Senior notes, aggregate principal amount issued and sold				$ 900
Maturity date				Apr. 15, 2021
Net proceeds from sale of senior notes				$ 884
Frequency of interest payment				semiannually
7.625% Notes [Member]
Long-Term Debt (Textual) [Abstract]
Date senior notes issued and sold					Nov. 26, 2013
Senior notes, aggregate principal amount issued and sold					$ 350
Maturity date					Jan. 15, 2022
Debt instrument percent discount price of par					98.494%
Net proceeds from sale of senior notes					$ 337.4
Frequency of interest payment					semiannually
9.375% Notes [Member]
Long-Term Debt (Textual) [Abstract]
Extinguishment of Debt, Amount				$ 500	$ 100
9.625% Notes [Member]
Long-Term Debt (Textual) [Abstract]
Extinguishment of Debt, Amount		$ 178.8
Senior Notes [Member] | Maximum [Member]
Long-Term Debt (Textual) [Abstract]
Fixed charge coverage ratio						1.7
Revolving Credit Facility [Member]
Long-Term Debt (Textual) [Abstract]
Maturity date						Jul. 14, 2019
Frequency of interest payment						quarterly
Senior secured revolving credit facility						$ 900	900
Incremental uncommitted expansion feature						$ 500
Customary letter of credit fee, including a fronting fee per annum on the stated amount of each outstanding letter of credit						0.125%
Outstanding borrowings						$ 0.1	10.2
Outstanding standby letters of credit						$ 100.3	$ 82.1
Financial covenant						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
Revolving Credit Facility [Member] | Maximum [Member]
Long-Term Debt (Textual) [Abstract]
Unutilized commitments fee to the lender under the revolving credit facility						0.375%
Revolving Credit Facility [Member] | Minimum [Member]
Long-Term Debt (Textual) [Abstract]
Unutilized commitments fee to the lender under the revolving credit facility						0.25%
Prime Rate [Member] | Revolving Credit Facility [Member]
Long-Term Debt (Textual) [Abstract]
Basis points						0.50%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member]
Long-Term Debt (Textual) [Abstract]
Basis points						1.50%

Long-Term Debt - Summary of Pri

Long-Term Debt - Summary of Principal Payments on Debt Obligations and Future Minimum Rentals on Capital Lease Obligations (Details) $ in Millions	Sep. 30, 2017USD ($)
Maturities of long-term debt
2,017	$ 0.8
2,018	4.2
2,019	2.9
2,020	2.4
2,021	1,303.3
Thereafter	713.1
Long-term debt	$ 2,026.7

Derivatives - Summary of Gross

Derivatives - Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative Assets (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 3.8	$ 10.5
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(3.5)	(9.7)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0.3	0.8
Natural Gas Swaps [Member] | Not Designated as Hedging Instrument [Member] | Specialty Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	0.1
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.3)	(0.1)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	(0.3)	0
Crude Oil Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	1.9	10.3
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(1.4)	(7.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0.5	2.9
Crude Oil Basis Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	1	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.5)	(2.1)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0.5	(2.1)
Crude Oil Percent Basis Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0.7	0.1
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(0.1)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0.7	0
Gasoline Crack Spread Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0.2	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.5)	0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	(0.3)	0
Diesel Crack Spread Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.8)	0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	$ (0.8)	$ 0

Derivatives - Summary of Gros50

Derivatives - Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative Liabilities (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ (15.6)	$ (24.5)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	3.5	9.7
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(12.1)	(14.8)
Natural Gas Swaps [Member] | Specialty Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(0.7)	(1.2)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.3	0.1
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.4)	(1.1)
Crude Oil Swaps [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(2)	(8.2)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	1.4	7.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.6)	(0.8)
Crude Oil Basis Swaps [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	(7.1)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.5	2.1
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0.5	(5)
Crude Oil Percent Basis Swaps [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	(0.6)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0.1
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0	(0.5)
Gasoline Swaps [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(0.3)	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.3)	0
Gasoline Crack Spread Swaps [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(2.6)	(3.5)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.5	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(2.1)	(3.5)
Diesel Crack Spread Swaps [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(5.8)	(1.4)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.8	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(5)	(1.4)
2-1-1- Crack Spread Swap [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	(2.5)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0	(2.5)
Diesel Swaps [Member] | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(0.4)	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.4)	0
Inventory Financing Obligations | Fuel Product [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(3.8)	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	$ (3.8)	$ 0

Derivatives - Schedule of Deriv

Derivatives - Schedule of Derivative Instruments (Cash Flow Hedges) (Details) - Designated as Hedging Instrument [Member] - Cash Flow Hedging [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	$ 0	$ 0	$ 0	$ 0
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion)	0	4.8	0	9.2
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	0	0	0	0
Crude Oil Swaps [Member] | Specialty Product [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	0	0	0	0
Crude Oil Swaps [Member] | Specialty Product [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion)	0	2.6	0	1.4
Crude Oil Swaps [Member] | Specialty Product [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	0	0	0	0
Crude Oil Swaps [Member] | Fuel Product [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	0	(2.3)	0	(8.1)
Crude Oil Swaps [Member] | Fuel Product [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion)	0	(12.3)	0	(37.8)
Crude Oil Swaps [Member] | Fuel Product [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	0	0	0	0
Diesel Swaps [Member] | Fuel Product [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	0	2.3	0	8.1
Diesel Swaps [Member] | Fuel Product [Member] | Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Loss (Effective Portion)	0	14.5	0	45.6
Diesel Swaps [Member] | Fuel Product [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Loss on Derivatives (Ineffective Portion)	$ 0	$ 0	$ 0	$ 0

Derivatives - Schedule of Der52

Derivatives - Schedule of Derivative Instruments (Fair Value Hedges) (Details) - Fair Value Hedging [Member] - USD ($) $ in Millions	Jan. 13, 2015	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Interest Expense [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item				$ 2.2		$ 2.5
Interest Rate Contract [Member] | Interest Expense [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Loss of Derivative		$ 0.1	$ 0.1	0.3	$ 0.3
Interest Rate Contract [Member] | Interest Income [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item		0	0	0	0
Interest Rate Swap [Member] | Interest Expense [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Loss of Derivative		0.1	0.1	0.3	0.3
Gain (Loss) on Hedged Item	$ 3.3
Interest Rate Swap [Member] | Interest Income [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item		$ 0	$ 0	$ 0	$ 0

Derivatives - Schedule of Der53

Derivatives - Schedule of Derivative Instruments (Not Designated as Hedges) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	$ (2.3)	$ (1.8)	$ (7.2)	$ (20.1)
Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(9.7)	(4.9)	2.2	23.5
Natural Gas Swaps [Member] | Specialty Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(1.2)	(1.8)	(2.9)	(8.4)
Natural Gas Swaps [Member] | Specialty Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	1.1	0.9	0.5	9.4
Natural Gas Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(0.2)	0	(1.4)
Natural Gas Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0.1	0	1.4
Natural Gas Collars [Member] | Specialty Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(0.3)	0	(1)
Natural Gas Collars [Member] | Specialty Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0.3	0	0.9
Crude Oil Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(1)	2.1	(2.5)	1.3
Crude Oil Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	2.6	(5.4)	(2.2)	7.6
Crude Oil Basis Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	2	(1.7)	2.6	(1.6)
Crude Oil Basis Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(1.5)	(0.1)	7.9	(5)
Crude Oil Percent Basis Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0.9	0.1	1.5	(4.3)
Crude Oil Percent Basis Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.1)	0	1.2	5.4
Crude Oil Options [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0	0	(1.5)
Crude Oil Options [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(0.7)	0	(0.5)
Crude Oil Futures [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)			0	(2)
Crude Oil Futures [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)			0	0
Gasoline Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.2)	0	(0.2)	0
Gasoline Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.3)	0	(0.3)	0
Gasoline Crack Spread Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(1.2)	0	(2.8)	(1.2)
Gasoline Crack Spread Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(2.4)	0	2.4	4.3
Diesel Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.2)	0	(0.2)	0
Diesel Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.4)	0	(0.4)	0
2-1-1- Crack Spread Swap [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)			(1)	0
2-1-1- Crack Spread Swap [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)			0	0
Diesel Crack Spread Swaps [Member] | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(1.4)	0	(1.7)	0
Diesel Crack Spread Swaps [Member] | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(5.8)	0	(3.1)	0
Inventory Financing Obligations | Fuel Product [Member] | Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0	0	0
Inventory Financing Obligations | Fuel Product [Member] | Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	$ (2.9)	$ 0	$ (3.8)	$ 0

Derivatives - Schedule of Der54

Derivatives - Schedule of Derivative Positions (Natural Gas Swaps - Specialty) (Details) - Natural Gas Swap Contracts [Member] - Specialty Product [Member] - Not Designated as Hedging Instrument [Member]	Sep. 30, 2017MMBTU$ / MMBtu	Dec. 31, 2016MMBTU$ / MMBtu
Derivative [Line Items]
MMBtu	960,000	4,950,000
$/MMBtu	3.72	3.85
First Quarter 2017 [Member]
Derivative [Line Items]
MMBtu | MMBTU		1,350,000
$/MMBtu		3.88
Second Quarter 2017 [Member]
Derivative [Line Items]
MMBtu | MMBTU		1,320,000
$/MMBtu		3.87
Third Quarter 2017 [Member]
Derivative [Line Items]
MMBtu | MMBTU		1,320,000
$/MMBtu		3.87
Fourth Quarter 2017 [Member]
Derivative [Line Items]
MMBtu	960,000	960,000
$/MMBtu	3.72	3.72

Derivatives - Schedule of Der55

Derivatives - Schedule of Derivative Positions (Crude Oil Swaps & Basis Swaps) (Details) - Fuel Product [Member] - Not Designated as Hedging Instrument [Member]	Sep. 30, 2017bbl$ / bbl	Dec. 31, 2016USD ($)bbl$ / bbl
Crude Oil Swap Purchases [Member]
Derivative [Line Items]
Derivative, notional amount	447,161	1,297,976
Average Swap ($/Bbl) | $ / bbl	49	48.87
Crude Oil Swap Purchases [Member] | First Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		320,049
Barrels per day, purchased		3,556
Average Swap ($/Bbl) | $ / bbl		48.87
Crude Oil Swap Purchases [Member] | Second Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		323,605
Barrels per day, purchased		3,556
Average Swap ($/Bbl) | $ / bbl		48.87
Crude Oil Swap Purchases [Member] | Third Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		327,161
Barrels per day, purchased		3,556
Average Swap ($/Bbl) | $ / bbl		48.87
Crude Oil Swap Purchases [Member] | Fourth Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	419,161	327,161
Barrels per day, purchased	4,556	3,556
Average Swap ($/Bbl) | $ / bbl	49.05	48.87
Crude Oil Swap Purchases [Member] | Calendar Year 2018 [Member]
Derivative [Line Items]
Derivative, notional amount	28,000
Barrels per day, purchased	77
Average Swap ($/Bbl) | $ / bbl	48.25
Crude Oil Swap Sales [Member]
Derivative [Line Items]
Derivative, notional amount	133,216	528,520
Average Swap ($/Bbl) | $ / bbl	41.56	41.56
Crude Oil Swap Sales [Member] | First Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount | $		130,320
Barrels per day, sold		1,448
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Sales [Member] | Second Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount | $		131,768
Barrels per day, sold		1,448
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Sales [Member] | Third Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount | $		133,216
Barrels per day, sold		1,448
Average Swap ($/Bbl) | $ / bbl		41.56
Crude Oil Swap Sales [Member] | Fourth Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	133,216	133,216
Barrels per day, sold	1,448	1,448
Average Swap ($/Bbl) | $ / bbl	41.56	41.56
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member]
Derivative [Line Items]
Derivative, notional amount	644,000	2,555,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(13.22)	(13.22)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | First Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		630,000
Barrels per day, purchased		7,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl		(13.22)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Second Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		637,000
Barrels per day, purchased		7,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl		(13.22)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Third Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		644,000
Barrels per day, purchased		7,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl		(13.22)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Fourth Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	644,000	644,000
Barrels per day, purchased	7,000	7,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(13.22)	(13.22)

Derivatives - Schedule of Der56

Derivatives - Schedule of Derivative Positions (Crude Oil Percent Basis Swaps) (Details) - Fuel Product [Member] - Crude Oil Percent Basis Swaps Purchased [Member] - Not Designated as Hedging Instrument [Member] - bbl	Sep. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative, notional amount	276,000	1,095,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	72.30%	72.30%
First Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		270,000
Barrels per day, purchased		3,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)		72.30%
Second Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		273,000
Barrels per day, purchased		3,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)		72.30%
Third Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		276,000
Barrels per day, purchased		3,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)		72.30%
Fourth Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	276,000	276,000
Barrels per day, purchased	3,000	3,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	72.30%	72.30%

Derivatives Schedule of Derivat

Derivatives Schedule of Derivative Positions (Gasoline Crack Spread Swaps) (Details) $ in Millions	Sep. 30, 2017bbl$ / bbl	Dec. 31, 2016bbl$ / bbl	Jan. 13, 2015USD ($)
Derivative [Line Items]
Derivative, Notional Amount | $			$ 200
Gasoline Crack Spread Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Derivative [Line Items]
Derivative, notional amount	1,975,000	590,000
Average Swap ($/Bbl) | $ / bbl	12.67	10.21
Gasoline Crack Spread Swaps [Member] | First Quarter 2017 [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Derivative [Line Items]
Derivative, notional amount		590,000
Barrels per day, sold		6,556
Average Swap ($/Bbl) | $ / bbl		10.21
Gasoline Crack Spread Swaps [Member] | Fourth Quarter 2017 [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Derivative [Line Items]
Derivative, notional amount	1,149,000
Barrels per day, sold	12,489
Average Swap ($/Bbl) | $ / bbl	12.98
Gasoline Crack Spread Swaps [Member] | Calendar Year 2018 [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Derivative [Line Items]
Derivative, notional amount	826,000
Barrels per day, sold	2,263
Average Swap ($/Bbl) | $ / bbl	12.24

Derivatives Derivatives - Sched

Derivatives Derivatives - Schedule of Derivative Positions (Gasoline Swap) (Details) - Gasoline Swaps [Member] - Not Designated as Hedging Instrument [Member] - Fuel Product [Member]	Sep. 30, 2017bbl$ / bbl	Dec. 31, 2016bbl
Derivative [Line Items]
Derivative, notional amount	60,000	0
Average Swap ($/Bbl) | $ / bbl	62.42
Fourth Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	46,000
Barrels per day, sold	500
Average Swap ($/Bbl) | $ / bbl	62.75
Calendar Year 2018 [Member]
Derivative [Line Items]
Derivative, notional amount	14,000
Barrels per day, sold	38
Average Swap ($/Bbl) | $ / bbl	61.35

Derivatives Schedule of Deriv59

Derivatives Schedule of Derivative Positions (Diesel Crack Spread Swaps) (Details) (Details) - Diesel Crack Spread Swaps [Member] - Not Designated as Hedging Instrument [Member] - Fuel Product [Member]	Sep. 30, 2017bbl$ / bbl	Dec. 31, 2016bbl$ / bbl
Derivative [Line Items]
Derivative, notional amount	1,975,000	590,000
Average Swap ($/Bbl) | $ / bbl	17.92	13.67
First Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		590,000
Barrels per day, sold		6,556
Average Swap ($/Bbl) | $ / bbl		13.67
Fourth Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	1,149,000
Barrels per day, sold	12,489
Average Swap ($/Bbl) | $ / bbl	18.17
Calendar Year 2018 [Member]
Derivative [Line Items]
Derivative, notional amount	826,000
Barrels per day, sold	2,263
Average Swap ($/Bbl) | $ / bbl	17.58

Derivatives Derivatives - Sch60

Derivatives Derivatives - Schedule of Derivative Positions (Diesel Swap) (Details) - Diesel Swaps [Member] - Not Designated as Hedging Instrument [Member] - Fuel Product [Member]	Sep. 30, 2017bbl$ / bbl	Dec. 31, 2016bbl
Derivative [Line Items]
Derivative, notional amount	60,000	0
Average Swap ($/Bbl) | $ / bbl	67.29
Fourth Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	46,000
Barrels per day, sold	500
Average Swap ($/Bbl) | $ / bbl	67.58
Calendar Year 2018 [Member]
Derivative [Line Items]
Derivative, notional amount	14,000
Barrels per day, sold	38
Average Swap ($/Bbl) | $ / bbl	66.35

Derivatives Derivatives - Sch61

Derivatives Derivatives - Schedule of Derivative Positions (2-1-1 Crack Spread Swaps) (Details) - 2-1-1- Crack Spread Swap [Member] - Not Designated as Hedging Instrument [Member] - Fuel Product [Member]	Sep. 30, 2017bbl	Dec. 31, 2016bbl$ / bbl
Derivative [Line Items]
Derivative, notional amount	0	590,000
Average Swap ($/Bbl) | $ / bbl		11.91
First Quarter 2017 [Member]
Derivative [Line Items]
Derivative, notional amount		590,000
Barrels per day, sold		6,556
Average Swap ($/Bbl) | $ / bbl		11.91

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) $ in Millions	Jan. 13, 2015USD ($)	Sep. 30, 2017USD ($)bbl	Dec. 31, 2016USD ($)bbl
Derivative [Line Items]
Counterparties in which derivatives held were net assets		2	1
Derivative Asset		$ 0.3	$ 0.8
Derivative, Collateral, Right to Reclaim Securities		0	0
Derivative, Collateral, Obligation to Return Securities		0	0
Accumulated other comprehensive loss		(8.2)	(8.3)
Derivative, Notional Amount	$ 200
Derivative gains (losses) reflected in gross profit:
Derivative [Line Items]
Accumulated other comprehensive loss		0	0
Fair Value Hedging [Member] | Interest Expense [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item		2.2	2.5
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities		15.6	24.5
Gasoline Swaps [Member] | Fuel Product [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities		$ 0.3	$ 0
Derivative, notional amount | bbl		60,000	0
Gasoline Swaps [Member] | Fourth Quarter 2017 [Member] | Fuel Product [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount | bbl		46,000
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest Expense [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item	$ 3.3
Diesel Swaps [Member] | Fuel Product [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities		$ 0.4	$ 0
Derivative, notional amount | bbl		60,000	0
Diesel Swaps [Member] | Fourth Quarter 2017 [Member] | Fuel Product [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount | bbl		46,000
2-1-1- Crack Spread Swap [Member] | Fuel Product [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities		$ 0	$ 2.5
Derivative, notional amount | bbl		0	590,000
2-1-1- Crack Spread Swap [Member] | First Quarter 2017 [Member] | Fuel Product [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount | bbl			590,000
Inventory Financing Obligations | Fuel Product [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities		$ 3.8	$ 0

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Increase in net derivative asset	$ 0.1	$ 0.1
Reduction in net derivative liability	$ 0.1	$ 0.5
Date goodwill impairment is reviewed, annually	Oct. 1, 2017

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Recurring Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Assets:
Derivative Asset	$ 0.3	$ 0.8
Pension plan investments	34.4	49.8
Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset	0.3	0.8
Pension plan investments	0	0.3
Total recurring assets at fair value	0.3	1.1
Derivative liabilities:
Total derivative liabilities	(12.1)	(14.8)
RINs Obligation	(41)	(79.3)
Liability Awards	(4.1)	0
Total recurring liabilities at fair value	(57.2)	(94.1)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Derivative Asset	0	0
Pension plan investments	0	0.3
Total recurring assets at fair value	0	0.3
Derivative liabilities:
Total derivative liabilities	0	0
RINs Obligation	0	0
Liability Awards	(4.1)	0
Total recurring liabilities at fair value	(4.1)	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Derivative Asset	0	0
Pension plan investments	0	0
Total recurring assets at fair value	0	0
Derivative liabilities:
Total derivative liabilities	0	0
RINs Obligation	(41)	(79.3)
Liability Awards	0	0
Total recurring liabilities at fair value	(41)	(79.3)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Derivative Asset	0.3	0.8
Pension plan investments	0	0
Total recurring assets at fair value	0.3	0.8
Derivative liabilities:
Total derivative liabilities	(12.1)	(14.8)
RINs Obligation	0	0
Liability Awards	0	0
Total recurring liabilities at fair value	(12.1)	(14.8)
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset	0.5	2.9
Derivative liabilities:
Total derivative liabilities	(0.6)	(0.8)
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Derivative Asset	0.5	2.9
Derivative liabilities:
Total derivative liabilities	(0.6)	(0.8)
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset	0.5	(2.1)
Derivative liabilities:
Total derivative liabilities	0.5	(5)
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Derivative Asset	0.5	(2.1)
Derivative liabilities:
Total derivative liabilities	0.5	(5)
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset	0.7	0
Derivative liabilities:
Total derivative liabilities	0	(0.5)
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Derivative Asset	0.7	0
Derivative liabilities:
Total derivative liabilities	0	(0.5)
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(0.3)	0
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(0.3)	0
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset	(0.3)	0
Derivative liabilities:
Total derivative liabilities	(2.1)	(3.5)
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Derivative Asset	(0.3)	0
Derivative liabilities:
Total derivative liabilities	(2.1)	(3.5)
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(0.4)	0
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(0.4)	0
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset	(0.8)	0
Derivative liabilities:
Total derivative liabilities	(5)	(1.4)
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Derivative Asset	(0.8)	0
Derivative liabilities:
Total derivative liabilities	(5)	(1.4)
2-1-1- Crack Spread Swap [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	0	(2.5)
2-1-1- Crack Spread Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
2-1-1- Crack Spread Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
2-1-1- Crack Spread Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	0	(2.5)
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset	(0.3)	0
Derivative liabilities:
Total derivative liabilities	(0.4)	(1.1)
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Derivative Asset	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Derivative Asset	(0.3)	0
Derivative liabilities:
Total derivative liabilities	(0.4)	(1.1)
Inventory Financing Obligations | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(3.8)	0
Inventory Financing Obligations | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Inventory Financing Obligations | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Inventory Financing Obligations | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(3.8)	0
Not Designated as Hedging Instrument [Member]
Derivative liabilities:
Total derivative liabilities	(12.1)	(14.8)
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil Swaps [Member]
Assets:
Derivative Asset	0.5	2.9
Derivative liabilities:
Total derivative liabilities	(0.6)	(0.8)
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil Basis Swaps [Member]
Assets:
Derivative Asset	0.5	(2.1)
Derivative liabilities:
Total derivative liabilities	0.5	(5)
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil Percent Basis Swaps [Member]
Assets:
Derivative Asset	0.7	0
Derivative liabilities:
Total derivative liabilities	0	(0.5)
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Gasoline Swaps [Member]
Derivative liabilities:
Total derivative liabilities	(0.3)	0
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Gasoline Crack Spread Swaps [Member]
Assets:
Derivative Asset	(0.3)	0
Derivative liabilities:
Total derivative liabilities	(2.1)	(3.5)
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Diesel Swaps [Member]
Derivative liabilities:
Total derivative liabilities	(0.4)	0
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Diesel Crack Spread Swaps [Member]
Assets:
Derivative Asset	(0.8)	0
Derivative liabilities:
Total derivative liabilities	(5)	(1.4)
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | 2-1-1- Crack Spread Swap [Member]
Derivative liabilities:
Total derivative liabilities	0	(2.5)
Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Inventory Financing Obligations
Derivative liabilities:
Total derivative liabilities	$ (3.8)	$ 0

Fair Value Measurements - Sum65

Fair Value Measurements - Summary of Net Changes in Fair Value of the Company's Level 3 Financial Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Loss on derivative instruments	$ (12)	$ (6.7)	$ (5)	$ 3.4
Unrealized gain (loss) on derivative instruments	(9.7)	(4.9)	2.2	23.5
Level 3 [Member]
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Fair value	$ (11.8)	$ (10.3)	(11.8)	(10.3)	$ (14)	$ (33.9)
Loss on derivative instruments			7.2	20.1
Unrealized gain (loss) on derivative instruments			2.2	23.5
Settlements			(7.2)	(20)
September 30			$ 2.2	$ 23.5

Fair Value Measurements - Sum66

Fair Value Measurements - Summary of the Company's Carrying and Estimated Fair Value of the Company's Financial Instruments, Carried at Adjusted Historical Cost (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Fair Value [Member] | Level 1 [Member]
Financial Instrument:
Senior notes	$ 1,543.9	$ 1,334.1
Fair Value [Member] | Level 2 [Member]
Financial Instrument:
Senior notes	464.1	458.8
Fair Value [Member] | Level 3 [Member]
Financial Instrument:
Debt Instrument, Fair Value Disclosure	51.6	54.5
Fair Value [Member] | Revolving Credit Facility [Member] | Level 3 [Member]
Financial Instrument:
Revolving credit facility	0.1	6
Carrying value [Member] | Level 1 [Member]
Financial Instrument:
Senior notes	1,555.4	1,552.2
Carrying value [Member] | Level 2 [Member]
Financial Instrument:
Senior notes	386.8	384.5
Carrying value [Member] | Level 3 [Member]
Financial Instrument:
Debt Instrument, Fair Value Disclosure	51.6	54.5
Carrying value [Member] | Revolving Credit Facility [Member] | Level 3 [Member]
Financial Instrument:
Revolving credit facility	$ 0.1	$ 6

Employee Benefit Plans - Summar

Employee Benefit Plans - Summary of Components of Net Periodic Pension Cost (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Components of net periodic pension and other post retirement benefits cost
Amortization of net loss	$ 0.1	$ 0	$ 0.1	$ 0.1
Pension Benefits [Member]
Components of net periodic pension and other post retirement benefits cost
Interest cost	0.6	0.6	1.8	1.9
Expected return on assets	(0.7)	(0.8)	(2.3)	(2.4)
Amortization of net loss	0.1	0	0.1	0.1
Net periodic benefit income	$ 0	$ (0.2)	$ (0.4)	$ (0.4)

Employee Benefit Plans - Schedu

Employee Benefit Plans - Schedule of Pension Plan Assets Measured at Fair Value (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	$ 34.4	$ 49.8
Fair Value, Measurements, Recurring [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0.3
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0.3
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0.3
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0.3
Fair Value, Measurements, Recurring [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	6.1	8.6
Fair Value, Measurements, Recurring [Member] | Foreign Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	6.2	8.7
Fair Value, Measurements, Recurring [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	$ 22.1	$ 32.2

Employee Benefit Plans - Narrat

Employee Benefit Plans - Narrative (Details)	9 Months Ended
	Sep. 30, 2017
Domestic Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
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 [Member]
Defined Benefit Plan Disclosure [Line Items]
Investment fund strategies	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.

Accumulated Other Comprehensi70

Accumulated Other Comprehensive Income - Summary of Reclassification Adjustments out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net loss		$ 0.1	$ 0	$ 0.1	$ 0.1
Total		0.1	(4.8)	0.1	(9.1)
Amount Reclassified From Accumulated Other Comprehensive Income [Member] | Derivative gains (losses) reflected in gross profit:
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Sales		0	14.5	0	45.6
Cost of sales		0	(9.7)	0	(36.4)
Total		0	4.8	0	9.2
Amount Reclassified From Accumulated Other Comprehensive Income [Member] | Amortization of defined benefit pension plans:
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net loss	[1]	(0.1)	0	(0.1)	(0.1)
Total		(0.1)	0	(0.1)	(0.1)
Pension Plan [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net loss		$ 0.1	$ 0	$ 0.1	$ 0.1
[1]	This accumulated other comprehensive loss component is included in the computation of net periodic benefit income. See Note 11 for additional details.

Earnings Per Unit - Summary of

Earnings Per Unit - Summary of Computation of Basic and Diluted Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Numerator for basic and diluted earnings per limited partner unit:
Net loss		$ (23.6)	$ (33.4)	$ (20.2)	$ (249)
General partner’s interest in net loss		(0.5)	(0.7)	(0.4)	(5)
Net loss available to limited partners		$ (23.1)	$ (32.7)	$ (19.8)	$ (244)
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average limited partner units outstanding (in shares)		77,632,784	77,331,347	77,537,531	76,767,975
Diluted weighted average limited partner units outstanding (in shares)	[1]	77,632,784	77,331,347	77,537,531	76,767,975
Limited partners' interest basic net loss per unit		$ (0.30)	$ (0.42)	$ (0.25)	$ (3.18)
Limited partners' interest diluted net loss per unit		$ (0.30)	$ (0.42)	$ (0.25)	$ (3.18)
Dilutive phantom units excluded (in shares)		300,000	100,000	300,000	200,000
[1]	Total diluted weighted average limited partner units outstanding excludes 0.3 million for the three and nine months ended September 30, 2017 as compared to the 0.1 million and 0.2 million, respectively, of dilutive phantom units for the three and nine months ended September 30, 2016.

Segments and Related Informat72

Segments and Related Information - Schedule of Reportable Segment Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Sales:
Total sales	$ 1,097.4	$ 966.6	$ 3,065.7	$ 2,652.5
Loss from unconsolidated affiliates	(0.2)	(0.3)	(0.4)	(18.5)
Adjusted EBITDA	95.7	53.9	276	130.5
Reconciling items to net loss:
Depreciation and amortization	55	52.4	151	152.4
Realized gain (loss) on derivatives, not reflected in net income (loss)		(4.8)		(9.2)
Asset Impairment	0	0	0.4	33.4
Loss on sale of unconsolidated affiliate				113.9
Unrealized gain (loss) on derivative instruments	9.7	4.9	(2.2)	(23.5)
Interest expense	47.4	44.6	135.8	117.7
Non-cash equity based compensation	7.3	(2.2)	12.3	1.9
Income tax benefit	(0.1)	(7.6)	(1.1)	(7.1)
Net loss	(23.6)	(33.4)	(20.2)	(249)
External Customers [Member]
Sales:
Total sales	1,097.4	966.6	3,065.7	2,652.5
Intersegment Sales [Member]
Sales:
Total sales	0	0	0	0
Operating Segments [Member] | Specialty Products [Member]
Sales:
Total sales	305.8	315.8	986.3	949.3
Loss from unconsolidated affiliates	(0.1)	(0.2)	(0.1)	(0.2)
Adjusted EBITDA	43	43.4	155.7	160.9
Reconciling items to net loss:
Depreciation and amortization	20.6	18.8	53.5	56
Realized gain (loss) on derivatives, not reflected in net income (loss)		(2.6)		(1.4)
Asset Impairment			0.4	0
Loss on sale of unconsolidated affiliate				0
Operating Segments [Member] | Specialty Products [Member] | External Customers [Member]
Sales:
Total sales	305.8	315.7	986.1	948.8
Operating Segments [Member] | Specialty Products [Member] | Intersegment Sales [Member]
Sales:
Total sales	0	0.1	0.2	0.5
Operating Segments [Member] | Fuel Products [Member]
Sales:
Total sales	735.6	629.3	1,941.4	1,642.1
Loss from unconsolidated affiliates	0	0	0	(18)
Adjusted EBITDA	46.3	13.8	117.1	(13.3)
Reconciling items to net loss:
Depreciation and amortization	30.6	28.8	85.9	82
Realized gain (loss) on derivatives, not reflected in net income (loss)		(2.2)		(7.8)
Asset Impairment			0	33.4
Loss on sale of unconsolidated affiliate				113.9
Operating Segments [Member] | Fuel Products [Member] | External Customers [Member]
Sales:
Total sales	720.7	616.6	1,893.9	1,615.7
Operating Segments [Member] | Fuel Products [Member] | Intersegment Sales [Member]
Sales:
Total sales	14.9	12.7	47.5	26.4
Operating Segments [Member] | Oilfield Services [Member]
Sales:
Total sales	70.9	34.3	185.7	88
Loss from unconsolidated affiliates	(0.1)	(0.1)	(0.3)	(0.3)
Adjusted EBITDA	6.4	(3.3)	3.2	(17.1)
Reconciling items to net loss:
Depreciation and amortization	3.8	4.8	11.6	14.4
Realized gain (loss) on derivatives, not reflected in net income (loss)		0		0
Asset Impairment			0	0
Loss on sale of unconsolidated affiliate				0
Operating Segments [Member] | Oilfield Services [Member] | External Customers [Member]
Sales:
Total sales	70.9	34.3	185.7	88
Operating Segments [Member] | Oilfield Services [Member] | Intersegment Sales [Member]
Sales:
Total sales	0	0	0	0
Operating Segments [Member] | Combined Segments [Member]
Sales:
Total sales	1,112.3	979.4	3,113.4	2,679.4
Loss from unconsolidated affiliates	(0.2)	(0.3)	(0.4)	(18.5)
Adjusted EBITDA	95.7	53.9	276	130.5
Reconciling items to net loss:
Depreciation and amortization	55	52.4	151	152.4
Realized gain (loss) on derivatives, not reflected in net income (loss)		(4.8)		(9.2)
Asset Impairment			0.4	33.4
Loss on sale of unconsolidated affiliate				113.9
Operating Segments [Member] | Combined Segments [Member] | External Customers [Member]
Sales:
Total sales	1,097.4	966.6	3,065.7	2,652.5
Operating Segments [Member] | Combined Segments [Member] | Intersegment Sales [Member]
Sales:
Total sales	14.9	12.8	47.7	26.9
Eliminations [Member]
Sales:
Total sales	(14.9)	(12.8)	(47.7)	(26.9)
Loss from unconsolidated affiliates	0	0	0	0
Adjusted EBITDA	0	0	0	0
Reconciling items to net loss:
Depreciation and amortization	0	0	0	0
Realized gain (loss) on derivatives, not reflected in net income (loss)		0		0
Asset Impairment			0	0
Loss on sale of unconsolidated affiliate				0
Eliminations [Member] | External Customers [Member]
Sales:
Total sales	0	0	0	0
Eliminations [Member] | Intersegment Sales [Member]
Sales:
Total sales	$ (14.9)	$ (12.8)	$ (47.7)	$ (26.9)

Segments and Related Informat73

Segments and Related Information - Schedule of Major Product Category Sales (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Major product category sales
Sales	$ 1,097.4	$ 966.6	$ 3,065.7	$ 2,652.5
Product Concentration Risk [Member]
Major product category sales
Sales	$ 1,097.4	$ 966.6	$ 3,065.7	$ 2,652.5
Sales, percentage	100.00%	100.00%	100.00%	100.00%
Product Concentration Risk [Member] | Specialty Products [Member]
Major product category sales
Sales	$ 305.8	$ 315.7	$ 986.1	$ 948.8
Sales, percentage	27.90%	32.70%	32.20%	35.80%
Product Concentration Risk [Member] | Specialty Products [Member] | Lubricating Oils [Member]
Major product category sales
Sales	$ 148.8	$ 133	$ 453.2	$ 408.5
Sales, percentage	13.60%	13.80%	14.80%	15.40%
Product Concentration Risk [Member] | Specialty Products [Member] | Solvents [Member]
Major product category sales
Sales	$ 62.6	$ 60.6	$ 198.7	$ 177.6
Sales, percentage	5.70%	6.30%	6.50%	6.70%
Product Concentration Risk [Member] | Specialty Products [Member] | Waxes [Member]
Major product category sales
Sales	$ 27.4	$ 33.2	$ 87.4	$ 96.7
Sales, percentage	2.50%	3.40%	2.90%	3.60%
Product Concentration Risk [Member] | Specialty Products [Member] | Packaged and Synthetic Specialty Products [Member]
Major product category sales
Sales	$ 62.8	$ 79.6	$ 224.3	$ 237.1
Sales, percentage	5.70%	8.20%	7.30%	8.90%
Product Concentration Risk [Member] | Specialty Products [Member] | Other [Member]
Major product category sales
Sales	$ 4.2	$ 9.3	$ 22.5	$ 28.9
Sales, percentage	0.40%	1.00%	0.70%	1.20%
Product Concentration Risk [Member] | Fuel Products [Member]
Major product category sales
Sales	$ 720.7	$ 616.6	$ 1,893.9	$ 1,615.7
Sales, percentage	65.60%	63.80%	61.80%	60.90%
Product Concentration Risk [Member] | Fuel Products [Member] | Gasoline [Member]
Major product category sales
Sales	$ 260.5	$ 209.4	$ 736.1	$ 599.6
Sales, percentage	23.70%	21.70%	24.00%	22.60%
Product Concentration Risk [Member] | Fuel Products [Member] | Diesel [Member]
Major product category sales
Sales	$ 241.9	$ 216.7	$ 658.9	$ 594.2
Sales, percentage	22.00%	22.40%	21.50%	22.40%
Product Concentration Risk [Member] | Fuel Products [Member] | Jet fuel [Member]
Major product category sales
Sales	$ 36	$ 32.3	$ 106.4	$ 81.5
Sales, percentage	3.30%	3.30%	3.50%	3.10%
Product Concentration Risk [Member] | Fuel Products [Member] | Asphalt, Heavy Fuel Oils and Other [Member]
Major product category sales
Sales	$ 182.3	$ 158.2	$ 392.5	$ 340.4
Sales, percentage	16.60%	16.40%	12.80%	12.80%
Product Concentration Risk [Member] | Oilfield Services [Member]
Major product category sales
Sales	$ 70.9	$ 34.3	$ 185.7	$ 88
Sales, percentage	6.50%	3.50%	6.00%	3.30%

Segments and Related Informat74

Segments and Related Information - Narrative (Details) - supplier	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Number of customers representing 10% or greater of consolidated sales	0	0	0	0
number of major suppliers	2	2	2	2
Disclosure on Geographic Areas, Description of Revenue from External Customers	0.1	0.1	0.1	0.1
Supplier Concentration Risk [Member]
Segment Reporting Information [Line Items]
Percentage of crude oil supply from 2 suppliers	64.80%	72.90%	65.90%	62.60%

Subsequent Events Subsequent 75

Subsequent Events Subsequent Events (Details) - USD ($) $ in Millions	Nov. 21, 2017	Nov. 08, 2017	Aug. 11, 2017
Subsequent Event [Line Items]
Superior Refinery, Consideration			$ 435
Subsequent Event [Member]
Subsequent Event [Line Items]
Superior Refinery, Consideration	$ 84	$ 492.1
Anchor Drilling, Total Consideration	50
Anchor Drilling, Consideration for Working Capital and other	$ 15
Interest Acquired in Fluid Holding Corp	10.00%