Calumet Specialty Products Partners (CLMT) 10-Q 6 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 06, 2016
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	Mar. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		76,063,679

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 7.2	$ 5.6
Accounts receivable:
Trade	209.1	195.3
Other	22	15.4
Total accounts receivable	231.1	210.7
Inventories	429.9	384.4
Prepaid expenses and other current assets	6.9	8.3
Total current assets	675.1	609
Property, plant and equipment, net	1,727.6	1,719.2
Investment in unconsolidated affiliates	115.8	126
Goodwill	212	212
Other intangible assets, net	206.5	214.1
Other noncurrent assets, net	61.6	64.4
Total assets	2,998.6	2,944.7
Current liabilities:
Accounts payable	288.1	316.6
Accrued interest payable	45.3	31.1
Accrued salaries, wages and benefits	23.7	32.9
Other taxes payable	17.5	17.9
Other current liabilities	143.5	119
Current portion of long-term debt	1.7	1.7
Note payable - related party	72.4	73.5
Derivative liabilities	29.3	33.9
Total current liabilities	621.5	626.6
Noncurrent deferred income taxes	2.1	2.1
Pension and postretirement benefit obligations	12.5	13
Other long-term liabilities	0.9	0.9
Long-term debt, less current portion	1,883.1	1,698.2
Total liabilities	2,520.1	2,340.8
Partners’ capital:
Limited partners’ interest 75,884,400 units and 75,884,400 units, issued and outstanding as of March 31, 2016 and December 31, 2015, respectively	461.4	578
General partner’s interest	20.8	27.5
Accumulated other comprehensive loss	(3.7)	(1.6)
Total partners’ capital	478.5	603.9
Total liabilities and partners’ capital	$ 2,998.6	$ 2,944.7

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - Limited Partner [Member] - shares	Mar. 31, 2016	Dec. 31, 2015
Limited partners’ interest units issued (in shares)	75,884,400	75,884,400
Limited partners’ interest units outstanding (in shares)	75,884,400	75,884,400

Unaudited Condensed Consolidate

Unaudited Condensed Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Sales		$ 713	$ 1,018.6
Cost of sales		(626.8)	(823.4)
Gross profit		86.2	195.2
Operating costs and expenses:
Selling		30.5	38.4
General and administrative		27.6	39.2
Transportation		39.2	42
Taxes other than income taxes		5.7	4
Other		2	2.9
Operating income (loss)		(18.8)	68.7
Other income (expense):
Interest expense		(30.3)	(27)
Realized gain (loss) on derivative instruments		(12.3)	8.9
Unrealized gain (loss) on derivative instruments		4.6	(27.9)
Loss from unconsolidated affiliates		(11.1)	(4.5)
Other		0.4	0.8
Total other expense		(48.7)	(49.7)
Net income (loss) before income taxes		(67.5)	19
Income tax expense (benefit)		0.2	(4.8)
Net income (loss)		(67.7)	23.8
Allocation of net income (loss):
Net income (loss)		(67.7)	23.8
Less:
General partner’s interest in net income (loss)		(1.4)	0.5
General partner’s incentive distribution rights		0	4.2
Net income (loss) available to limited partners		$ (66.3)	$ 19.1
Weighted average limited partner units outstanding:
Basic (in shares)		76,449,841	71,232,392
Diluted (in shares)	[1]	76,449,841	71,275,452
Limited partners' interest basic net income (loss) per unit		$ (0.87)	$ 0.27
Limited partners' interest diluted net loss per unit		(0.87)	0.27
Cash distributions declared per limited partner unit (in USD per share)		$ 0.685	$ 0.685
[1]	Total diluted weighted average limited partner units outstanding excludes less than 0.1 million of dilutive phantom units for the three months ended March 31, 2016.

Unaudited Condensed Consolidat5

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (67.7)	$ 23.8
Cash flow hedges:
Cash flow hedge (gain) loss reclassified to net income (loss)	(2.1)	1.7
Change in fair value of cash flow hedges	0	(5.1)
Defined benefit pension and retiree health benefit plans	0	0.2
Foreign currency translation adjustment	0	(0.3)
Total other comprehensive loss	(2.1)	(3.5)
Comprehensive income (loss) attributable to partners’ capital	$ (69.8)	$ 20.3

Unaudited Condensed Consolidat6

Unaudited Condensed Consolidated Statements of Partners' Capital - 3 months ended Mar. 31, 2016 - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income [Member]	General Partner [Member]	Limited Partner [Member]
Beginning Balance at Dec. 31, 2015	$ 603.9	$ (1.6)	$ 27.5	$ 578
Other comprehensive loss	(2.1)	(2.1)	0	0
Net loss	(67.7)	0	(1.4)	(66.3)
Amortization of vested phantom units	1.8	0	0	1.8
Distributions to partners	(57.4)	0	(5.3)	(52.1)
Ending Balance at Mar. 31, 2016	$ 478.5	$ (3.7)	$ 20.8	$ 461.4

Unaudited Condensed Consolidat7

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating activities
Net income (loss)	$ (67.7)	$ 23.8
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	38.8	35.4
Amortization of turnaround costs	9.1	6.1
Non-cash interest expense	1.9	1.4
Provision for doubtful accounts	0.3	0
Unrealized (gain) loss on derivative instruments	(4.6)	27.9
Gain (Loss) on Disposition of Assets	0.8	0.3
Non-cash equity based compensation	1.8	3.2
Deferred income tax benefit	0	(4.8)
Inventory Write-down	(8.1)	13.2
Losses from unconsolidated affiliates	(11.1)	(4.5)
Other non-cash activities	1.2	1.3
Changes in assets and liabilities:
Accounts receivable	(20.7)	29.2
Inventories	(36)	(18.9)
Prepaid expenses and other current assets	0	4.4
Derivative activity	(3.6)	9.2
Turnaround costs	(6.4)	(2.7)
Increase (Decrease) in Other Operating Assets	0.3	0
Accounts payable	(1.8)	(78.9)
Accrued interest payable	14.2	0.7
Accrued salaries, wages and benefits	(9.2)	(1.9)
Other taxes payable	(0.4)	(2)
Other liabilities	24	38.2
Pension and postretirement benefit obligations	(0.5)	(0.2)
Net cash provided by (used in) operating activities	(56.1)	89.4
Investing activities
Additions to property, plant and equipment	(66.8)	(74.1)
Investment in unconsolidated affiliates	(0.9)	(25)
Proceeds from sale of property, plant and equipment	0	0.1
Net cash used in investing activities	(67.7)	(99)
Financing activities
Proceeds from borrowings — revolving credit facility	393.9	358.8
Repayments of borrowings — revolving credit facility	(210)	(509.5)
Repayments of Related Party Debt	(1.5)	0
Payments on capital lease obligations	(2)	(1.7)
Proceeds from other financing activities	2.4	0
Proceeds from senior notes offering	0	322.6
Payments of Debt Issuance Costs	0	5.6
Proceeds from public offerings of common units, net	0	161.7
Contributions from Calumet GP, LLC	0	3.5
Common units repurchased and taxes paid for phantom unit grants	0	(3.2)
Distributions to partners	(57.4)	(52.7)
Net cash provided by financing activities	125.4	273.9
Net increase in cash and cash equivalents	1.6	264.3
Cash and cash equivalents at beginning of period	5.6	8.5
Cash and cash equivalents at end of period	7.2	272.8
Supplemental disclosure of non-cash financing and investing activities
Non-cash property, plant and equipment additions	$ 29.3	$ 47.2

Description of the Business

Description of the Business	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 , the Company had 75,884,400 limited partner common units and 1,548,660 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses. The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums 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 March 31, 2016 , and for the three months ended March 31, 2016 and 2015 , 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. 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 months ended March 31, 2016 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 . These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2015 Annual Report.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Reclassifications Certain amounts in the prior years’ condensed consolidated financial statements have been reclassified to conform to the current year presentation. New Accounting Pronouncements In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation — Stock Compensation (Topic 606): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. Under the new standard, income tax benefits and deficiencies are to be recognized as income tax expense or benefit in the income statement and the tax effects of exercised or vested awards should be treated as discrete items in the reporting period in which they occur. Excess tax benefits should be classified along with other income tax cash flows as an operating activity. In regards to forfeitures, the entity may make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-07, Investments — Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting (“ASU 2016-07”), which eliminates the retroactive adjustments to an investment upon it qualifying for the equity method of accounting as a result of an increase in the level of ownership interest or degree of influence by the investor. ASU 2016-07 requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment qualifies for equity method accounting. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments (“ASU 2016-06”). ASU 2016-06 simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The adoption of ASU 2016-06 is not expected to have an impact on the Company’s condensed consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (“ASU 2016-05”) . ASU 2016-05 clarifies that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument under Topic 815 does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. An entity can elect to adopt the amendments of ASU 2016-05 on either a prospective or modified retrospective basis. The adoption of ASU 2016-05 is not expected to have an impact on the Company’s 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 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 effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The Company is currently evaluating the impact of this standard on its 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 ASC 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. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 was originally effective for fiscal years (including interim periods) beginning after December 15, 2016. 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 effective date by one year, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606) — Principal versus Agent Considerations (“ASU 2016-08”). ASU 2016-08 provides clarifying guidance regarding the application of ASU 2014-09 when another party, along with the reporting entity, is involved in providing a good or a service to a customer. In these circumstances, an entity is required to determine whether the nature of its promise is to provide that good or service to the customer (that is, the entity is a principal) or to arrange for the good or service to be provided to the customer by the other party (that is, the entity is an agent). ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606) — Identifying Performance Obligations and Licensing (“ASU 2016-10”). ASU 2016-10 further amends the guidance with respect to certain implementation issues on identifying performance obligations and accounting for licenses of intellectual property. The new revenue standard permits companies to either apply the requirements retrospectively to all prior periods presented or apply the requirements in the year of adoption through a cumulative adjustment. The amendments in these standards, along with ASU 2014-09, are effective for fiscal years (including interim periods) beginning after December 15, 2017. The Company is currently evaluating the impact of these standards on its condensed consolidated financial statements.

Inventories

Inventories	3 Months Ended
	Mar. 31, 2016
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 $69.3 million and $41.0 million lower as of March 31, 2016 , and December 31, 2015 , respectively. Inventories consist of the following (in millions): March 31, 2016 December 31, 2015 Raw materials $ 51.6 $ 47.9 Work in process 72.7 64.0 Finished goods 305.6 272.5 $ 429.9 $ 384.4 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 March 31, 2016 and 2015 , the Company recorded $8.1 million of gains and $13.2 million of losses, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market (“LCM”) valuation.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 , and December 31, 2015 (in millions): Three Months Ended March 31, 2016 Year Ended December 31, 2015 Investment Percent Ownership Investment Percent Ownership Dakota Prairie Refining, LLC $ 113.7 50 % $ 124.7 50 % Other 2.1 1.3 Total $ 115.8 $ 126.0 Dakota Prairie Refining, LLC On February 7, 2013 , the Company entered into a joint venture agreement with MDU Resources Group, Inc. (“MDU”) to develop, build and operate a diesel refinery in southwestern North Dakota. The joint venture is named Dakota Prairie Refining, LLC (“Dakota Prairie”). The capitalization of the construction cost was funded through cash contributions from MDU, cash contributions from the Company and proceeds of $75.0 million from a syndicated term loan facility with the joint venture as the borrower, which is expected to be repaid by the Company through its allocation of profits from the joint venture. The term loan facility was funded in April 2013. In addition to the $300.0 million commitment outlined in the joint venture agreement, MDU and the Company made additional cash contributions, net of distributions, in the amount of $80.6 million and $88.7 million , respectively, to fund construction costs and working capital needs. Additionally, MDU or the Company may make cash contributions or loans to fund working capital needs. The joint venture allocates profits on a 50% /50% basis to the Company and MDU, except for the adjustments made to the Company’s share for repayment of the principal and interest of the $75.0 million term loan as noted above. The joint venture is governed by a board of managers comprised of representatives from both the Company and MDU. MDU is providing natural gas and electricity utility services to the joint venture. The Company is providing refinery operations, crude oil procurement and refined product marketing expertise to the joint venture. Dakota Prairie commenced sales of finished products in May 2015. The following represents summary financial information for Dakota Prairie, presented at 100% (in millions): Three Months Ended March 31, 2016 2015 Operating revenue $ 45.1 $ 1.7 Operating loss $ (20.8 ) $ (7.0 ) Net loss $ (21.6 ) $ (7.1 )

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2016
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, which activities are subject to stringent federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects, and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures. Remediation of subsurface contamination is in process at certain of the Company’s refinery sites and is being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the soil and groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. San Antonio Refinery In connection with the 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. Montana Refinery In connection with the acquisition of the Montana refinery from Connacher Oil and Gas Limited (“Connacher”), the Company became a party to an existing 2002 Refinery Initiative Consent Decree (the “Montana Consent Decree”) with the EPA and the Montana Department of Environmental Quality (the “MDEQ”). The material obligations imposed by the Montana Consent Decree have been completed. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previously held hazardous waste permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Montana refinery. The Company believes the majority of damages related to such contamination at the Montana refinery are covered by a contractual indemnity provided by HollyFrontier Corporation (“Holly”), the owner and operator of the Montana refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Montana refinery. Under this asset purchase agreement, Holly agreed to indemnify Connacher and Montana Refining Company, Inc., subject to timely notification, certain conditions and certain monetary baskets and caps, for environmental conditions arising under Holly’s ownership and operation of the Montana refinery and existing as of the date of sale to Connacher. During 2014, Holly provided the Company a notice challenging the Company’s position that Holly is obligated to indemnify the Company’s remediation expenses for environmental conditions to the extent arising under Holly’s ownership and operation of the refinery and existing as of the date of sale to Connacher, which expenses totaled approximately $18.2 million as of March 31, 2016 , of which $14.6 million was capitalized into the cost of the Company’s recently completed expansion project and $3.6 million was expensed. The Company continues to believe that Holly is responsible to indemnify the Company for these remediation expenses disputed by Holly, and on September 22, 2015, the Company initiated a lawsuit against Holly and the sellers of the Montana refinery under the asset purchase agreement. On November 24, 2015, Holly and the sellers of the Montana refinery under the asset purchase agreement filed a motion to dismiss the case pending arbitration. On February 10, 2016, the court granted Holly’s motion to dismiss the case and ordered that all of the claims be addressed in arbitration. In the event the Company is unsuccessful, the Company will be responsible for those remediation expenses. The Company expects that it may incur some costs to remediate other environmental conditions at the Montana refinery; however, the Company believes at this time that these other costs it may incur will not be material to its financial position or results of operations. Superior Refinery In connection with the acquisition of the Superior refinery, the Company became a party to an existing Refinery Initiative Consent Decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to its Superior refinery. Under the Superior Consent Decree, the Company must complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the refinery to the EPA and the WDNR. The Company estimates costs of up to $4.0 million as of March 31, 2016 , to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform these required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be material. The Company is currently assessing certain past actions at the refinery for compliance with the terms of the Superior Consent Decree, which actions may be subject to stipulated penalties under the Superior Consent Decree but, in any event, the Company does not currently believe that the imposition of such penalties for those actions, should they be imposed, would be material. In addition, the Company is pursuing certain additional environmental and safety-related projects at the Superior refinery. Completion of these additional projects will result in the Company incurring additional costs, which could be substantial. For the three months ended March 31, 2016 , the Company incurred no costs related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations. For the three months ended March 31, 2015 , the Company incurred approximately $0.3 million of costs related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations. On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery, which included a proposed penalty amount of $0.1 million . This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and is in settlement discussions with the EPA to resolve this issue. The Company has not yet received formal action from the EPA. The Company does not believe that the resolution of these allegations will have a material adverse effect on the Company’s financial position or results of operations. The Company is contractually indemnified by Murphy Oil Corporation (“Murphy Oil”) under an asset purchase agreement between the Company and Murphy Oil for specified environmental liabilities arising from the operation of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or otherwise discharged by Murphy Oil. The Company believes contractual indemnity by Murphy Oil for such specified environmental liabilities is unlimited in duration and not subject to any monetary deductibles or maximums. The amount of any damages payable by Murphy Oil pursuant to the contractual indemnities under the asset purchase agreement are net of any amount recoverable under an environmental insurance policy that the Company obtained in connection with the 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 acquisition of the Superior refinery. Shreveport, Cotton Valley and Princeton Refineries On December 23, 2010 , the Company entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012 . The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations that arose prior to December 23, 2010 . Among other things, the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During the three months ended March 31, 2016 and 2015 , the Company incurred approximately $0.4 million and $1.0 million , respectively, of such expenditures and estimates additional expenditures of approximately $3.0 million to $5.0 million of capital expenditures and expenditures related to additional personnel and environmental studies through 2016 as a result of the implementation of these requirements. These capital investment requirements will be incorporated into the Company’s annual capital expenditures budget and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the Global Settlement to have a material adverse effect on the Company’s financial position or results of operations. The Company is contractually indemnified by Shell Oil Company (“Shell”), as successor to Pennzoil-Quaker State Company, and Atlas Processing Company, under an asset purchase agreement between the Company and Shell, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The Company believes the contractual indemnity is unlimited in amount and duration, but requires the Company to contribute $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities. Bel-Ray Facility Bel-Ray executed an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection, effective January 4, 1994, which required investigation and remediation of contamination at or emanating from the Bel-Ray facility. In 2000, Bel-Ray entered into a fixed price remediation contract with Weston Solutions (“Weston”), a large remediation contractor, whereby Weston agreed to be fully liable for the remediation of the soil and groundwater issues at the facility, including an offsite groundwater plume pursuant to the ACO (“Weston Agreement”). The Weston Agreement set up a trust fund to reimburse Weston, administered by Bel-Ray’s environmental counsel. As of March 31, 2016 , the trust fund contained approximately $0.8 million . In addition, Weston has remediation cost containment insurance, should Weston be unable to complete the work required under the Weston Agreement. In connection with the 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. Occupational Health and Safety The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges. The Company has completed studies to assess the adequacy of its PSM practices at its Shreveport refinery with respect to certain consensus codes and standards. During the three months ended March 31, 2016 and 2015 , the Company incurred $0.3 million and $0.1 million , respectively, of related capital expenditures and expects to incur up to $1.0 million during 2016 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards. In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program. On March 14, 2011 , OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $0.2 million . The Company has contested the Cotton Valley Citation and the parties have reached a tentative settlement with OSHA on the matter, which the Company does not believe will have a material adverse effect on its financial position or results of operations. Labor Matters The Company has employees covered by various collective bargaining agreements. The Company’s Cotton Valley facility collective bargaining agreement was ratified on April 1, 2016, and will expire on March 31, 2019. The Dickinson facility collective bargaining agreement was ratified on April 1, 2016, and will expire on March 31, 2019. The Shreveport refinery collective bargaining agreement was extended until a new agreement is reached or is voided by either party with a 30-day written notice. The Missouri esters facility collective bargaining agreement was extended until a new agreement is reached or is voided by either party with a 30-day written notice. 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 condensed consolidated financial statements but are not, individually or in the aggregate, considered material. For other matters, the Company has not recorded accruals because it has not yet determined that a loss is probable or because the amount of loss cannot be reasonably estimated. While the ultimate outcome of claims and litigation currently pending cannot be determined, the Company currently does not expect that these proceedings and claims, individually or in the aggregate, will have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any litigation is inherently uncertain, however, and if decided adversely to the Company, or if the Company determines that settlement of particular litigation is appropriate, the Company may be subject to liability that could have a material adverse effect on its financial position, results of operations or cash flows. Standby Letters of Credit The Company has agreements with various financial institutions for standby letters of credit which have been issued primarily to vendors and for the benefit of Dakota Prairie to support its revolving credit facility. As of March 31, 2016 , and December 31, 2015 , the Company had outstanding standby letters of credit of $63.5 million and $66.8 million , respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 6 for additional information regarding the Company’s revolving credit facility. At March 31, 2016 , and December 31, 2015 , the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $600.0 million , which amount may be increased to 90% of revolver commitments in effect ( $1.0 billion at March 31, 2016 , and December 31, 2015 ) with the consent of the Agent (as defined below). As of March 31, 2016 , and December 31, 2015 , the Company had availability to issue letters of credit of $101.3 million and $233.5 million , respectively, under its revolving credit facility.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consisted of the following (in millions): March 31, 2016 December 31, 2015 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 3.3% at March 31, 2016 $ 294.9 $ 111.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for the three months ended March 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 three months ended March 31, 2016 (1) 352.8 352.9 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 three months ended March 31, 2016 325.0 325.0 Related party note payable, interest at a fixed rate of 6.0% on a portion of the note, interest payments at various dates, borrowings due July 2016, weighted average interest rate of 6.0% for the three months ended March 31, 2016 72.4 73.5 Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034 46.1 46.4 Less unamortized debt issuance costs (2) (27.7 ) (28.9 ) Less unamortized discounts (6.3 ) (6.5 ) Total long-term debt 1,957.2 1,773.4 Less current portion of note payable — related party 72.4 73.5 Less current portion of long-term debt 1.7 1.7 $ 1,883.1 $ 1,698.2 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.8 million and $2.9 million as of March 31, 2016 , and December 31, 2015 , respectively (refer to Note 7 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 $9.4 million and $8.1 million at March 31, 2016 , and December 31, 2015 , respectively. Senior Notes 7.75% Senior Notes (the “2023 Notes”) On March 27, 2015 , the Company issued and sold $325.0 million in aggregate principal amount of 7.75% Senior Notes due April 15, 2023 , in a private placement pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 99.257 percent of par. The 2023 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S under the Securities Act. The Company received net proceeds of approximately $317.0 million net of discount, initial purchasers’ fees and expenses, which the Company used to fund the redemption of $178.8 million in aggregate principal amount of outstanding 9.625% senior notes due 2020 on April 28, 2015, to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at the Company’s facilities and working capital. Interest on the 2023 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2015. On March 27, 2015, in connection with the issuance and sale of the 2023 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2023 Notes obligating the Company to use reasonable best efforts to file an exchange offer registration statement with the SEC, so that holders of the 2023 Notes can offer to exchange the 2023 Notes for registered notes having substantially the same terms as the 2023 Notes and evidencing the same indebtedness as the 2023 Notes. On December 11, 2015, the Company filed an exchange offer registration statement for the 2023 Notes with the SEC, which was declared effective on January 28, 2016. The exchange offer was completed on March 7, 2016, thereby fulfilling all of the requirements of the 2023 Notes registration rights agreement. 6.50% Senior Notes (the “2021 Notes”) On March 31, 2014 , the Company issued and sold $900.0 million in aggregate principal amount of 6.50% Senior Notes due April 15, 2021 , in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at par. The Company received net proceeds of approximately $884.0 million net of initial purchasers’ fees and expenses, which the Company used to fund the purchase price of ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc. (subsequently converted to ADF Holdings, LLC and Anchor Drilling Fluids USA, LLC), the redemption of $500.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019 (the “2019 Notes”) and for general partnership purposes, including planned capital expenditures at the Company’s facilities. Interest on the 2021 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2014. 7.625% Senior Notes (the “2022 Notes”) On November 26, 2013 , the Company issued and sold $350.0 million in aggregate principal amount of 7.625% Senior Notes due January 15, 2022 , in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 98.494 percent of par. The Company received net proceeds of approximately $337.4 million , net of discount, initial purchasers’ fees and expenses, which the Company used for general partnership purposes, to fund previously announced organic growth projects, the purchase price of the Bel-Ray acquisition and the redemption of $100.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019. Interest on the 2022 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2014. 2021 Notes, 2022 Notes and 2023 Notes In accordance with SEC Rule 3-10 of Regulation S-X, condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of the Company’s “minor” subsidiaries (as defined by Rule 3-10 of Regulation S-X), including Calumet Finance Corp. (100%-owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2021, 2022 and 2023 Notes). There are no significant restrictions on the ability of the Company or subsidiary guarantors for the Company to obtain funds from its subsidiary guarantors by dividend or loan. None of the subsidiary guarantors’ assets represent restricted assets pursuant to SEC Rule 4-08(e)(3) of Regulation S-X. The 2021, 2022 and 2023 Notes are subject to certain automatic customary releases, including the sale, disposition, or transfer of capital stock or substantially all of the assets of a subsidiary guarantor, designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture, exercise of legal defeasance option or covenant defeasance option, liquidation or dissolution of the subsidiary guarantor and a subsidiary guarantor ceases to both guarantee other Company debt and to be an obligor under the revolving credit facility. The Company’s operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the 2021, 2022 and 2023 Notes. The indentures governing the 2021, 2022 and 2023 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2021, 2022 and 2023 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or S&P Global Ratings (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of March 31, 2016 , the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 1.0 to 1.0. As of March 31, 2016 , the Company was in compliance with all covenants under the indentures governing the 2021, 2022 and 2023 Notes. Second Amended and Restated Senior Secured Revolving Credit Facility The Company has a $1.0 billion senior secured revolving credit facility, subject to borrowing base limitations, which includes a $500.0 million incremental uncommitted expansion feature. The revolving credit facility is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in July 2019 and currently bears interest at a rate equal to 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 March 31, 2016 , the margin was 75 basis points for prime rate loans and 175 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 during the preceding fiscal quarter. In addition to paying interest quarterly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.250% or 0.375% per annum, depending on the average daily available unused borrowing capacity for the preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees. The borrowing capacity as of March 31, 2016 , under the revolving credit facility was $459.7 million . As of March 31, 2016 , the Company had $294.9 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $63.5 million , leaving $101.3 million available for additional borrowings based on specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s accounts receivable, inventory and substantially all of its cash (collectively, the “Credit Agreement Collateral”). 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 March 31, 2016 , the Company was in compliance with all covenants under the revolving credit facility. Maturities of Long-Term Debt As of March 31, 2016 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2016 $ 74.7 2017 1.6 2018 1.5 2019 296.2 2020 0.9 Thereafter 1,614.5 Total $ 1,989.4

Derivatives

Derivatives	3 Months Ended
	Mar. 31, 2016
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 NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”). The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in 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 recognizes all derivative instruments at their fair values (see Note 8 ) 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 Company’s financial results are subject to the possibility that changes in a derivative’s fair value could result in significant ineffectiveness and potentially no longer qualify portions or all of its derivative instruments for hedge accounting. The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s condensed consolidated balance sheets as of March 31, 2016 , and December 31, 2015 (in millions): March 31, 2016 December 31, 2015 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: Fuel products segment: Crude oil swaps $ 3.8 $ (3.8 ) $ — $ — $ — $ — Crude oil basis swaps 1.0 (1.0 ) — 0.4 (0.4 ) — Crude oil percentage basis swaps 0.1 (0.1 ) — 0.2 (0.2 ) — Crude oil options 0.6 (0.6 ) — 0.8 (0.8 ) — Total derivative instruments not designated as hedges 5.5 (5.5 ) — 1.4 (1.4 ) — Total derivative instruments $ 5.5 $ (5.5 ) $ — $ 1.4 $ (1.4 ) $ — 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 March 31, 2016 , and December 31, 2015 (in millions): March 31, 2016 December 31, 2015 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 $ (13.0 ) $ — $ (13.0 ) $ (14.9 ) $ — $ (14.9 ) Natural gas collars (0.7 ) — (0.7 ) (0.9 ) — (0.9 ) Fuel products segment: Crude oil swaps (7.5 ) 3.8 (3.7 ) (5.2 ) — (5.2 ) Crude oil basis swaps (4.1 ) 1.0 (3.1 ) (0.7 ) 0.4 (0.3 ) Crude oil percentage basis swaps (6.5 ) 0.1 (6.4 ) (6.9 ) 0.2 (6.7 ) Crude oil options (1.5 ) 0.6 (0.9 ) (1.1 ) 0.8 (0.3 ) Gasoline crack spread swaps — — — (4.3 ) — (4.3 ) Natural gas swaps (1.5 ) — (1.5 ) (1.3 ) — (1.3 ) Total derivative instruments not designated as hedges (34.8 ) 5.5 (29.3 ) (35.3 ) 1.4 (33.9 ) Total derivative instruments $ (34.8 ) $ 5.5 $ (29.3 ) $ (35.3 ) $ 1.4 $ (33.9 ) 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 March 31, 2016 , the Company had no counterparties in which the derivatives held were net assets. As of December 31, 2015 , the Company had no counterparties in which the derivatives held were net assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least 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 March 31, 2016 , or December 31, 2015 . The Company’s contracts with these counterparties allow for netting of derivative instruments executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities. As of March 31, 2016 , and December 31, 2015 , the Company had provided its counterparties with no collateral. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability. Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. The majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business. The cash flow impact of the Company’s derivative activities is classified primarily as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows. Derivative Instruments Designated as Cash Flow Hedges The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel swaps as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases are recorded to sales and cost of sales, respectively, in the 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 unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously deferred in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments 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 income (loss) and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended March 31, 2016 and 2015 , 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 Income (Loss) (Effective Portion) Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion) Three Months Ended Location of Gain (Loss) Three Months Ended Location of Gain (Loss) Three Months Ended March 31, March 31, March 31, 2016 2015 2016 2015 2016 2015 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ (0.7 ) $ (0.4 ) Unrealized/ Realized $ — $ — Fuel products segment: Crude oil swaps (1.3 ) (6.3 ) Cost of sales (13.2 ) (21.5 ) Unrealized/ Realized — (0.2 ) Gasoline swaps — 0.8 Sales — 14.0 Unrealized/ Realized — 0.7 Diesel swaps 1.3 0.1 Sales 16.0 4.8 Unrealized/ Realized — — Jet fuel swaps — 0.3 Sales — 1.4 Unrealized/ Realized — — Total $ — $ (5.1 ) $ 2.1 $ (1.7 ) $ — $ 0.5 The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was gains of $4.3 million and $6.4 million as of March 31, 2016 , and December 31, 2015 , respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive income (loss) at March 31, 2016 , will be reclassified to earnings by December 31, 2016, with balances being recognized as follows (in millions): Year Accumulated Other Comprehensive Income 2016 $ 4.3 Total $ 4.3 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 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 gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 , related to its derivative instrument designated as a fair value hedge (in millions): Location of Loss of Derivative Amount of Loss Recognized in Net Income (Loss) Hedged Item Location of Gain on Hedged Item Amount of Gain Recognized in Net Income (Loss) Three Months Ended March 31, Three Months Ended March 31, 2016 2015 2016 2015 Swaps not allocated to a specific segment: Interest rate swap Interest expense $ 0.1 $ 0.2 2022 Notes Interest income $ — $ — Total $ 0.1 $ 0.2 $ — $ — Derivative Instruments Not Designated as Hedges For derivative instruments not designated as hedges, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. The Company has entered into crude oil basis swaps that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract. Additionally, the Company has entered into diesel crack spread collars, gasoline crack spread collars, natural gas collars, and certain other crude oil swaps, diesel swaps, gasoline swaps, natural gas swaps and platinum swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and gasoline and diesel sales at the Company’s Superior refinery. The amount reclassified from accumulated other comprehensive loss into earnings, as a result of the discontinuance of cash flow hedge accounting for certain crude oil, gasoline, jet fuel and diesel derivative instruments at the Shreveport refinery because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, caused the Company to recognize the following gains in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 (in millions): Three Months Ended March 31, 2016 2015 Realized gain on derivative instruments $ — $ 1.2 The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 , related to its derivative instruments not designated as hedges (in millions): Type of Derivative Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments Three Months Ended March 31, Three Months Ended March 31, 2016 2015 2016 2015 Specialty products segment: Natural gas swaps $ (3.7 ) $ (2.1 ) $ 2.0 $ (3.2 ) Platinum swaps — — — (0.1 ) Fuel products segment: Crude oil swaps (0.9 ) (48.3 ) 1.5 50.2 Crude oil basis swaps — 1.0 (2.6 ) (0.4 ) Crude oil percentage basis swaps (3.9 ) — 0.2 — Crude oil options — — (0.6 ) — Crude oil futures (2.0 ) — — — Gasoline swaps — (2.0 ) — (1.1 ) Gasoline crack spread swaps (1.2 ) (0.8 ) 4.3 (1.5 ) Diesel swaps — 58.0 — (63.4 ) Diesel crack spread swaps — 0.9 — (6.4 ) Jet fuel swaps — 1.6 — (1.6 ) Natural gas swaps (0.6 ) — (0.2 ) (0.3 ) Total $ (12.3 ) $ 8.3 $ 4.6 $ (27.8 ) Derivative Positions — Specialty Products Segment Natural Gas Swap Contracts At March 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 Second Quarter 2016 1,380,000 $ 4.26 Third Quarter 2016 1,380,000 $ 4.26 Fourth Quarter 2016 1,540,000 $ 4.14 Calendar Year 2017 4,950,000 $ 3.85 Total 9,250,000 Average price $ 4.02 At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 1,580,000 $ 4.24 Second Quarter 2016 1,380,000 $ 4.26 Third Quarter 2016 1,380,000 $ 4.26 Fourth Quarter 2016 1,540,000 $ 4.14 Calendar Year 2017 4,950,000 $ 3.85 Total 10,830,000 Average price $ 4.05 Natural Gas Collars At March 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 Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) Second Quarter 2016 180,000 $ 4.25 $ 3.89 Third Quarter 2016 180,000 $ 4.25 $ 3.89 Fourth Quarter 2016 60,000 $ 4.25 $ 3.89 Total 420,000 Average price $ 4.25 $ 3.89 At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2016 180,000 $ 4.25 $ 3.89 Second Quarter 2016 180,000 $ 4.25 $ 3.89 Third Quarter 2016 180,000 $ 4.25 $ 3.89 Fourth Quarter 2016 60,000 $ 4.25 $ 3.89 Total 600,000 Average price $ 4.25 $ 3.89 Derivative Positions — Fuel Products Segment Crude Oil Swap Contracts At March 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 Second Quarter 2016 54,120 595 $ 39.32 Third Quarter 2016 398,893 4,336 $ 39.52 Fourth Quarter 2016 398,893 4,336 $ 39.52 Calendar Year 2017 1,297,976 3,556 $ 48.87 Total 2,149,882 Average price $ 45.16 At March 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 Calendar Year 2017 528,520 1,448 $ 41.56 Total 528,520 Average price $ 41.56 At December 31, 2015 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2016 29,120 320 $ 44.06 Second Quarter 2016 29,120 320 $ 44.06 Third Quarter 2016 29,440 320 $ 44.06 Fourth Quarter 2016 29,440 320 $ 44.06 Calendar Year 2017 630,720 1,728 $ 54.94 Total 747,840 Average price $ 53.24 Crude Oil Basis Swap Contracts The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between LLS and NYMEX WTI. At March 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 Second Quarter 2016 365,000 5,000 $ 1.80 Third Quarter 2016 460,000 5,000 $ 1.80 Fourth Quarter 2016 460,000 5,000 $ 1.80 Total 1,285,000 Average differential $ 1.80 At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 182,000 2,000 $ 2.40 Second Quarter 2016 182,000 2,000 $ 2.40 Third Quarter 2016 184,000 2,000 $ 2.40 Fourth Quarter 2016 184,000 2,000 $ 2.40 Total 732,000 Average differential $ 2.40 The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At March 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 Second Quarter 2016 697,000 7,659 $ (14.02 ) Third Quarter 2016 1,196,000 13,000 $ (13.18 ) Fourth Quarter 2016 1,196,000 13,000 $ (13.18 ) Calendar Year 2017 2,555,000 7,000 $ (13.22 ) Total 5,644,000 Average differential $ (13.31 ) At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 91,000 1,000 $ (14.10 ) Second Quarter 2016 91,000 1,000 $ (14.10 ) Third Quarter 2016 92,000 1,000 $ (14.10 ) Fourth Quarter 2016 92,000 1,000 $ (14.10 ) Calendar Year 2017 365,000 1,000 $ (13.70 ) Total 731,000 Average differential $ (13.90 ) Crude Oil Percentage Basis Swap Contracts The Company has entered into derivative instruments to secure a percentage differential on WCS crude oil to NYMEX WTI. At March 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 Second Quarter 2016 728,000 8,000 73.5 % Third Quarter 2016 736,000 8,000 73.5 % Fourth Quarter 2016 736,000 8,000 73.5 % Calendar Year 2017 1,095,000 3,000 72.3 % Total 3,295,000 Average percentage 73.1 % At December 31, 2015 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI First Quarter 2016 728,000 8,000 73.5 % Second Quarter 2016 728,000 8,000 73.5 % Third Quarter 2016 736,000 8,000 73.5 % Fourth Quarter 2016 736,000 8,000 73.5 % Calendar Year 2017 730,000 2,000 73.0 % Total 3,658,000 Average percentage 73.4 % Crude Oil Option Contracts The Company has entered into derivative instruments to mitigate the risk of future changes in the price of NYMEX WTI crude oil. At March 31, 2016 , the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Call ($/Bbl) Fourth Quarter 2016 350,000 11,290 $ 55.00 Total 350,000 Average price $ 55.00 At March 31, 2016 , the Company had the following derivatives related to crude oil call option sales in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Sold BPD Average Sold Call ($/Bbl) Second Quarter 2016 300,000 9,677 $ 41.78 Total 300,000 Average price $ 41.78 At March 31, 2016 , the Company had the following derivatives related to crude oil put option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Put ($/Bbl) Second Quarter 2016 300,000 9,677 $ 32.58 Total 300,000 Average price $ 32.58 At December 31, 2015 , the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Call ($/Bbl) Fourth Quarter 2016 350,000 11,290 $ 55.00 Total 350,000 Average price $ 55.00 Gasoline Crack Spread Swap Contracts At December 31, 2015 , the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges: Gasoline Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2016 873,000 9,593 $ 8.98 Total 873,000 Average price $ 8.98 Natural Gas Swap Contracts At March 31, 2016 , the Company had the following derivatives related to natural gas purchases in its fuel products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu Second Quarter 2016 603,000 $ 2.99 Third Quarter 2016 606,000 $ 3.03 Fourth Quarter 2016 790,000 $ 3.02 Total 1,999,000 Average price $ 3.01 At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its fuel products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 603,000 $ 3.01 Second Quarter 2016 603,000 $ 2.99 Third Quarter 2016 606,000 $ 3.03 Fourth Quarter 2016 790,000 $ 3.02 Total 2,602,000 Average price $ 3.01

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2016
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 derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least Baa1 and BBB+ by Moody’s and S&P, respectively. To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument, the Company uses discounted cash flows, which use observable inputs such as maturity and market interest rates. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the 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 March 31, 2016 , the Company’s net liability was reduced by approximately $2.3 million . As a result of applying the CVA at December 31, 2015 , the Company’s net liability was reduced by approximately $1.2 million . Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 7 for further information on derivative instruments. Pension Assets Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At March 31, 2016 , the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. Plan investments can be redeemed within a short time frame (10 or so business days), if requested. See Note 10 for further information on pension assets. Renewable Identification Numbers 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 Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase net of amounts internally generated and the price of those RINs as of the balance sheet date. The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service. For the three months ended March 31, 2016 and 2015 , the Company sold approximately 29 million and 49 million RINs, respectively, for gains of $20.8 million and $35.0 million , respectively, net of cost to generate, recorded in cost of sales in the unaudited condensed consolidated statements of operations. As of March 31, 2016 and 2015 , the Company had a RINs Obligation of approximately 154 million and 81 million RINs, respectively, which resulted in RINs expense for the three months ended March 31, 2016 and 2015 , of approximately $37.6 million and $42.2 million , respectively. Hierarchy of Recurring Fair Value Measurements The Company’s recurring assets and liabilities measured at fair value at March 31, 2016 , and December 31, 2015 , were as follows (in millions): March 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Pension plan investments $ 0.2 $ 48.8 $ — $ 49.0 $ 0.4 $ 47.1 $ — $ 47.5 Total recurring assets at fair value $ 0.2 $ 48.8 $ — $ 49.0 $ 0.4 $ 47.1 $ — $ 47.5 Liabilities: Derivative liabilities: Crude oil swaps $ — $ — $ (3.7 ) $ (3.7 ) $ — $ — $ (5.2 ) $ (5.2 ) Crude oil basis swaps — — (3.1 ) (3.1 ) — — (0.3 ) (0.3 ) Crude oil percentage basis swaps — — (6.4 ) (6.4 ) — — (6.7 ) (6.7 ) Crude oil options — — (0.9 ) (0.9 ) — — (0.3 ) (0.3 ) Gasoline crack spread swaps — — — — — — (4.3 ) (4.3 ) Natural gas swaps — — (14.5 ) (14.5 ) — — (16.2 ) (16.2 ) Natural gas collars — — (0.7 ) (0.7 ) — — (0.9 ) (0.9 ) Total derivative liabilities — — (29.3 ) (29.3 ) — — (33.9 ) (33.9 ) RINs Obligation — (115.2 ) — (115.2 ) — (88.4 ) — (88.4 ) Total recurring liabilities at fair value $ — $ (115.2 ) $ (29.3 ) $ (144.5 ) $ — $ (88.4 ) $ (33.9 ) $ (122.3 ) 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 three months ended March 31, 2016 and 2015 (in millions): Three Months Ended March 31, 2016 2015 Fair value at January 1, $ (33.9 ) $ 17.6 Realized (gain) loss on derivative instruments 12.3 (8.9 ) Unrealized gain (loss) on derivative instruments 4.6 (27.9 ) Interest expense, net (0.1 ) (0.2 ) Change in fair value of cash flow hedges — (5.1 ) Settlements (12.2 ) 2.2 Transfers in (out) of Level 3 — — Fair value at March 31, $ (29.3 ) $ (22.3 ) Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of March 31, $ 4.6 $ (27.9 ) 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 realized 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 realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 7 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 The carrying value of cash is considered to be representative of its fair value. Debt The estimated fair value of long-term debt at March 31, 2016 , and December 31, 2015 , consists primarily of the 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 notes classified as Level 2 was based upon directly observable inputs. The carrying value of borrowings, if any, under the Company’s revolving credit facility and capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 6 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 March 31, 2016 , and December 31, 2015 , were as follows (in millions): March 31, 2016 December 31, 2015 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,110.9 $ 1,549.3 $ 1,095.8 $ 1,230.8 Senior notes 2 $ — $ — $ 294.1 $ 317.6 Revolving credit facility 3 $ 289.4 $ 289.4 $ 105.1 $ 105.1 Note payable — related party 3 $ 72.4 $ 72.4 $ 73.5 $ 73.5 Capital lease and other obligations 3 $ 46.1 $ 46.1 $ 46.4 $ 46.4

Partners' Capital

Partners' Capital	3 Months Ended
	Mar. 31, 2016
Partners' Capital [Abstract]
Partners' Capital	Partners’ Capital The Company has entered into an Equity Placement Agreement with various sales agents under which the Company may issue and sell, from time to time, common units representing limited partner interests, having an aggregate offering price of up to $300.0 million through one or more sales agents. The Equity Placement Agreement provides the Company the right, but not the obligation, to sell common units in the future, at prices the Company deems appropriate. These sales, if any, will be made pursuant to the terms of the Equity Placement Agreement between the Company and the sales agents. The net proceeds from any sales under this agreement will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, working capital, capital expenditures and acquisitions. The Company’s general partner may contribute its proportionate capital contribution to retain its 2% general partner interest. The Company had no sales of its common units during the three months ended March 31, 2016 . For the three months ended March 31, 2015 , the Company sold 307,985 common units for the net proceeds of approximately $7.7 million . Underwriting discounts totaled approximately $0.1 million and the Company’s general partner contributed $0.2 million to maintain its general partner interest. In the three months ended March 31, 2016 and 2015 , the Company made distributions of $57.4 million and $52.7 million , respectively, to its partners. For the three months ended March 31, 2016 , the general partner was allocated no incentive distribution rights. For the three months ended March 31, 2015 , the general partner was allocated $4.2 million in incentive distribution rights.

Employee Benefit Plans

Employee Benefit Plans	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Employee Benefit Plans	Employee Benefit Plans The components of net periodic pension cost for the three months ended March 31, 2016 and 2015 , were as follows (in millions): Three Months Ended March 31, 2016 2015 Service cost $ — $ 0.1 Interest cost 0.6 0.7 Expected return on assets (0.8 ) (0.8 ) Amortization of net loss — 0.2 Net periodic benefit cost (income) $ (0.2 ) $ 0.2 At March 31, 2016 , and December 31, 2015 , the Company’s investments associated with its pension plan primarily consisted of (i) cash and cash equivalents and (ii) mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the NAV of shares in each fund held by the Pension Plan at quarter end as provided by the third party administrator. See Note 8 for the definitions of Levels 1, 2 and 3. The Company’s pension plan assets measured at fair value at March 31, 2016 , and December 31, 2015 , were as follows (in millions): March 31, 2016 December 31, 2015 Level 1 Level 2 Level 1 Level 2 Cash and cash equivalents $ 0.2 $ — $ 0.4 $ — Domestic equities — 9.7 — 9.6 Foreign equities — 9.2 — 9.2 Fixed income — 29.9 — 28.3 $ 0.2 $ 48.8 $ 0.4 $ 47.1 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	3 Months Ended
	Mar. 31, 2016
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 income (loss) in the Company’s unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 (in millions): Components of Accumulated Other Comprehensive Income (Loss) Amount Reclassified From Accumulated Other Comprehensive Loss Location of Gain (Loss) Three Months Ended March 31, 2016 2015 Derivative gains (losses) reflected in gross profit: $ 16.0 $ 20.2 Sales (13.9 ) (21.9 ) Cost of sales $ 2.1 $ (1.7 ) Total Amortization of defined benefit pension plans: Amortization of net loss $ — $ (0.2 ) (1) $ — $ (0.2 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 10 for additional details.

Earnings Per Unit

Earnings Per Unit	3 Months Ended
	Mar. 31, 2016
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 months ended March 31, 2016 and 2015 (in millions, except unit and per unit data): Three Months Ended March 31, 2016 2015 Numerator for basic and diluted earnings per limited partner unit: Net income (loss) $ (67.7 ) $ 23.8 General partner’s interest in net income (loss) (1.4 ) 0.5 General partner’s incentive distribution rights — 4.2 Net income (loss) available to limited partners $ (66.3 ) $ 19.1 Denominator for basic and diluted earnings per limited partner unit: Basic weighted average limited partner units outstanding 76,449,841 71,232,392 Effect of dilutive securities: Participating securities — phantom units — 43,060 Diluted weighted average limited partner units outstanding (1) 76,449,841 71,275,452 Limited partners’ interest basic and diluted net income (loss) per unit $ (0.87 ) $ 0.27 (1) Total diluted weighted average limited partner units outstanding excludes less than 0.1 million of dilutive phantom units for the three months ended March 31, 2016 .

Segments and Related Informatio

Segments and Related Information	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Segments and Related Information	Segments and Related Information a. Segment Reporting The Company manages its business in multiple operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments: • Specialty Products. The specialty products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants and other products which are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. Specialty products also include synthetic lubricants used in manufacturing, mining and automotive applications. • Fuel Products . The fuel products segment produces primarily gasoline, diesel, jet fuel and asphalt which are primarily sold to customers located in the PADD 2, PADD 3 and PADD 4 areas within the U.S. • Oilfield Services. The oilfield services segment markets its products and oilfield services including drilling fluids, completion fluids and solids control services to the oil and gas industry. 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 2015 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. The Company defines Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period. The Company manages its assets on a total company basis, not by segment. Therefore, management does not review any asset information by segment and, accordingly, the Company does not report asset information by segment. Reportable segment information for the three months ended March 31, 2016 and 2015 , is as follows (in millions): Three Months Ended March 31, 2016 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 300.7 $ 379.9 $ 32.4 $ 713.0 $ — $ 713.0 Intersegment sales 0.4 3.7 — 4.1 (4.1 ) — Total sales $ 301.1 $ 383.6 $ 32.4 $ 717.1 $ (4.1 ) $ 713.0 Loss from unconsolidated affiliates $ — $ (11.0 ) $ (0.1 ) $ (11.1 ) $ — $ (11.1 ) Adjusted EBITDA $ 58.5 $ (46.0 ) $ (5.9 ) $ 6.6 $ — $ 6.6 Reconciling items to net loss: Depreciation and amortization 18.4 24.7 4.8 47.9 — 47.9 Realized gain (loss) on derivatives, not reflected in net loss or settled in a prior period 0.7 (2.8 ) — (2.1 ) — (2.1 ) Unrealized gain on derivatives (4.6 ) Interest expense 30.3 Non-cash equity based compensation and other non-cash items 2.6 Income tax expense 0.2 Net loss $ (67.7 ) Three Months Ended March 31, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 361.6 $ 568.3 $ 88.7 $ 1,018.6 $ — $ 1,018.6 Intersegment sales 1.3 12.9 — 14.2 (14.2 ) — Total sales $ 362.9 $ 581.2 $ 88.7 $ 1,032.8 $ (14.2 ) $ 1,018.6 Loss from unconsolidated affiliates $ — $ (4.4 ) $ (0.1 ) $ (4.5 ) $ — $ (4.5 ) Adjusted EBITDA $ 65.9 $ 63.1 $ (4.1 ) $ 124.9 $ — $ 124.9 Reconciling items to net income: Depreciation and amortization 15.9 20.0 5.6 41.5 — 41.5 Realized gain on derivatives, not reflected in net income or settled in a prior period 0.4 5.7 — 6.1 — 6.1 Unrealized loss on derivatives 27.9 Interest expense 27.0 Non-cash equity based compensation and other non-cash items 3.4 Income tax benefit (4.8 ) Net income $ 23.8 b. Geographic Information International sales accounted for less than 10% of consolidated sales in each of the three months ended March 31, 2016 and 2015 . Substantially all of the Company’s long-lived assets are domestically located. c. Product Information The Company offers specialty products primarily in categories consisting of lubricating oils, solvents, waxes, packaged and synthetic specialty products and other. Fuel products categories primarily consist of gasoline, diesel, jet fuel, asphalt, heavy fuel oils and other. 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 March 31, 2016 and 2015 (in millions): Three Months Ended March 31, 2016 2015 Specialty products: Lubricating oils $ 129.2 18.1 % $ 149.8 14.7 % Solvents 55.9 7.8 % 86.2 8.5 % Waxes 27.2 3.8 % 39.0 3.8 % Packaged and synthetic specialty products 80.9 11.3 % 80.5 7.9 % Other 7.5 1.2 % 6.1 0.6 % Total $ 300.7 42.2 % $ 361.6 35.5 % Fuel products: Gasoline $ 162.2 22.7 % $ 246.3 24.1 % Diesel 138.9 19.5 % 213.9 21.0 % Jet fuel 23.4 3.3 % 38.2 3.8 % Asphalt, heavy fuel oils and other 55.4 7.8 % 69.9 6.9 % Total $ 379.9 53.3 % $ 568.3 55.8 % Oilfield services: Total $ 32.4 4.5 % $ 88.7 8.7 % Consolidated sales $ 713.0 100.0 % $ 1,018.6 100.0 % d. Major Customers During the three months ended March 31, 2016 and 2015 , the Company had no customer that represented 10% or greater of consolidated sales. e. Major Suppliers During the three months ended March 31, 2016 and 2015 , the Company had two suppliers that supplied approximately 52.8% and 48.1% , respectively, of its crude oil supply.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events The fair value of the Company’s derivatives that were outstanding as of March 31, 2016 , increased by approximately $4.0 million subsequent to March 31, 2016 , to a net liability of approximately $22.0 million . The fair value of the Company’s senior notes has decreased by approximately $42.0 million subsequent to March 31, 2016 . 11.5% Senior Secured Notes due 2021 On April 20, 2016 , the Company issued and sold $400.0 million in aggregate principal amount of 11.5% Senior Secured Notes due January 15, 2021 , at a discounted price of 98.273 percent of par (“2021 Secured Notes”). The Company received net proceeds of approximately $383.3 million net of discount, initial purchasers’ fees and estimated expenses, which it used to repay borrowings outstanding under its revolving credit facility and intends to use the remainder 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. Collateral Trust Agreement In connection with the private placement of the 2021 Secured Notes, on April 20, 2016, the Company entered into a collateral trust agreement (the “Collateral Trust Agreement”) which governs how the holders of the 2021 Secured Notes and secured hedging counterparties will share collateral pledged as security for the payment obligations owed by it to the holders of the 2021 Secured Notes and secured hedging counterparties under their respective master derivatives contracts. The Collateral Trust Agreement limits to $150.0 million the extent to which forward purchase contracts for physical commodities are covered by, and secured under, the Collateral Trust Agreement and the Parity Lien Security Documents (as defined in the Collateral Trust Agreement). There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, the Company has the ability to add secured hedging counterparties from time to time. Intercreditor Agreement The 2021 Secured Notes will not be secured by a lien on the collateral securing the Company’s revolving credit facility. In connection with the offering of the 2021 Secured Notes, the Collateral Trustee entered into that certain Second Amended and Restated Intercreditor Agreement (the “Intercreditor Agreement”) among the Collateral Trustee, as fixed asset collateral trustee, Bank of America, N.A., as agent for the lenders under the Company’s revolving credit facility (in such capacity, the “Agent”), the Company and the other grantors named therein (the “Obligors”), providing for certain access and administrative agreements with respect to the Credit Agreement Collateral and the Fixed Asset Collateral (as defined in the Intercreditor Agreement). Second Amendment to Second Amended and Restated Credit Agreement On April 20, 2016, the Company and certain of its operating subsidiaries as borrowers (collectively, the “Borrowers”) entered into a Second Amendment to Second Amended and Restated Credit Agreement (the “Second Amendment”), by and among the Borrowers, the Agent and the lenders party thereto (including Bank of America, N.A.), amending the Company’s revolving credit facility. The Second Amendment, among other things, amends the revolving credit facility to permit (a) the issuance of the 2021 Secured Notes pursuant to the indenture governing the 2021 Secured Notes and (b) such 2021 Secured Notes to be secured by a lien on the Fixed Asset Collateral, subject to the terms of the Intercreditor Agreement.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Basis of Accounting	The unaudited condensed consolidated financial statements of the Company as of March 31, 2016 , and for the three months ended March 31, 2016 and 2015 , 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. 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 months ended March 31, 2016 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 . These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2015 Annual Report.
New Accounting Pronouncements	New Accounting Pronouncements In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation — Stock Compensation (Topic 606): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. Under the new standard, income tax benefits and deficiencies are to be recognized as income tax expense or benefit in the income statement and the tax effects of exercised or vested awards should be treated as discrete items in the reporting period in which they occur. Excess tax benefits should be classified along with other income tax cash flows as an operating activity. In regards to forfeitures, the entity may make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-07, Investments — Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting (“ASU 2016-07”), which eliminates the retroactive adjustments to an investment upon it qualifying for the equity method of accounting as a result of an increase in the level of ownership interest or degree of influence by the investor. ASU 2016-07 requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment qualifies for equity method accounting. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments (“ASU 2016-06”). ASU 2016-06 simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The adoption of ASU 2016-06 is not expected to have an impact on the Company’s condensed consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (“ASU 2016-05”) . ASU 2016-05 clarifies that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument under Topic 815 does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. An entity can elect to adopt the amendments of ASU 2016-05 on either a prospective or modified retrospective basis. The adoption of ASU 2016-05 is not expected to have an impact on the Company’s 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 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 effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The Company is currently evaluating the impact of this standard on its 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 ASC 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. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 was originally effective for fiscal years (including interim periods) beginning after December 15, 2016. 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 effective date by one year, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606) — Principal versus Agent Considerations (“ASU 2016-08”). ASU 2016-08 provides clarifying guidance regarding the application of ASU 2014-09 when another party, along with the reporting entity, is involved in providing a good or a service to a customer. In these circumstances, an entity is required to determine whether the nature of its promise is to provide that good or service to the customer (that is, the entity is a principal) or to arrange for the good or service to be provided to the customer by the other party (that is, the entity is an agent). ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606) — Identifying Performance Obligations and Licensing (“ASU 2016-10”). ASU 2016-10 further amends the guidance with respect to certain implementation issues on identifying performance obligations and accounting for licenses of intellectual property. The new revenue standard permits companies to either apply the requirements retrospectively to all prior periods presented or apply the requirements in the year of adoption through a cumulative adjustment. The amendments in these standards, along with ASU 2014-09, are effective for fiscal years (including interim periods) beginning after December 15, 2017. The Company is currently evaluating the impact of these standards on its condensed consolidated financial statements.
Inventories	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 March 31, 2016 and 2015 , the Company recorded $8.1 million of gains and $13.2 million of losses, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market (“LCM”) valuation. 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.
Derivatives	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 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 cash flow impact of the Company’s derivative activities is classified primarily as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows. The Company is exposed to 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 NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”). The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in 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 recognizes all derivative instruments at their fair values (see Note 8 ) 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 Company’s financial results are subject to the possibility that changes in a derivative’s fair value could result in significant ineffectiveness and potentially no longer qualify portions or all of its derivative instruments for hedge accounting. Derivative Instruments Not Designated as Hedges For derivative instruments not designated as hedges, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. The Company has entered into crude oil basis swaps that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract. Additionally, the Company has entered into diesel crack spread collars, gasoline crack spread collars, natural gas collars, and certain other crude oil swaps, diesel swaps, gasoline swaps, natural gas swaps and platinum swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and gasoline and diesel sales at the Company’s Superior refinery. Derivative Instruments Designated as Cash Flow Hedges The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel swaps as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases are recorded to sales and cost of sales, respectively, in the 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 unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously deferred in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations.
Fair Value Measurement	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 realized 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 realized 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. Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument, the Company uses discounted cash flows, which use observable inputs such as maturity and market interest rates. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the 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. Debt The estimated fair value of long-term debt at March 31, 2016 , and December 31, 2015 , consists primarily of the 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 notes classified as Level 2 was based upon directly observable inputs. The carrying value of borrowings, if any, under the Company’s revolving credit facility and capital lease obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. 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. Pension Assets Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At March 31, 2016 , the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. Plan investments can be redeemed within a short time frame (10 or so business days), if requested. See Note 10 for further information on pension assets. Renewable Identification Numbers 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 Renewable Fuel Standard. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S., and as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase net of amounts internally generated and the price of those RINs as of the balance sheet date. The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service. Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds.
Segment Reporting	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 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 2015 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. The Company defines Adjusted EBITDA for any period as: (1) net income (loss) plus (2)(a) interest expense; (b) income taxes; (c) depreciation and amortization; (d) unrealized losses from mark to market accounting for hedging activities; (e) realized gains under derivative instruments excluded from the determination of net income (loss); (f) non-cash equity based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (g) debt refinancing fees, premiums and penalties and (h) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Summary of Inventories	Inventories consist of the following (in millions): March 31, 2016 December 31, 2015 Raw materials $ 51.6 $ 47.9 Work in process 72.7 64.0 Finished goods 305.6 272.5 $ 429.9 $ 384.4

Investment in Unconsolidated 24

Investment in Unconsolidated Affiliates Equity Method Investments and Joint Ventures (Tables)	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments [Table Text Block]	The following represents summary financial information for Dakota Prairie, presented at 100% (in millions): Three Months Ended March 31, 2016 2015 Operating revenue $ 45.1 $ 1.7 Operating loss $ (20.8 ) $ (7.0 ) Net loss $ (21.6 ) $ (7.1 ) The following table summarizes the Company’s investments in unconsolidated affiliates as of March 31, 2016 , and December 31, 2015 (in millions): Three Months Ended March 31, 2016 Year Ended December 31, 2015 Investment Percent Ownership Investment Percent Ownership Dakota Prairie Refining, LLC $ 113.7 50 % $ 124.7 50 % Other 2.1 1.3 Total $ 115.8 $ 126.0

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Instrument [Line Items]
Summary of Long-Term Debt	Long-term debt consisted of the following (in millions): March 31, 2016 December 31, 2015 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 3.3% at March 31, 2016 $ 294.9 $ 111.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for the three months ended March 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 three months ended March 31, 2016 (1) 352.8 352.9 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 three months ended March 31, 2016 325.0 325.0 Related party note payable, interest at a fixed rate of 6.0% on a portion of the note, interest payments at various dates, borrowings due July 2016, weighted average interest rate of 6.0% for the three months ended March 31, 2016 72.4 73.5 Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034 46.1 46.4 Less unamortized debt issuance costs (2) (27.7 ) (28.9 ) Less unamortized discounts (6.3 ) (6.5 ) Total long-term debt 1,957.2 1,773.4 Less current portion of note payable — related party 72.4 73.5 Less current portion of long-term debt 1.7 1.7 $ 1,883.1 $ 1,698.2 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.8 million and $2.9 million as of March 31, 2016 , and December 31, 2015 , respectively (refer to Note 7 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 $9.4 million and $8.1 million at March 31, 2016 , and December 31, 2015 , respectively.
Summary of Principal Payments on Debt Obligations and Future Minimum Rentals on Capital Lease Obligations	As of March 31, 2016 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year Maturity 2016 $ 74.7 2017 1.6 2018 1.5 2019 296.2 2020 0.9 Thereafter 1,614.5 Total $ 1,989.4

Derivatives (Tables)

Derivatives (Tables)	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 , and December 31, 2015 (in millions): March 31, 2016 December 31, 2015 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: Fuel products segment: Crude oil swaps $ 3.8 $ (3.8 ) $ — $ — $ — $ — Crude oil basis swaps 1.0 (1.0 ) — 0.4 (0.4 ) — Crude oil percentage basis swaps 0.1 (0.1 ) — 0.2 (0.2 ) — Crude oil options 0.6 (0.6 ) — 0.8 (0.8 ) — Total derivative instruments not designated as hedges 5.5 (5.5 ) — 1.4 (1.4 ) — Total derivative instruments $ 5.5 $ (5.5 ) $ — $ 1.4 $ (1.4 ) $ —
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 March 31, 2016 , and December 31, 2015 (in millions): March 31, 2016 December 31, 2015 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 $ (13.0 ) $ — $ (13.0 ) $ (14.9 ) $ — $ (14.9 ) Natural gas collars (0.7 ) — (0.7 ) (0.9 ) — (0.9 ) Fuel products segment: Crude oil swaps (7.5 ) 3.8 (3.7 ) (5.2 ) — (5.2 ) Crude oil basis swaps (4.1 ) 1.0 (3.1 ) (0.7 ) 0.4 (0.3 ) Crude oil percentage basis swaps (6.5 ) 0.1 (6.4 ) (6.9 ) 0.2 (6.7 ) Crude oil options (1.5 ) 0.6 (0.9 ) (1.1 ) 0.8 (0.3 ) Gasoline crack spread swaps — — — (4.3 ) — (4.3 ) Natural gas swaps (1.5 ) — (1.5 ) (1.3 ) — (1.3 ) Total derivative instruments not designated as hedges (34.8 ) 5.5 (29.3 ) (35.3 ) 1.4 (33.9 ) Total derivative instruments $ (34.8 ) $ 5.5 $ (29.3 ) $ (35.3 ) $ 1.4 $ (33.9 )
Schedule of Derivative Instruments	The amount reclassified from accumulated other comprehensive loss into earnings, as a result of the discontinuance of cash flow hedge accounting for certain crude oil, gasoline, jet fuel and diesel derivative instruments at the Shreveport refinery because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, caused the Company to recognize the following gains in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 (in millions): Three Months Ended March 31, 2016 2015 Realized gain on derivative instruments $ — $ 1.2
Schedule of the Effective Portion of Cash Flow Hedges Classified in Accumulated Other Comprehensive Income	The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was gains of $4.3 million and $6.4 million as of March 31, 2016 , and December 31, 2015 , respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive income (loss) at March 31, 2016 , will be reclassified to earnings by December 31, 2016, with balances being recognized as follows (in millions): Year Accumulated Other Comprehensive Income 2016 $ 4.3 Total $ 4.3
Specialty Product [Member] | Natural Gas Swap Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Natural Gas Swap Contracts At March 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 Second Quarter 2016 1,380,000 $ 4.26 Third Quarter 2016 1,380,000 $ 4.26 Fourth Quarter 2016 1,540,000 $ 4.14 Calendar Year 2017 4,950,000 $ 3.85 Total 9,250,000 Average price $ 4.02 At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 1,580,000 $ 4.24 Second Quarter 2016 1,380,000 $ 4.26 Third Quarter 2016 1,380,000 $ 4.26 Fourth Quarter 2016 1,540,000 $ 4.14 Calendar Year 2017 4,950,000 $ 3.85 Total 10,830,000 Average price $ 4.05
Specialty Product [Member] | Natural Gas Collars [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Natural Gas Collars At March 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 Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) Second Quarter 2016 180,000 $ 4.25 $ 3.89 Third Quarter 2016 180,000 $ 4.25 $ 3.89 Fourth Quarter 2016 60,000 $ 4.25 $ 3.89 Total 420,000 Average price $ 4.25 $ 3.89 At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges: Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2016 180,000 $ 4.25 $ 3.89 Second Quarter 2016 180,000 $ 4.25 $ 3.89 Third Quarter 2016 180,000 $ 4.25 $ 3.89 Fourth Quarter 2016 60,000 $ 4.25 $ 3.89 Total 600,000 Average price $ 4.25 $ 3.89
Fuel Product [Member] | Natural Gas Swap Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Natural Gas Swap Contracts At March 31, 2016 , the Company had the following derivatives related to natural gas purchases in its fuel products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu Second Quarter 2016 603,000 $ 2.99 Third Quarter 2016 606,000 $ 3.03 Fourth Quarter 2016 790,000 $ 3.02 Total 1,999,000 Average price $ 3.01 At December 31, 2015 , the Company had the following derivatives related to natural gas purchases in its fuel products segment, none of which are designated as hedges: Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2016 603,000 $ 3.01 Second Quarter 2016 603,000 $ 2.99 Third Quarter 2016 606,000 $ 3.03 Fourth Quarter 2016 790,000 $ 3.02 Total 2,602,000 Average price $ 3.01
Fuel Product [Member] | Crude Oil Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Swap Contracts At March 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 Second Quarter 2016 54,120 595 $ 39.32 Third Quarter 2016 398,893 4,336 $ 39.52 Fourth Quarter 2016 398,893 4,336 $ 39.52 Calendar Year 2017 1,297,976 3,556 $ 48.87 Total 2,149,882 Average price $ 45.16 At March 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 Calendar Year 2017 528,520 1,448 $ 41.56 Total 528,520 Average price $ 41.56 At December 31, 2015 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2016 29,120 320 $ 44.06 Second Quarter 2016 29,120 320 $ 44.06 Third Quarter 2016 29,440 320 $ 44.06 Fourth Quarter 2016 29,440 320 $ 44.06 Calendar Year 2017 630,720 1,728 $ 54.94 Total 747,840 Average price $ 53.24
Fuel Product [Member] | Crude Oil Basis Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Basis Swap Contracts The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between LLS and NYMEX WTI. At March 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 Second Quarter 2016 365,000 5,000 $ 1.80 Third Quarter 2016 460,000 5,000 $ 1.80 Fourth Quarter 2016 460,000 5,000 $ 1.80 Total 1,285,000 Average differential $ 1.80 At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 182,000 2,000 $ 2.40 Second Quarter 2016 182,000 2,000 $ 2.40 Third Quarter 2016 184,000 2,000 $ 2.40 Fourth Quarter 2016 184,000 2,000 $ 2.40 Total 732,000 Average differential $ 2.40 The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At March 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 Second Quarter 2016 697,000 7,659 $ (14.02 ) Third Quarter 2016 1,196,000 13,000 $ (13.18 ) Fourth Quarter 2016 1,196,000 13,000 $ (13.18 ) Calendar Year 2017 2,555,000 7,000 $ (13.22 ) Total 5,644,000 Average differential $ (13.31 ) At December 31, 2015 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2016 91,000 1,000 $ (14.10 ) Second Quarter 2016 91,000 1,000 $ (14.10 ) Third Quarter 2016 92,000 1,000 $ (14.10 ) Fourth Quarter 2016 92,000 1,000 $ (14.10 ) Calendar Year 2017 365,000 1,000 $ (13.70 ) Total 731,000 Average differential $ (13.90 )
Fuel Product [Member] | Crude Oil Percent Basis Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Percentage Basis Swap Contracts The Company has entered into derivative instruments to secure a percentage differential on WCS crude oil to NYMEX WTI. At March 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 Second Quarter 2016 728,000 8,000 73.5 % Third Quarter 2016 736,000 8,000 73.5 % Fourth Quarter 2016 736,000 8,000 73.5 % Calendar Year 2017 1,095,000 3,000 72.3 % Total 3,295,000 Average percentage 73.1 % At December 31, 2015 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges: Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI First Quarter 2016 728,000 8,000 73.5 % Second Quarter 2016 728,000 8,000 73.5 % Third Quarter 2016 736,000 8,000 73.5 % Fourth Quarter 2016 736,000 8,000 73.5 % Calendar Year 2017 730,000 2,000 73.0 % Total 3,658,000 Average percentage 73.4 %
Fuel Product [Member] | Crude Option Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Option Contracts The Company has entered into derivative instruments to mitigate the risk of future changes in the price of NYMEX WTI crude oil. At March 31, 2016 , the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Call ($/Bbl) Fourth Quarter 2016 350,000 11,290 $ 55.00 Total 350,000 Average price $ 55.00 At March 31, 2016 , the Company had the following derivatives related to crude oil call option sales in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Sold BPD Average Sold Call ($/Bbl) Second Quarter 2016 300,000 9,677 $ 41.78 Total 300,000 Average price $ 41.78 At March 31, 2016 , the Company had the following derivatives related to crude oil put option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Put ($/Bbl) Second Quarter 2016 300,000 9,677 $ 32.58 Total 300,000 Average price $ 32.58 At December 31, 2015 , the Company had the following derivatives related to crude oil call option purchases in its fuel products segment, none of which are designated as hedges: Crude Oil Option Contracts by Expiration Dates Barrels Purchased BPD Average Bought Call ($/Bbl) Fourth Quarter 2016 350,000 11,290 $ 55.00 Total 350,000 Average price $ 55.00
Fuel Product [Member] | Gasoline Crack Spread Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Gasoline Crack Spread Swap Contracts At December 31, 2015 , the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges: Gasoline Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2016 873,000 9,593 $ 8.98 Total 873,000 Average price $ 8.98
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 income (loss) and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended March 31, 2016 and 2015 , 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 Income (Loss) (Effective Portion) Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion) Three Months Ended Location of Gain (Loss) Three Months Ended Location of Gain (Loss) Three Months Ended March 31, March 31, March 31, 2016 2015 2016 2015 2016 2015 Specialty products segment: Crude oil swaps $ — $ — Cost of sales $ (0.7 ) $ (0.4 ) Unrealized/ Realized $ — $ — Fuel products segment: Crude oil swaps (1.3 ) (6.3 ) Cost of sales (13.2 ) (21.5 ) Unrealized/ Realized — (0.2 ) Gasoline swaps — 0.8 Sales — 14.0 Unrealized/ Realized — 0.7 Diesel swaps 1.3 0.1 Sales 16.0 4.8 Unrealized/ Realized — — Jet fuel swaps — 0.3 Sales — 1.4 Unrealized/ Realized — — Total $ — $ (5.1 ) $ 2.1 $ (1.7 ) $ — $ 0.5
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 March 31, 2016 and 2015 , related to its derivative instruments not designated as hedges (in millions): Type of Derivative Amount of Gain (Loss) Recognized in Realized Gain (Loss) on Derivative Instruments Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments Three Months Ended March 31, Three Months Ended March 31, 2016 2015 2016 2015 Specialty products segment: Natural gas swaps $ (3.7 ) $ (2.1 ) $ 2.0 $ (3.2 ) Platinum swaps — — — (0.1 ) Fuel products segment: Crude oil swaps (0.9 ) (48.3 ) 1.5 50.2 Crude oil basis swaps — 1.0 (2.6 ) (0.4 ) Crude oil percentage basis swaps (3.9 ) — 0.2 — Crude oil options — — (0.6 ) — Crude oil futures (2.0 ) — — — Gasoline swaps — (2.0 ) — (1.1 ) Gasoline crack spread swaps (1.2 ) (0.8 ) 4.3 (1.5 ) Diesel swaps — 58.0 — (63.4 ) Diesel crack spread swaps — 0.9 — (6.4 ) Jet fuel swaps — 1.6 — (1.6 ) Natural gas swaps (0.6 ) — (0.2 ) (0.3 ) Total $ (12.3 ) $ 8.3 $ 4.6 $ (27.8 )
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 gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 , related to its derivative instrument designated as a fair value hedge (in millions): Location of Loss of Derivative Amount of Loss Recognized in Net Income (Loss) Hedged Item Location of Gain on Hedged Item Amount of Gain Recognized in Net Income (Loss) Three Months Ended March 31, Three Months Ended March 31, 2016 2015 2016 2015 Swaps not allocated to a specific segment: Interest rate swap Interest expense $ 0.1 $ 0.2 2022 Notes Interest income $ — $ — Total $ 0.1 $ 0.2 $ — $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 , and December 31, 2015 , were as follows (in millions): March 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Pension plan investments $ 0.2 $ 48.8 $ — $ 49.0 $ 0.4 $ 47.1 $ — $ 47.5 Total recurring assets at fair value $ 0.2 $ 48.8 $ — $ 49.0 $ 0.4 $ 47.1 $ — $ 47.5 Liabilities: Derivative liabilities: Crude oil swaps $ — $ — $ (3.7 ) $ (3.7 ) $ — $ — $ (5.2 ) $ (5.2 ) Crude oil basis swaps — — (3.1 ) (3.1 ) — — (0.3 ) (0.3 ) Crude oil percentage basis swaps — — (6.4 ) (6.4 ) — — (6.7 ) (6.7 ) Crude oil options — — (0.9 ) (0.9 ) — — (0.3 ) (0.3 ) Gasoline crack spread swaps — — — — — — (4.3 ) (4.3 ) Natural gas swaps — — (14.5 ) (14.5 ) — — (16.2 ) (16.2 ) Natural gas collars — — (0.7 ) (0.7 ) — — (0.9 ) (0.9 ) Total derivative liabilities — — (29.3 ) (29.3 ) — — (33.9 ) (33.9 ) RINs Obligation — (115.2 ) — (115.2 ) — (88.4 ) — (88.4 ) Total recurring liabilities at fair value $ — $ (115.2 ) $ (29.3 ) $ (144.5 ) $ — $ (88.4 ) $ (33.9 ) $ (122.3 )
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 three months ended March 31, 2016 and 2015 (in millions): Three Months Ended March 31, 2016 2015 Fair value at January 1, $ (33.9 ) $ 17.6 Realized (gain) loss on derivative instruments 12.3 (8.9 ) Unrealized gain (loss) on derivative instruments 4.6 (27.9 ) Interest expense, net (0.1 ) (0.2 ) Change in fair value of cash flow hedges — (5.1 ) Settlements (12.2 ) 2.2 Transfers in (out) of Level 3 — — Fair value at March 31, $ (29.3 ) $ (22.3 ) Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of March 31, $ 4.6 $ (27.9 )
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 March 31, 2016 , and December 31, 2015 , were as follows (in millions): March 31, 2016 December 31, 2015 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,110.9 $ 1,549.3 $ 1,095.8 $ 1,230.8 Senior notes 2 $ — $ — $ 294.1 $ 317.6 Revolving credit facility 3 $ 289.4 $ 289.4 $ 105.1 $ 105.1 Note payable — related party 3 $ 72.4 $ 72.4 $ 73.5 $ 73.5 Capital lease and other obligations 3 $ 46.1 $ 46.1 $ 46.4 $ 46.4

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Summary of Components of Net Periodic Pension Cost	The components of net periodic pension cost for the three months ended March 31, 2016 and 2015 , were as follows (in millions): Three Months Ended March 31, 2016 2015 Service cost $ — $ 0.1 Interest cost 0.6 0.7 Expected return on assets (0.8 ) (0.8 ) Amortization of net loss — 0.2 Net periodic benefit cost (income) $ (0.2 ) $ 0.2
Schedule of Pension Plan Assets Measured at Fair Value	The Company’s pension plan assets measured at fair value at March 31, 2016 , and December 31, 2015 , were as follows (in millions): March 31, 2016 December 31, 2015 Level 1 Level 2 Level 1 Level 2 Cash and cash equivalents $ 0.2 $ — $ 0.4 $ — Domestic equities — 9.7 — 9.6 Foreign equities — 9.2 — 9.2 Fixed income — 29.9 — 28.3 $ 0.2 $ 48.8 $ 0.4 $ 47.1

Accumulated Other Comprehensi29

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 2016
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 income (loss) in the Company’s unaudited condensed consolidated statements of operations for the three months ended March 31, 2016 and 2015 (in millions): Components of Accumulated Other Comprehensive Income (Loss) Amount Reclassified From Accumulated Other Comprehensive Loss Location of Gain (Loss) Three Months Ended March 31, 2016 2015 Derivative gains (losses) reflected in gross profit: $ 16.0 $ 20.2 Sales (13.9 ) (21.9 ) Cost of sales $ 2.1 $ (1.7 ) Total Amortization of defined benefit pension plans: Amortization of net loss $ — $ (0.2 ) (1) $ — $ (0.2 ) Total (1) This accumulated other comprehensive loss component is included in the computation of net periodic pension cost. See Note 10 for additional details.

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	3 Months Ended
	Mar. 31, 2016
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 months ended March 31, 2016 and 2015 (in millions, except unit and per unit data): Three Months Ended March 31, 2016 2015 Numerator for basic and diluted earnings per limited partner unit: Net income (loss) $ (67.7 ) $ 23.8 General partner’s interest in net income (loss) (1.4 ) 0.5 General partner’s incentive distribution rights — 4.2 Net income (loss) available to limited partners $ (66.3 ) $ 19.1 Denominator for basic and diluted earnings per limited partner unit: Basic weighted average limited partner units outstanding 76,449,841 71,232,392 Effect of dilutive securities: Participating securities — phantom units — 43,060 Diluted weighted average limited partner units outstanding (1) 76,449,841 71,275,452 Limited partners’ interest basic and diluted net income (loss) per unit $ (0.87 ) $ 0.27 (1) Total diluted weighted average limited partner units outstanding excludes less than 0.1 million of dilutive phantom units for the three months ended March 31, 2016 .

Segments and Related Informat31

Segments and Related Information (Tables)	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Schedule of Reportable Segment Information	Reportable segment information for the three months ended March 31, 2016 and 2015 , is as follows (in millions): Three Months Ended March 31, 2016 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 300.7 $ 379.9 $ 32.4 $ 713.0 $ — $ 713.0 Intersegment sales 0.4 3.7 — 4.1 (4.1 ) — Total sales $ 301.1 $ 383.6 $ 32.4 $ 717.1 $ (4.1 ) $ 713.0 Loss from unconsolidated affiliates $ — $ (11.0 ) $ (0.1 ) $ (11.1 ) $ — $ (11.1 ) Adjusted EBITDA $ 58.5 $ (46.0 ) $ (5.9 ) $ 6.6 $ — $ 6.6 Reconciling items to net loss: Depreciation and amortization 18.4 24.7 4.8 47.9 — 47.9 Realized gain (loss) on derivatives, not reflected in net loss or settled in a prior period 0.7 (2.8 ) — (2.1 ) — (2.1 ) Unrealized gain on derivatives (4.6 ) Interest expense 30.3 Non-cash equity based compensation and other non-cash items 2.6 Income tax expense 0.2 Net loss $ (67.7 ) Three Months Ended March 31, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 361.6 $ 568.3 $ 88.7 $ 1,018.6 $ — $ 1,018.6 Intersegment sales 1.3 12.9 — 14.2 (14.2 ) — Total sales $ 362.9 $ 581.2 $ 88.7 $ 1,032.8 $ (14.2 ) $ 1,018.6 Loss from unconsolidated affiliates $ — $ (4.4 ) $ (0.1 ) $ (4.5 ) $ — $ (4.5 ) Adjusted EBITDA $ 65.9 $ 63.1 $ (4.1 ) $ 124.9 $ — $ 124.9 Reconciling items to net income: Depreciation and amortization 15.9 20.0 5.6 41.5 — 41.5 Realized gain on derivatives, not reflected in net income or settled in a prior period 0.4 5.7 — 6.1 — 6.1 Unrealized loss on derivatives 27.9 Interest expense 27.0 Non-cash equity based compensation and other non-cash items 3.4 Income tax benefit (4.8 ) Net income $ 23.8
Schedule of Major Product Category Sales	The following table sets forth the major product category sales for the three months ended March 31, 2016 and 2015 (in millions): Three Months Ended March 31, 2016 2015 Specialty products: Lubricating oils $ 129.2 18.1 % $ 149.8 14.7 % Solvents 55.9 7.8 % 86.2 8.5 % Waxes 27.2 3.8 % 39.0 3.8 % Packaged and synthetic specialty products 80.9 11.3 % 80.5 7.9 % Other 7.5 1.2 % 6.1 0.6 % Total $ 300.7 42.2 % $ 361.6 35.5 % Fuel products: Gasoline $ 162.2 22.7 % $ 246.3 24.1 % Diesel 138.9 19.5 % 213.9 21.0 % Jet fuel 23.4 3.3 % 38.2 3.8 % Asphalt, heavy fuel oils and other 55.4 7.8 % 69.9 6.9 % Total $ 379.9 53.3 % $ 568.3 55.8 % Oilfield services: Total $ 32.4 4.5 % $ 88.7 8.7 % Consolidated sales $ 713.0 100.0 % $ 1,018.6 100.0 %

Description of the Business - N

Description of the Business - Narrative (Details) - shares	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Limited Partner [Member]
Schedule of Equity Method Investments [Line Items]
Limited partner common units outstanding (in shares)	75,884,400	75,884,400
Ownership percentage	98.00%
General Partner [Member]
Schedule of Equity Method Investments [Line Items]
General partner equivalent units outstanding (in shares)	1,548,660
Ownership percentage	2.00%

Inventories - Narrative (Detail

Inventories - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventory Write-down	$ 8.1	$ (13.2)
Inventory method	last-in, first-out (“LIFO”)
Replacement cost of inventories, based on current market values	$ 69.3		$ 41

Inventories - Summary of Invent

Inventories - Summary of Inventories (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Inventories
Raw materials	$ 51.6	$ 47.9
Work in process	72.7	64
Finished goods	305.6	272.5
Inventories total	$ 429.9	$ 384.4

Investment in Unconsolidated 35

Investment in Unconsolidated Affiliates Investment in Unconsolidated Affiliates - Schedule (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Feb. 07, 2013
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliates	$ 115.8	$ 126
Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliates	$ 113.7	$ 124.7
Equity interest percentage	50.00%	50.00%	50.00%
Other Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliates	$ 2.1	$ 1.3

Investment in Unconsolidated 36

Investment in Unconsolidated Affiliates - Narrative (Details) - USD ($) $ in Millions	Feb. 07, 2013	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments		$ 0.9	$ 25
Investment in unconsolidated affiliates		115.8		$ 126
Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments		$ 300
Equity interest percentage	50.00%	50.00%		50.00%
Investment in unconsolidated affiliates		$ 113.7		$ 124.7
Dakota Prairie Refining, LLC [Member] | Proceeds From Term Loan [Member]
Schedule of Equity Method Investments [Line Items]
Contribution amount funded	$ 75
Payments to Acquire Equity Method Investments		88.7
Dakota Prairie Refining, LLC [Member] | MDU Resources Group Inc [Member]
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments		$ 80.6

Investment in Unconsolidated 37

Investment in Unconsolidated Affiliates Investment in Unconsolidated Affiliates - DPR Summary Financials (Details) - Dakota Prairie Refining, LLC [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Schedule of Equity Method Investments [Line Items]
Operating revenue	$ 45.1	$ 1.7
Operating loss	(20.8)	(7)
Net loss	$ (21.6)	$ (7.1)

Commitments and Contingencies -

Commitments and Contingencies - Narrative - Environmental (Details) - USD ($) $ in Millions	Jun. 29, 2012	Mar. 31, 2016	Mar. 31, 2015
Montana [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		$ 18.2
WDNR-Superior [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		0	$ 0.3
Estimates Costs of Equipment Upgrades and Conduct Other Discrete		4
EPA [Member]
Loss Contingencies [Line Items]
Proposed penalty amount	$ 0.1
LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		$ 0.4	$ 1
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
Bel-Ray [Member]
Loss Contingencies [Line Items]
Weston Agreement trust fund amount		0.8
Capital Expenditure [Member] | Montana [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		14.6
Expense [Member] | Montana [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		3.6
Minimum [Member] | LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		3
Maximum [Member] | LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense		5
Maximum [Member] | Shreveport [Member]
Loss Contingencies [Line Items]
Specified environmental liabilities first required amount to contribute		$ 1

Commitments and Contingencies39

Commitments and Contingencies - Narrative - Occupational Health and Safety (Details) - Occupational Safety and Health Administration [Member] - USD ($) $ in Millions	Mar. 14, 2011	Mar. 31, 2016	Mar. 31, 2015
Loss Contingencies [Line Items]
Capital expenditures		$ 0.3	$ 0.1
Date in which OSHA issued a Citation and Notification of Penalty	Mar. 14, 2011
Proposed penalty amount	$ 0.2
Maximum [Member]
Loss Contingencies [Line Items]
Expected capital expenditures		$ 1

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies - Narrative -Standby Letters of Credit (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Revolving Credit Facility [Member]
Loss Contingencies [Line Items]
Outstanding standby letters of credit	$ 63.5	$ 66.8
Revolving Credit Facility [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Letter of credit sublimit	90.00%
Revolver commitments	$ 1,000
Letter of Credit [Member]
Loss Contingencies [Line Items]
Revolver commitments	600
Line of Credit Facility, Capacity Available for Trade Purchases	$ 101.3	$ 233.5

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Summary of Long-term debt
Deferred Finance Costs, Noncurrent, Net	[1]	$ (27.7)	$ (28.9)
Total long-term debt		1,957.2	1,773.4
Note payable - related party		72.4	73.5
Less current portion of long-term debt		1.7	1.7
Total long-term debt, excluding current portion		1,883.1	1,698.2
Revolving Credit Facility [Member]
Summary of Long-term debt
Borrowings under senior secured revolving credit agreement		$ 294.9	111
Senior Notes [Abstract]
Weighted average interest rate		3.30%
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%
Effective interest rate		6.80%
7.625% Notes [Member]
Summary of Long-term debt
Borrowings under Notes	[2]	$ 352.8	352.9
Senior Notes [Abstract]
Fixed rate		7.625%
Effective interest rate		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%
Effective interest rate		8.00%
Less unamortized discounts [Member]
Summary of Long-term debt
Less unamortized discounts		$ (6.3)	(6.5)
Interest Expense [Member] | Fair Value Hedging [Member]
Senior Notes [Abstract]
Liabilities, fair value adjustment		$ 2.8	$ 2.9
[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 $9.4 million and $8.1 million at March 31, 2016, and December 31, 2015, respectively.
[2]	The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.8 million and $2.9 million as of March 31, 2016, and December 31, 2015, respectively (refer to Note 7 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 ($)	Apr. 28, 2015	Mar. 27, 2015	Mar. 31, 2014	Nov. 26, 2013	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Accumulated Amortization, Deferred Finance Costs					$ 9,400,000		$ 8,100,000
Long-Term Debt (Textual) [Abstract]
Common units sold (in shares)						307,985
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		$ 325,000,000
Maturity date		Apr. 15, 2023
Debt instrument percent discount price of par		99.257%
Net proceeds from sale of senior notes		$ 317,000,000
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			$ 900,000,000
Maturity date			Apr. 15, 2021
Net proceeds from sale of senior notes			$ 884,000,000
Redemption of aggregate principal amount			$ 500,000,000
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				$ 350,000,000
Maturity date				Jan. 15, 2022
Debt instrument percent discount price of par				98.494%
Net proceeds from sale of senior notes				$ 337,400,000
Frequency of interest payment				semiannually
9.375% Notes [Member]
Long-Term Debt (Textual) [Abstract]
Redemption of aggregate principal amount				$ 100,000,000
9.625% Notes [Member]
Long-Term Debt (Textual) [Abstract]
Redemption of aggregate principal amount	$ 178,800,000
Senior Notes [Member] | Maximum [Member]
Long-Term Debt (Textual) [Abstract]
Fixed charge coverage ratio					1
Revolving Credit Facility [Member]
Long-Term Debt (Textual) [Abstract]
Maturity date					Jul. 14, 2019
Frequency of interest payment					quarterly
Incremental uncommitted expansion feature					$ 500,000,000
Customary letter of credit fee, including a fronting fee per annum on the stated amount of each outstanding letter of credit					0.125%
Revolving credit facility, borrowing capacity					$ 459,700,000
Outstanding borrowings					294,900,000		111,000,000
Outstanding standby letters of credit					63,500,000		$ 66,800,000
Available for additional borrowings based on specified availability limitations					$ 101,300,000
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]
Senior secured revolving credit facility					$ 1,000,000,000
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					75.00%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member]
Long-Term Debt (Textual) [Abstract]
Basis points					175.00%

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	Mar. 31, 2016USD ($)
Maturities of long-term debt
2,016	$ 74.7
2,017	1.6
2,018	1.5
2,019	296.2
2,020	0.9
Thereafter	1,614.5
Long-term debt	$ 1,989.4

Derivatives - Summary of Gross

Derivatives - Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative Assets (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 5.5	$ 1.4
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(5.5)	(1.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0
Not Designated as Hedging Instrument [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	5.5	1.4
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(5.5)	(1.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0
Commodity Contract [Member] | Crude Oil Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	3.8	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(3.8)	0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0
Commodity Contract [Member] | Crude Oil Basis Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	1	0.4
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(1)	(0.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0
Commodity Contract [Member] | Crude Oil Percent Basis Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0.1	0.2
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.1)	(0.2)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0
Commodity Contract [Member] | Crude Oil Options [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0.6	0.8
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.6)	(0.8)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	$ 0	$ 0

Derivatives - Summary of Gros45

Derivatives - Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ (34.8)	$ (35.3)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	5.5	1.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(29.3)	(33.9)
Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(34.8)	(35.3)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	5.5	1.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(29.3)	(33.9)
Commodity Contract [Member] | Specialty Product [Member] | Natural Gas Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(13)	(14.9)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(13)	(14.9)
Commodity Contract [Member] | Specialty Product [Member] | Natural Gas Collars [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(0.7)	(0.9)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.7)	(0.9)
Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(7.5)	(5.2)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	3.8	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(3.7)	(5.2)
Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Basis Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(4.1)	(0.7)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	1	0.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(3.1)	(0.3)
Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Percent Basis Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(6.5)	(6.9)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.1	0.2
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(6.4)	(6.7)
Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Options [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(1.5)	(1.1)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.6	0.8
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.9)	(0.3)
Commodity Contract [Member] | Fuel Product [Member] | Gasoline Crack Spread Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	(4.3)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0	(4.3)
Commodity Contract [Member] | Fuel Product [Member] | Natural Gas Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(1.5)	(1.3)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	$ (1.5)	$ (1.3)

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
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	$ 0	$ (5.1)
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)	2.1	(1.7)
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	0.5
Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	(1.3)	(6.3)
Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Swaps [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)	(13.2)	(21.5)
Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Swaps [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	(0.2)
Commodity Contract [Member] | Fuel Product [Member] | Gasoline Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	0	0.8
Commodity Contract [Member] | Fuel Product [Member] | Gasoline Swaps [Member] | Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)	0	14
Commodity Contract [Member] | Fuel Product [Member] | Gasoline Swaps [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	0.7
Commodity Contract [Member] | Fuel Product [Member] | Diesel Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	1.3	0.1
Commodity Contract [Member] | Fuel Product [Member] | Diesel Swaps [Member] | Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)	16	4.8
Commodity Contract [Member] | Fuel Product [Member] | Diesel Swaps [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	0
Commodity Contract [Member] | Fuel Product [Member] | Jet Fuel Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	0	0.3
Commodity Contract [Member] | Fuel Product [Member] | Jet Fuel Swaps [Member] | Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)	0	1.4
Commodity Contract [Member] | Fuel Product [Member] | Jet Fuel Swaps [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	0
Commodity Contract [Member] | Specialty Product [Member] | Crude Oil Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)	0	0
Commodity Contract [Member] | Specialty Product [Member] | Crude Oil Swaps [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)	(0.7)	(0.4)
Commodity Contract [Member] | Specialty Product [Member] | Crude Oil Swaps [Member] | Unrealized / Realized [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	$ 0	$ 0

Derivatives - Schedule of the E

Derivatives - Schedule of the Effective Portion of Cash Flow Hedges Classified in Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Total	$ (3.7)	$ (1.6)
2016 [Member]
Derivative [Line Items]
Accumulated Other Comprehensive Income	4.3
Derivative gains (losses) reflected in gross profit:
Derivative [Line Items]
Total	$ 4.3	$ 6.4

Derivatives - Schedule of Der48

Derivatives - Schedule of Derivative Instruments (Fair Value Hedges) (Details) - Fair Value Hedging [Member] - USD ($) $ in Millions	Jan. 13, 2015	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Interest Expense [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item		$ 2.8		$ 2.9
Interest Expense [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) of Derivative		0.1	$ 0.2
Gain (Loss) on Hedged Item	$ 3.3
Interest Income [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item		0	0
Interest Rate Contract [Member] | Interest Expense [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) of Derivative		0.1	0.2
Interest Rate Contract [Member] | Interest Income [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item		$ 0	$ 0

Derivatives - Schedule of Der49

Derivatives - Schedule of Derivative Instruments (Not Designated as Hedges) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivative instruments	$ 0	$ 1.2
Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(12.3)	8.3
Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	4.6	(27.8)
Natural Gas Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.6)	0
Natural Gas Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.2)	(0.3)
Natural Gas Swaps [Member] | Specialty Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(3.7)	(2.1)
Natural Gas Swaps [Member] | Specialty Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	2	(3.2)
Platinum Swaps [Member] | Specialty Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0
Platinum Swaps [Member] | Specialty Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(0.1)
Crude Oil Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.9)	(48.3)
Crude Oil Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	1.5	50.2
Crude Oil Basis Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	1
Crude Oil Basis Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(2.6)	(0.4)
Crude Oil Percent Basis Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(3.9)	0
Crude Oil Percent Basis Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0.2	0
Crude Oil Options [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0
Crude Oil Options [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(0.6)	0
Crude Oil Futures [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(2)	0
Crude Oil Futures [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0
Gasoline Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(2)
Gasoline Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(1.1)
Gasoline Crack Spread Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	(1.2)	(0.8)
Gasoline Crack Spread Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	4.3	(1.5)
Diesel Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	58
Diesel Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(63.4)
Diesel Crack Spread Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	0.9
Diesel Crack Spread Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	(6.4)
Jet Fuel Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Realized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	0	1.6
Jet Fuel Swaps [Member] | Fuel Product [Member] | Commodity Contract [Member] | Unrealized Gain (Loss) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss)	$ 0	$ (1.6)

Derivatives - Schedule of Der50

Derivatives - Schedule of Derivative Positions (Natural Gas Swaps - Specialty) (Details) - Commodity Contract [Member] - Specialty Product [Member] - Natural Gas Swaps [Member] - Not Designated as Hedging Instrument [Member]	Mar. 31, 2016MMBTU$ / MMBtu	Dec. 31, 2015MMBTU$ / MMBtu
Derivative [Line Items]
MMBtu	9,250,000	10,830,000
$/MMBtu	4.02	4.05
First Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | MMBTU		1,580,000
$/MMBtu		4.24
Second Quarter 2016 [Member]
Derivative [Line Items]
MMBtu	1,380,000	1,380,000
$/MMBtu	4.26	4.26
Third Quarter 2016 [Member]
Derivative [Line Items]
MMBtu	1,380,000	1,380,000
$/MMBtu	4.26	4.26
Fourth Quarter 2016 [Member]
Derivative [Line Items]
MMBtu	1,540,000	1,540,000
$/MMBtu	4.14	4.14
Calendar Year 2017 [Member]
Derivative [Line Items]
MMBtu	4,950,000	4,950,000
$/MMBtu	3.85	3.85

Derivatives - Schedule of Der51

Derivatives - Schedule of Derivative Positions (Natural Gas Collars) (Details) - Not Designated as Hedging Instrument [Member] - Commodity Contract [Member] - Specialty Product [Member] - Natural Gas Collars [Member]	Mar. 31, 2016MMBTU$ / MMBtu	Dec. 31, 2015MMBTU$ / MMBtu
Derivative [Line Items]
MMBtu | MMBTU	420,000	600,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.89	3.89
First Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | MMBTU		180,000
Average Bought Call ($/MMBtu)		4.25
Average Sold Put ($/MMBtu)		3.89
Second Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | MMBTU	180,000	180,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.89	3.89
Third Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | MMBTU	180,000	180,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.89	3.89
Fourth Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | MMBTU	60,000	60,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.89	3.89

Derivatives - Schedule of Der52

Derivatives - Schedule of Derivative Positions (Crude Oil Swaps & Basis Swaps) (Details) - Commodity Contract [Member] - Fuel Product [Member] - Not Designated as Hedging Instrument [Member]	Mar. 31, 2016bbl$ / bbl	Dec. 31, 2015bbl$ / bbl
Crude Oil Swap Purchased [Member]
Derivative [Line Items]
Derivative, notional amount	2,149,882	747,840
Average Swap ($/Bbl) | $ / bbl	45.16	53.24
Crude Oil Swap Purchased [Member] | Second Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	54,120	29,120
Barrels per day, purchased	595	320
Average Swap ($/Bbl) | $ / bbl	39.32	44.06
Crude Oil Swap Purchased [Member] | Third Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	398,893	29,440
Barrels per day, purchased	4,336	320
Average Swap ($/Bbl) | $ / bbl	39.52	44.06
Crude Oil Swap Purchased [Member] | First Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount		29,120
Barrels per day, purchased		320
Average Swap ($/Bbl) | $ / bbl		44.06
Crude Oil Swap Purchased [Member] | Fourth Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	398,893	29,440
Barrels per day, purchased	4,336	320
Average Swap ($/Bbl) | $ / bbl	39.52	44.06
Crude Oil Swap Purchased [Member] | Calendar Year 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	1,297,976	630,720
Barrels per day, purchased	3,556	1,728
Average Swap ($/Bbl) | $ / bbl	48.87	54.94
Crude Oil Swap Sold [Member]
Derivative [Line Items]
Derivative, notional amount	528,520
Average Swap ($/Bbl) | $ / bbl	41.56
Crude Oil Swap Sold [Member] | Calendar Year 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	528,520
Barrels per day, purchased	1,448
Average Swap ($/Bbl) | $ / bbl	41.56
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member]
Derivative [Line Items]
Derivative, notional amount	1,285,000	732,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	1.80	2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | Second Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	365,000	182,000
Barrels per day, purchased	5,000	2,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(1.80)	2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | Third Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	460,000	184,000
Barrels per day, purchased	5,000	2,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(1.80)	2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | First Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount		182,000
Barrels per day, purchased		2,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl		2.40
Crude Oil Basis Swaps LLS and NYMEX WTI Purchased [Member] | Fourth Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	460,000	184,000
Barrels per day, purchased	5,000	2,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(1.80)	2.40
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member]
Derivative [Line Items]
Derivative, notional amount	5,644,000	731,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(13.31)	(13.90)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Second Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	697,000	91,000
Barrels per day, purchased	7,659	1,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(14.02)	(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Third Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	1,196,000	92,000
Barrels per day, purchased	13,000	1,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(13.18)	(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | First Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount		91,000
Barrels per day, purchased		1,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl		(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Fourth Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	1,196,000	92,000
Barrels per day, purchased	13,000	1,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	13.18	(14.10)
Crude Oil Basis Swaps WCS and NYMEX WTI Purchased [Member] | Calendar Year 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	2,555,000	365,000
Barrels per day, purchased	7,000	1,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl	(13.22)	(13.70)

Derivatives - Schedule of Der53

Derivatives - Schedule of Derivative Positions (Crude Oil Percent Basis Swaps) (Details) - Fuel Product [Member] - Commodity Contract [Member] - Not Designated as Hedging Instrument [Member] - Crude Oil Basis Swaps Purchased [Member] - bbl	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative, notional amount	3,295,000	3,658,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	73.10%	73.40%
First Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount		728,000
Barrels per day, purchased		8,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)		73.50%
Second Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	728,000	728,000
Barrels per day, purchased	8,000	8,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	73.50%	73.50%
Third Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	736,000	736,000
Barrels per day, purchased	8,000	8,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	73.50%	73.50%
Fourth Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	736,000	736,000
Barrels per day, purchased	8,000	8,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	73.50%	73.50%
Calendar Year 2017 [Member]
Derivative [Line Items]
Derivative, notional amount	1,095,000	730,000
Barrels per day, purchased	3,000	2,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	72.30%	73.00%

Derivatives - Schedule of Der54

Derivatives - Schedule of Derivative Positions (Crude Oil Options) (Details) - Not Designated as Hedging Instrument [Member] - Commodity Contract [Member] - Fuel Product [Member]	Mar. 31, 2016bbl$ / bbl	Dec. 31, 2015bbl$ / bbl
Crude Oil Call Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	350,000	350,000
Average Bought Call ($/Bbl) | $ / bbl	55	55
Crude Oil Call Options Sold [Member]
Derivative [Line Items]
Derivative, notional amount	300,000
Average Sold Call ($/Bbl) | $ / bbl	41.78
Crude Oil Put Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	300,000
Average Bought Put ($/Bbl) | $ / bbl	32.58
Second Quarter 2016 [Member] | Crude Oil Call Options Sold [Member]
Derivative [Line Items]
Derivative, notional amount	300,000
Barrels per day, sold	9,677
Average Sold Call ($/Bbl) | $ / bbl	41.78
Second Quarter 2016 [Member] | Crude Oil Put Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	300,000
Barrels per day, purchased	9,677
Average Bought Put ($/Bbl) | $ / bbl	32.58
Fourth Quarter 2016 [Member] | Crude Oil Call Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	350,000	350,000
Barrels per day, purchased	11,290	11,290
Average Bought Call ($/Bbl) | $ / bbl	55	55

Derivatives Schedule of Derivat

Derivatives Schedule of Derivative Positions (Gasoline Crack Spread Swaps) (Details) - Commodity Contract [Member] - Not Designated as Hedging Instrument [Member] - Fuel Product [Member] - Gasoline Crack Spread Swaps [Member]	Dec. 31, 2015bbl$ / bbl
Derivative [Line Items]
Derivative, notional amount	873,000
Average Swap ($/Bbl) | $ / bbl	8.98
First Quarter 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	873,000
Barrels per day, sold	9,593
Average Swap ($/Bbl) | $ / bbl	8.98

Derivatives - Schedule of Der56

Derivatives - Schedule of Derivative Positions (Natural Gas Swaps - Fuel) (Details) - Commodity Contract [Member] - Fuel Product [Member] - Not Designated as Hedging Instrument [Member] - Natural Gas Swaps [Member]	Mar. 31, 2016bbl$ / MMBtu	Dec. 31, 2015bbl$ / MMBtu
Derivative [Line Items]
MMBtu | bbl	1,999,000	2,602,000
$/MMBtu | $ / MMBtu	3.01	3.01
First Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | bbl		603,000
$/MMBtu | $ / MMBtu		3.01
Second Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | bbl	603,000	603,000
$/MMBtu | $ / MMBtu	2.99	2.99
Third Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | bbl	606,000	606,000
$/MMBtu | $ / MMBtu	3.03	3.03
Fourth Quarter 2016 [Member]
Derivative [Line Items]
MMBtu | bbl	790,000	790,000
$/MMBtu | $ / MMBtu	3.02	3.02

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) - USD ($)	Jan. 13, 2015	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Counterparties in which derivatives held were net assets		0	0
Collateral		$ 0	$ 0
Accumulated other comprehensive loss		(3,700,000)	(1,600,000)
Notional amount	$ 200,000,000
Derivative gains (losses) reflected in gross profit:
Derivative [Line Items]
Accumulated other comprehensive loss		4,300,000	6,400,000
Fair Value Hedging [Member] | Interest Expense [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item		$ 2,800,000	$ 2,900,000
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest Expense [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item	$ 3,300,000

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Reduction in net derivative liability	$ 2.3		$ 1.2
Gain on sale of RINs	20.8	$ 35
Cost of Goods Sold, Overhead	$ 37.6	$ 42.2
Date goodwill impairment is reviewed, annually	Oct. 1, 2015

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Recurring Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Derivative liabilities:
Total derivative liabilities	$ (29.3)	$ (33.9)
Fair Value, Measurements, Recurring [Member]
Assets:
Pension plan investments	49	47.5
Total recurring assets at fair value	49	47.5
Derivative liabilities:
Total derivative liabilities	(29.3)	(33.9)
RINs Obligation	(115.2)	(88.4)
Total recurring liabilities at fair value	(144.5)	(122.3)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Assets:
Pension plan investments	0.2	0.4
Total recurring assets at fair value	0.2	0.4
Derivative liabilities:
Total derivative liabilities	0	0
RINs Obligation	0	0
Total recurring liabilities at fair value	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Assets:
Pension plan investments	48.8	47.1
Total recurring assets at fair value	48.8	47.1
Derivative liabilities:
Total derivative liabilities	0	0
RINs Obligation	(115.2)	(88.4)
Total recurring liabilities at fair value	(115.2)	(88.4)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Assets:
Pension plan investments	0	0
Total recurring assets at fair value	0	0
Derivative liabilities:
Total derivative liabilities	(29.3)	(33.9)
RINs Obligation	0	0
Total recurring liabilities at fair value	(29.3)	(33.9)
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(3.7)	(5.2)
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(3.7)	(5.2)
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(3.1)	(0.3)
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(3.1)	(0.3)
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(6.4)	(6.7)
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(6.4)	(6.7)
Crude Oil Options [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(0.9)	(0.3)
Crude Oil Options [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Options [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Options [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(0.9)	(0.3)
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	0	(4.3)
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	0	(4.3)
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(14.5)	(16.2)
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	(14.5)	(16.2)
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(0.7)	(0.9)
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative liabilities:
Total derivative liabilities	$ (0.7)	$ (0.9)

Fair Value Measurements - Sum60

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
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring [Line Items]
Realized gain (loss) on derivative instruments	$ (12.3)	$ 8.9
Unrealized gain (loss) on derivative instruments	4.6	(27.9)
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Interest expense, net	(30.3)	(27)
Change in fair value of cash flow hedges	0	(5.1)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring [Line Items]
Realized gain (loss) on derivative instruments	12.3	(8.9)
Unrealized gain (loss) on derivative instruments	4.6	(27.9)
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Fair value at January 1,	(33.9)	17.6
Interest expense, net	(0.1)	(0.2)
Change in fair value of cash flow hedges	0	(5.1)
Settlements	(12.2)	2.2
Transfers in (out) of Level 3	0	0
Fair value at March 31,	(29.3)	(22.3)
Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of March 31,	$ 4.6	$ (27.9)

Fair Value Measurements - Sum61

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	Mar. 31, 2016	Dec. 31, 2015
Fair Value [Member] | Level 1 [Member]
Financial Instrument:
Senior notes	$ 1,110.9	$ 1,095.8
Fair Value [Member] | Level 2 [Member]
Financial Instrument:
Senior notes	0	294.1
Fair Value [Member] | Level 3 [Member]
Financial Instrument:
Senior notes	72.4
Fair Value [Member] | Revolving Credit Facility [Member] | Level 3 [Member]
Financial Instrument:
Revolving credit facility	289.4	105.1
Fair Value [Member] | Capital Lease Obligations [Member] | Level 3 [Member]
Financial Instrument:
Capital lease and other obligations	46.1	46.4
Carrying Value [Member] | Level 1 [Member]
Financial Instrument:
Senior notes	1,549.3	1,230.8
Carrying Value [Member] | Level 2 [Member]
Financial Instrument:
Senior notes	0	317.6
Carrying Value [Member] | Level 3 [Member]
Financial Instrument:
Senior notes		73.5
Carrying Value [Member] | Revolving Credit Facility [Member] | Level 3 [Member]
Financial Instrument:
Revolving credit facility	289.4	105.1
Carrying Value [Member] | Capital Lease Obligations [Member] | Level 3 [Member]
Financial Instrument:
Capital lease and other obligations	$ 46.1	$ 46.4

Partners' Capital - Narrative (

Partners' Capital - Narrative (Details) - USD ($)	1 Months Ended	3 Months Ended
	Feb. 19, 2015	Mar. 31, 2016	Mar. 31, 2015
Partners' Capital [Abstract]
Common units sold (in shares)			307,985
Proceeds from sale of common units, net	$ 7,700,000	$ 0	$ 161,700,000
Underwriting discounts			100,000
General partner contribution amount			200,000
Equity Placement Agreement aggregate offering price up to		300,000,000
Distributions to partners		57,400,000	52,700,000
General partner’s incentive distribution rights		$ 0	$ 4,200,000

Employee Benefit Plans - Summar

Employee Benefit Plans - Summary of Components of Net Periodic Pension Cost (Details) - Pension Benefits [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Components of net periodic pension and other post retirement benefits cost
Service cost	$ 0	$ 0.1
Interest cost	0.6	0.7
Expected return on assets	(0.8)	(0.8)
Amortization of net loss	0	0.2
Net periodic benefit cost (income)	$ (0.2)	$ 0.2

Employee Benefit Plans - Schedu

Employee Benefit Plans - Schedule of Pension Plan Assets Measured at Fair Value (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	$ 49	$ 47.5
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0.2	0.4
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	48.8	47.1
Cash and Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0.2	0.4
Cash and Cash Equivalents [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Domestic Equities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Domestic Equities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	9.7	9.6
Foreign Equities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Foreign Equities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	9.2	9.2
Fixed Income [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Fixed Income [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	$ 29.9	$ 28.3

Employee Benefit Plans - Narrat

Employee Benefit Plans - Narrative (Details)	3 Months Ended
	Mar. 31, 2016
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 Comprehensi66

Accumulated Other Comprehensive Income - Summary of Reclassification Adjustments out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total	$ (2.1)	$ (3.5)
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	16	20.2
Cost of sales	(13.9)	(21.9)
Total	2.1	(1.7)
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	0	(0.2)
Total	0	(0.2)
Pension Plan [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net loss	$ 0	$ 0.2

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
		Mar. 31, 2016	Mar. 31, 2015
Numerator for basic and diluted earnings per limited partner unit:
Net income (loss)		$ (67.7)	$ 23.8
General partner’s interest in net income (loss)		(1.4)	0.5
General partner’s incentive distribution rights		0	4.2
Net income (loss) available to limited partners		$ (66.3)	$ 19.1
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average limited partner units outstanding (in shares)		76,449,841	71,232,392
Participating securities - phantom units		0	43,060
Diluted weighted average limited partner units outstanding (in shares)	[1]	76,449,841	71,275,452
Limited partners' interest basic net income (loss) per unit		$ (0.87)	$ 0.27
Limited partners' interest diluted net loss per unit		$ (0.87)	$ 0.27
Dilutive phantom units excluded (in shares)		100,000
[1]	Total diluted weighted average limited partner units outstanding excludes less than 0.1 million of dilutive phantom units for the three months ended March 31, 2016.

Segments and Related Informat68

Segments and Related Information - Schedule of Reportable Segment Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Sales:
Total sales	$ 713	$ 1,018.6
Loss from unconsolidated affiliates	(11.1)	(4.5)
Adjusted EBITDA	6.6	124.9
Reconciling items to net loss:
Depreciation and amortization	47.9	41.5
Realized gain (loss) on derivatives, not reflected in net income (loss)	(2.1)	6.1
Unrealized (gain) loss on derivatives	(4.6)	27.9
Interest expense	30.3	27
Non-cash equity based compensation	2.6	3.4
Income tax expense (benefit)	0.2	(4.8)
Net income (loss)	(67.7)	23.8
External Customers [Member]
Sales:
Total sales	713	1,018.6
Intersegment Sales [Member]
Sales:
Total sales	0	0
Operating Segments [Member] | Specialty Products [Member]
Sales:
Total sales	301.1	362.9
Loss from unconsolidated affiliates	0	0
Adjusted EBITDA	58.5	65.9
Reconciling items to net loss:
Depreciation and amortization	18.4	15.9
Realized gain (loss) on derivatives, not reflected in net income (loss)	0.7	0.4
Operating Segments [Member] | Specialty Products [Member] | External Customers [Member]
Sales:
Total sales	300.7	361.6
Operating Segments [Member] | Specialty Products [Member] | Intersegment Sales [Member]
Sales:
Total sales	0.4	1.3
Operating Segments [Member] | Fuel Products [Member]
Sales:
Total sales	383.6	581.2
Loss from unconsolidated affiliates	(11)	(4.4)
Adjusted EBITDA	(46)	63.1
Reconciling items to net loss:
Depreciation and amortization	24.7	20
Realized gain (loss) on derivatives, not reflected in net income (loss)	(2.8)	5.7
Operating Segments [Member] | Fuel Products [Member] | External Customers [Member]
Sales:
Total sales	379.9	568.3
Operating Segments [Member] | Fuel Products [Member] | Intersegment Sales [Member]
Sales:
Total sales	3.7	12.9
Operating Segments [Member] | Oilfield Services [Member]
Sales:
Total sales	32.4	88.7
Loss from unconsolidated affiliates	(0.1)	(0.1)
Adjusted EBITDA	(5.9)	(4.1)
Reconciling items to net loss:
Depreciation and amortization	4.8	5.6
Realized gain (loss) on derivatives, not reflected in net income (loss)	0	0
Operating Segments [Member] | Oilfield Services [Member] | External Customers [Member]
Sales:
Total sales	32.4	88.7
Operating Segments [Member] | Oilfield Services [Member] | Intersegment Sales [Member]
Sales:
Total sales	0	0
Operating Segments [Member] | Combined Segments [Member]
Sales:
Total sales	717.1	1,032.8
Loss from unconsolidated affiliates	(11.1)	(4.5)
Adjusted EBITDA	6.6	124.9
Reconciling items to net loss:
Depreciation and amortization	47.9	41.5
Realized gain (loss) on derivatives, not reflected in net income (loss)	(2.1)	6.1
Operating Segments [Member] | Combined Segments [Member] | External Customers [Member]
Sales:
Total sales	713	1,018.6
Operating Segments [Member] | Combined Segments [Member] | Intersegment Sales [Member]
Sales:
Total sales	4.1	14.2
Eliminations [Member]
Sales:
Total sales	(4.1)	(14.2)
Loss from unconsolidated affiliates	0	0
Adjusted EBITDA	0	0
Reconciling items to net loss:
Depreciation and amortization	0	0
Realized gain (loss) on derivatives, not reflected in net income (loss)	0	0
Eliminations [Member] | External Customers [Member]
Sales:
Total sales	0	0
Eliminations [Member] | Intersegment Sales [Member]
Sales:
Total sales	$ (4.1)	$ (14.2)

Segments and Related Informat69

Segments and Related Information - Schedule of Major Product Category Sales (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Major product category sales
Sales	$ 713	$ 1,018.6
Sales, percentage	52.80%	48.10%
Product Concentration Risk [Member]
Major product category sales
Sales	$ 713	$ 1,018.6
Sales, percentage	100.00%	100.00%
Product Concentration Risk [Member] | Specialty Products [Member]
Major product category sales
Sales	$ 300.7	$ 361.6
Sales, percentage	42.20%	35.50%
Product Concentration Risk [Member] | Specialty Products [Member] | Lubricating Oils [Member]
Major product category sales
Sales	$ 129.2	$ 149.8
Sales, percentage	18.10%	14.70%
Product Concentration Risk [Member] | Specialty Products [Member] | Solvents [Member]
Major product category sales
Sales	$ 55.9	$ 86.2
Sales, percentage	7.80%	8.50%
Product Concentration Risk [Member] | Specialty Products [Member] | Waxes [Member]
Major product category sales
Sales	$ 27.2	$ 39
Sales, percentage	3.80%	3.80%
Product Concentration Risk [Member] | Specialty Products [Member] | Packaged and Synthetic Specialty Products [Member]
Major product category sales
Sales	$ 80.9	$ 80.5
Sales, percentage	11.30%	7.90%
Product Concentration Risk [Member] | Specialty Products [Member] | Other [Member]
Major product category sales
Sales	$ 7.5	$ 6.1
Sales, percentage	1.20%	0.60%
Product Concentration Risk [Member] | Fuel Products [Member]
Major product category sales
Sales	$ 379.9	$ 568.3
Sales, percentage	53.30%	55.80%
Product Concentration Risk [Member] | Fuel Products [Member] | Gasoline [Member]
Major product category sales
Sales	$ 162.2	$ 246.3
Sales, percentage	22.70%	24.10%
Product Concentration Risk [Member] | Fuel Products [Member] | Diesel [Member]
Major product category sales
Sales	$ 138.9	$ 213.9
Sales, percentage	19.50%	21.00%
Product Concentration Risk [Member] | Fuel Products [Member] | Jet fuel [Member]
Major product category sales
Sales	$ 23.4	$ 38.2
Sales, percentage	3.30%	3.80%
Product Concentration Risk [Member] | Fuel Products [Member] | Asphalt, Heavy Fuel Oils and Other [Member]
Major product category sales
Sales	$ 55.4	$ 69.9
Sales, percentage	7.80%	6.90%
Product Concentration Risk [Member] | Oilfield Services [Member]
Major product category sales
Sales	$ 32.4	$ 88.7
Sales, percentage	4.50%	8.70%

Segments and Related Informat70

Segments and Related Information - Narrative (Details)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Segment Reporting [Abstract]
Number of customers representing 10% or greater of consolidated sales	0	0
Number of crude oil suppliers	2	2
Percentage of crude oil supply from 2 suppliers	52.80%	48.10%

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details) - Subsequent Event [Member] - USD ($)	Apr. 20, 2016	May. 06, 2016
Subsequent Event [Line Items]
Gain (Loss) on Derivative		$ 4,000,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		(22,000,000)
Fair value of senior notes, increase (decrease)		$ (42,000,000)
Notes Due January Two Thousand Twenty One at Fixed Rated Eleven Point Five Percentage Interest Payments [Member]
Subsequent Event [Line Items]
Debt Instrument, Issuance Date	Apr. 20, 2016
Long-term Debt, Gross	$ 400,000,000
Fixed rate	11.50%
Maturity date	Jan. 15, 2021
Debt Instrument Percentage Of Discount Price	98.273%
Proceeds from Debt, Net of Issuance Costs	$ 383,300,000
Frequency of interest payment	semiannually
Maximum [Member]
Subsequent Event [Line Items]
Debt Instrument, Collateral Amount	$ 150,000,000